Good day, everyone and welcome to the PBF Energy Second 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 opened 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, Leo. 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 would like to direct your attention to the Safe Harbor statement contained in today’s press release. In summary, it outlines that 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 which 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. Special items included in the second quarter 2020 results, which increased net income by a net after-tax benefit of $777 million, or $6.42 per share consisted of a lower-of-cost-or-market, LCM inventory adjustment, change in the fair value of the earn-out provision included primarily in connection with the Martinez acquisition, and a gain on sale of hydrogen plants slightly offset by severance costs related to a reduction in workforce. 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. I will now turn the call over to Tom.

Thanks, Collin. Good morning, everyone and thank you for joining our call today. These are trying times in many respects and we are all finding ways to cope with our current circumstances as individuals, families and businesses. Like many others, PBF’s focus has been on safety, operational and personal. We have established a pandemic response team that is establishing and overseeing safety procedures and workplace protocols for our sites. We continue to ask employees and contractors to perform daily health screenings at all of our locations and are restricting access to our facilities for those that have been exposed to COVID in order to prevent community spread, while enforcing the CDC recommended 14-day quarantine period for all exposed employees, including those that have traveled to regions where there has been a resurgence. For those of us in the offices on the daily basis, we require a mask where social distancing is not possible. We have guidelines for the overall number of people we are allowing in our office environments until we are able to safely bring all of our employees back to the office. I am proud of all of our employees and especially those that have been dedicated to keeping all of our facilities operating safely under trying circumstances and conditions. In addition to maintaining safe operations, our focus in Q2 was the balance sheet and increasing liquidity. The steps we took operationally and financially were taken with the goal in mind of preserving cash within our system. The entire energy landscape was rocked by the unprecedented demand losses due to the pandemic. Refinery utilization dropped to levels usually only seen during major hurricanes on the U.S. Gulf Coast and yields were shifted in accordance with gasoline demand dropping much more than distillate. Crude oil production continued unabated culminating…

Thanks, Tom. As Tom mentioned, we have taken aggressive steps to manage our refining system in response to market conditions. Overall, we ran a refining system at approximately 70% of capacity with East Coast and Mid-Con seeing the lowest utilization. Our utilization going forward will simply be determined by demand and inventory levels. In this unprecedented time, we have complete focus on those items that are within our control. As such, we have assembled a dedicated project team to not only take the necessary steps to reduce expenses and capital in the immediate term, but also focus on initiatives to sustainably improve free cash flow on a go forward basis. So in addition to immediate reductions to operating expenses and capital, the team is also focused on initiatives to generate incremental cash flow through unit level improvements, inventory and risk management as well as regional level optimizations on the East and West Coasts. In regards to operating expenses, reduced throughput has the obvious result of increasing expenses on a per barrel basis as the denominator is reduced. As a rule of thumb, variable costs generally only represent 30% or 40% of total operating expenses. Importantly, in the second quarter, we were able to reduce our fixed expenses by approximately $65 million or 20%. The company has been effective at streamlining and gaining more efficiency of our own workforce, which has allowed us to reduce headcount, reduce over time and the total number of contractors in our facilities. By taking these steps, we believe we have effectively reduced our total operating expenses by approximately $30 million to $35 million per quarter across our system on a go forward basis and we certainly expect this to extend into ‘21 and beyond. On a normalized throughput basis, we expect these savings to equate to approximately $0.40 to $0.50 per barrel. On our first quarter call, we announced an expected operating expense savings goal of $140 million in 2020, which included $110 million of non-energy related savings. We now expect our non-energy related savings to reach $145 million for the year. On the West Coast, we initiate our integration optimization efforts beginning in February. All the areas for synergy we expected prior to acquisition, commercial, operational, logistical remain valid. We have taken advantage of our increased scale to improve our crude slate at Martinez. We have shifted Martinez refinement to Torrance for blending. Our marketing team has increased RAC sales of gasoline and distillate, which decreases logistics costs and increases refinery level margin. While many of these benefits are being masked in the current environment, we have been able to continue with our plans to integrate and optimize our West Coast operations in anticipation of market conditions improving. With that, I will turn it over to Erik to discuss liquidity and our financial position.

Thank you, Matt. Today, PBF reported an adjusted loss of $3.19 per share for the second quarter and adjusted EBITDA of negative $298.4 million. Consolidated CapEx for the quarter was approximately $148 million. The consolidated CapEx includes $146 million for refining and corporate CapEx and $1.8 million for PBF Logistics. As a result of their reductions to our 2020 capital budget, we expect to incur roughly $15 million of CapEx per month from July onwards and our full year refining CapEx should be approximately $360 million. We have incurred 75% of our refining capital expenditures during the first half of the year. We took aggressive steps in the second quarter to reduce our cost structure and shore up our balance sheet. We completed the sale of 5 hydrogen plants to Air Products for $530 million and issued $1 billion of senior secured notes. Our current liquidity is approximately $1.9 billion based on a cash balance of $1.2 billion in more than $700 million of available borrowing capacity under our asset-backed revolving credit facility. Since May, we repaid approximately $300 million on our revolving credit facility and have seen our borrowing base increase as commodity prices rebounded since the April lows. We have experienced significant working capital swing since the beginning of the year, primarily as a result of unprecedented volatility in the crude market. During the second quarter, we saw a benefit from normalized working capital versus the headwind we experienced in the first quarter of the year. This benefit was outweighed as we sourced more economic waterborne barrels that typically carry shorter payment terms. This in conjunction with a slight build in inventory resulted in an overall use of working capital of approximately $35 million for the quarter. Operator, we have completed our opening remarks and we would be pleased to take any questions.

[Operator Instructions] Your first question comes from Manav Gupta of Credit Suisse.

Hey, guys. Can you hear me?

Yes, Manav.

Okay. So, Tom, we keep hearing these news items where you know Google is saying we will probably bring back employees second half of next year. Facebook is saying we are not bringing back employees, there is no timeline, I am trying to understand what the demand for California? I mean, what’s the gasoline outlook for California, where all these big techs don’t actually want to bring back the employees? And is this a problem which can be solved with lower operating rates for the time being or do you actually think there is a need for capacity rationalization in California to bring back margins on a normalized level?

It’s a great question, multi-folded. But let me just say that we certainly saw Google’s announcement, but Californians love to drive and they are going to continue to drive when this pandemic passes. If we actually look and I am sure you do look at PADD 5 and California we are absolutely terrible. We had negative cracks in April, which severely impacted our earnings on the West Coast. But as of Wednesday’s EIA report, the inventory in PADD 5 was sub 20, sub 30 million barrels – 29.7 million barrels. Frankly, the refiners have done a very, very good job across the country in many ways, but also mainly in PADD 5, where utilization has been around 70% and it has helped clean up the inventories and their cracks have responded. Physical cracks, I don’t know what they closed at yesterday, but the day before we are about $13 both in San Francisco and in Los Angeles. So, my personal opinion is we passed the lows. Obviously, it’s all going to be a function of whether or not there is a second wave or a third way, but assuming nothing extraordinary happens, I believe that we have past the lows and demand will continue to creep up, not only in PADD 5, but across the country. Typically, people say California is long or PADD 5 is long, 1.5 refineries. That is very seasonal in a normal market. It’s not long at all in gasoline seasons, actually 9 months a year perhaps. So I think we are going to be fine in California over the long haul.

Thanks, Tom. And a quick follow-up on the Mid-Con region, I understand there was a downtime at the refinery. But as a trend, what we are seeing Tom here is during the when we look at screen, Gulf Coast and Mid-Con were pretty much neck and neck, but as the results are coming out, what we are seeing is that the capture on the Mid-Con side is weaker than expected. I have never seen TSX report a negative EBIT from their Mid-Con, but today they did and then even in your case, the gross margin at Chalmette was much bigger than the one at Toledo. So I am just trying to understand what’s driving this variance where Gulf Coast is coming in a little stronger than expected and Mid-Con gross margin capture across the board is coming in a little weaker than expected?

Okay. I think I can help on that. Let’s take the Mid-Con first. We obviously had the cat cracker and miscellaneous other units down in the first quarter. And given the marketplace environment, we consciously chose not to start that unit up for a period of time, because we really didn’t know what the demand was going to be. So, there was a significant amount of downtime in Toledo. We did not jump in because of our concerns about cash and liquidity and buy a bunch of cheap crude, which that was the hindsight comment that I kind of referenced that. If we had a crystal ball, we probably would have done that and that would have improved our margins in the Mid-Continent. Now, when you shift to Chalmette frankly, it’s the crude diff. Chalmette did have a reasonably crude differential effect. It’s really the only refinery that had a good crude differential and that helped us on the margin side. As we look today, the margins in the Midwest have improved. They are not where they need to be. We still have work to do there. But our Toledo system is much more competitive than it was when we had the units down.

Thank you so much for taking my questions.

Your next question is from Roger Reid of Wells Fargo.

Hey, thank you. Good morning, guys.

Good morning, Roger.

And since my dogs are run around, if you hear any barking in a minute, that’s probably why. Quick question for you on the OpEx side, so we have got the guidance to say of $250 million in 2020, lot of moving parts it sounds like here. And I was wondering if you could kind of work the reconciliation for us of what makes up the $250 million from what you talked about earlier? And then where do we think about, I assume some costs coming back to you from the sale of the hydrogen plants meaning that you are now having to pay something for the hydrogen? Is that in OpEx or is that built into the crack spread and how we should think about that as an ongoing cost as part of this transaction?

Okay, Roger. I am not sure that precisely what you are referring to in regards to $250 million. We guided last quarter to $140 million of operating expense savings in 2020. And we will exceed that what I said in the comments was that $140 million was consisted of about $110 million of non-energy related savings that we have increased that from $110 million to $145 million. We have had significant CapEx reductions in this year which would get us well and above $250 million that – those are the numbers for 2020. In regard to expenses going forward, what I said in the comments was our expenses we expect will be down $35 million on a per quarter basis going forward, so call it $140 million, $145 million on an annual basis. In regards to the incremental costs from the hydrogen plants, the two go hand-in-hand. We entered this pandemic. We took immediate steps on increasing our liquidity and that came with a cost and we need to make sure coming out of this pandemic that we are as competitive as we can be and that we are actually in a better position. So, we are working very hard to not only offset those incremental costs our business has because of accessing that capital, but actually to improve beyond it. So the steps we are taking, I think will position the company to not only absorb the increased cost from selling the hydrogen plants or the bond offering that we did, but certainly position us to generate more free cash flow even with those costs embedded in our company.

Okay. Well, I guess the reason I was asking about the $250 million, it’s in the press release. It said you made progress expense reductions goal remains to achieve the savings, operating expense reduction of $250 million. So that’s what I was trying to reconcile that $250 million back to the numbers you were talking about maybe it’s a different timeframe for the $250 million, but that’s – I don’t know if you can help us there. That’s what I am trying to get to is the $145 million, up from the $110 million versus the $250 million and it doesn’t sound like that includes CapEx. So, just trying to make sure I understood point A to point B here?

Roger, hey, this is Colin. Sorry, the $250 million is a kind of total expense savings, which also includes the salary reductions that we put in Q1 that we talked about on our first quarter call, as well as the reduction in dividends. So that’s kind of a combined cash savings, including the OpEx numbers that Matt was talking about have now more than $250 million with our increased expectations for operating expenses.

Okay, so the $110 million was embedded in the $250 million. If that’s now $145 million, we add that to the $250 million as a way to think about the savings here.

Correct.

Okay, awesome. And then just to get back to something maybe more operational, what have you seen in the in the last I guess, let’s call it, exit rate of Q2 to what is now the last day of July in terms of if you look across your various regions things would look better, as we think about gasoline, diesel and jet fuel, if you could give us any sort of regional breakdown that would be great as well?

Well, certainly, I alluded to it on the first question from where we were, the frankly PADDs 1, 2, 4 for that matter and 5 have all improved in terms of the inventory levels. They are getting pretty close on, even distillate but everything but yet to where we are starting to get within the band of the 5-year average the only one that remains above that band is PADD 3. We have seen improvements in all of the other PADDs. Demand has increased the four week moving average after last Wednesday’s report was about 8.7 million barrels a day on gasoline 3.6 on distillate that’s up a fair amount. Obviously it’s up a huge amount from the lows that we are seeing at the trough. Jet demand remains obviously very much impaired but it is actually incrementally moving up as well. What we have seen, we have started up a number of units that we had shut down and idled completely during the trough. The Paulsboro cat cracker has been started back up The Toledo cat cracker has been started back up. We continue to watch it very closely. But we do have we do have the ability to and have slightly increased utilization itself in the countries now, and the industry is almost 80% we are below that we are going to be very disciplined and make sure this light at the end of the tunnel is not a train and we continue to see the creep but we think creep upward in demand and that will help us correct so regionally. PADD 3 is the one that I look at and I worry the most about because frankly that is as we all know, with the abundance of cash capacity that exists and in a gold coast, we need a good export market to clear the barrel. We don’t have that on gasoline right now. We are still a net importer on gasoline into the country. We have pretty good exports and the forecast going forward, at least as I read some of the prognosticators is that and exports into Latin America both on gasoline and distillate in the third quarter will increase. And that should help further improve the situation in PADD 3, you will all see the distillate inventories are very high and they are very high in PADD, right.

Great, I appreciate it. Thank you.

Your next question is from Prashant Rao of Citigroup.

Hi, good morning. Thanks for taking the question. Maybe I can I can segue from those comments on the Gulf Coast there to broader question on utilization levels and also Sort of acid closures for sort of the intermediate term. Tom where do we need to see crude runs kind of go back to, in the system to start to see capture become more normalized or margins come or normalized? I think we all sort of think if we get into the 80s, that should start to we should start to see if demand can support that makes sense to start to think that like margins move within sort of a normal range, historically, even though that will be below and how much the sort of second part of that is dependent upon asset closures or idling. And if you get any commentary on what you have been seeing in both globally and in the U.S. that would be helpful to particularly in the Gulf Coast, we have seen – there has been some surprises there. Some of the some major assets that are either being marketed or, how crude units down. So any color there, giving your experience going through cycles would be helpful?

Yes, absolutely. In terms of margin, yes, I would agree that. While I back up a little bit, when you say, well, utilization would be necessary or would be give – bent to a capture rate that allows you to say break even or making money. Well, obviously, it is going to be a function of the utilization rate, the crack spread and a crude differential, but assuming that those things kind of equilibrate, then I think yes, you can get to certainly where you are not draining cash, if you are – you got a utilization by and large over 80%, where the industry is getting close, we are not quite there yet, but we are seeing that. So I think that’s a good way to look at it. But again, it’s – you can’t have high utilization and still have a $3 cracks on place. That’s insane. And the industry has to be very disciplined here. One in terms of – I am personally convinced that there will be rationalization, permanent rationalization in this business and to what level? I don’t know. But speaking to where we are today, if you take a look at the United States, there has been about almost 850,000 barrels a day of capacity that has been shuttered completely. Some of that maybe temporary, some of that maybe permanent, I included in that PES. So, we know that one is permanent and that’s 335,000 or 340,000 barrels a day. As you know, I can’t say this, so I apologize in advance Calcasieu has announced that they are going to shutdown on August 1 temporarily. You will watch them on – HollyFrontier has indicated that they are going to change – turn their Cheyenne plant from a fuels plant operation into bio-fuels. And we have – Marathon has a couple of refineries down and what – we don’t know what the long-term longevity is, but there is going to be continued rationalization. Similarly, there is probably 600,000 or 700,000 barrels a day of capacity that’s been shuttered temporarily at least in Europe. And I think there is more to come on that over the next year or two. As you just back up for a moment, the margins in Singapore have been negative for the last 2 to 3 months. The margins over the pandemic period when it really got bad in Europe are effectively zero and the margins in the United States on a Gulf Coast TI basis have been $6 or $7 better than Singapore $4 to $5 better than Europe. So, I think there is a competitive advantage that shows unfortunately, it just means that where we are losing less money than other parts of the globe, but we are refining cat in the United States is still advantaged.

Alright. And then just a quick follow-up on the West Coast on Martinez, now that you have had the asset in-house for several months. Any update on where you think through cycle or “normalized cash flow generation” could be from the asset once you have got it integrated into the system. And I think sort of related to that there were some integration costs in the quarter and the utilization dipped down. Some of that, I am assuming might be opportunistic, because you were integrating the asset that those crude runs might not all be and when the difficult environment has sort of might have made sense. So I was kind of just trying to get a sense of both one, what, looking under the hood a bit more closely now. What kind of cash flow through cycle cash flow generation, the city from that asset and then two, how can we think about maybe utilization or cash generation or the cadence of improvement, versus the rest of the West Coast as we look at in the back half of this year, more short-terms?

Now, on the plan for 6 months as of tomorrow and everything we know about the plan has reconfirmed what we thought about the plan in terms of its strength, its flexibility, its coordination and combination with the Torrance refinery. So, what we said when we bought the place we thought mid-cycle EBITDA was $275 million. Certainly, our view has not declined from there and the incremental cash generation that we can generate as a result of running a system on the West Coast, we still believe will be in excess of $125 million, we would expect next year to be able to generate at least $75 million of that $125 million on a run-rate basis for ‘21. So, everything we have known about the people about the steel, the capabilities of the refinery is as strong as we thought. And we have been impressed tremendously by the asset and by the people there we just have not been able to demonstrate it.

Okay, thank you very much for the time this morning. Gentlemen, I will turn it over.

[Operator Instructions] We will move next to Doug Leggate of Bank of America.

Hi, good morning everyone. I will make the same apologies for dogs barking, if that happens in the background. I hope everybody is doing well guys. Just can we talk about the balance sheet little bit and just what did you see as your rip to de leveraging in light of everything has been talked about so far? And I guess the logical question would be where you want the balance sheet to be and coming out of this? How do you think about resetting the balance sheet, assuming we do get a recovery on a go forward level?

Doug, I think quite frankly, the path right now is seeing incremental demand coming across the board, increasing the path to free cash flow. And then we have always viewed most recent billion dollar bond deal on the secured side as an insurance policy. And so the plan would be it’s a 5-year piece of paper with a no call provision for 2 years. I think assuming a regular way demand recovery, glide path gets us to the point where ultimately that’s off the balance sheet in less than 2 years. That is ultimately our goal I think we have been delivering at the PBF logistics level, which is clearly consolidated at the PBF Energy Inc. level as well, but it ultimately comes down to incremental throughput, increased utilization and a goal of generating incremental cash flow.

Okay. Well, you are right on the trajectory. But let me let me just try one other one if I may guys it is a question I asked you the other day. When Saudi launched their price war they obviously directed an enormous amount of volume towards the U.S. one assumes that at least part of that was relatively heavy barrels with a knock-on effect on spread. So, I am just wondering if you can walk us through how you see the dynamics on head heavy or differentials and perhaps confirm whether you believe outflow is now done in terms of the impact on imports to the U.S.?

Yes, Doug, it’s Tom. I mean, from a high level of we are sitting here today with, roughly about 10 million barrels a year on year from crude oil production which is not on the market. We are sitting there with roughly two to three of that is coming out of the U.S. And the remainder of that would be from OPEC and OPEC+, so leaving in that range 7 million to 8 million barrels, which is primarily medium and heavy and as the market recovers that is going to be the incremental barrel that comes back to the market.

Appreciate your time guys. Thanks so much.

Your next question is from Benny Wong of Morgan Stanley.

Thanks. Good morning, everyone. Thanks for taking my question. Just wanted to get an update on your perspective and what you are seeing in the export market and demand there seems like from the public data the levels have been trending up, just wanted to get your sense in terms of where that demand strength is coming from how resilient it could be. If there is any kind of seasonal inventory, building factors kind of embedded in there?

From what we see, I think the demand is export demand is held up nicely on distillate has been a little less on gasoline. But as I mentioned earlier, the forecast is that we will see an improvement in both gasoline exports and distillates exports over the third quarter. The demand is indicated to be up third quarter versus second quarter in Latin America by 255,000 barrels a day it does appear as though the countries in Latin America are not locking down at the extent that they were before whether that’s appropriate or not, is above my pay grade but we do expect to see improvement over the third quarter. And it’s important because as I said earlier, particularly for the Gulf Coast, that’s the clearing mechanism. So I will just leave it at that for the Gulf Coast. There is not much activity in other parts of the country, certainly on an export basis. So, I think we will see strengthening on both distillate and importantly gasoline and get back to having the country be a net exporter of gasoline as we were for most of last year.

Right. Thanks for those thoughts. We really appreciate it. My second question is really this month we have obviously seen a barrage of headlines around risk of Line 5 and DAPL. Just wanted to kind of get your perspective in terms of the potential impact and extended shutdown of either of those lines would bring to your operations and maybe speak to the flexibility and mitigating options you guys have around them?

Well, first of all, we say that we hope for everything we have heard from Enbridge and Energy Transfers, the pipelines they believe are operating and will be continuing to be operating safely. So, we see no reason for shutting down infrastructure that is vital to the country that is in good operating condition. I understand, Enbridge earlier this week indicated that they were making further progress in trying to get the other half of Line 5 up and operating. Now, if indeed though, there were some significant moves to shut those pipelines down, there would be an impact obviously for Line 5 Toledo refinery is in that path. Quebec is in that path. A lot of refineries are in that path. I don’t believe that pipeline is going to get shutdown, but there – Enbridge is also looking at ways to show us barrels. They indicated as much in our earnings call. We haven’t heard much of that, but we will have to watch that closely. As regards to DAPL, if indeed, that line were to be shutdown and again I don’t think it’s going to be shutdown, but it’s obviously going before an Appeals Court and that was believed decision to be made by the judges. But that meant we would likely see obviously the Bakken differentials weaken significantly and would probably create a Bakken by rail opportunity to the East Coast and other parts of the country.

Thanks, Tom. Appreciate it.

Your next question is from Phil Gresh of JPMorgan.

Hey, good morning. I wanted to follow-up on the commentary around the sour barrels coming back to the market and just to get your view on actually the shale side of things. We have seen return of curtailments, but not an increase in overall U.S. crude production. So how do you see that side of things playing out and what do you think it means for U.S. slide sweet crude differentials moving forward? Is this what we are seeing now? Is this a new normal in your view or could things widen back out?

Phil, it’s Tom, in terms of this question, I think a couple of important things to look at. As we are talking about the markets aren’t coming back in terms of it’s – on the demand side of the equation and more sour coming back on to the market, we are – I think we can sit here today and say that we are past the narrow point of what we have seen on the light heavy differentials right when they got into the almost flat and we are starting to see some trajectory of it moving out. The OPEC changes for August will probably be more felt come September, which will then correspond in terms of demand. And as it relates to the specifically to shale oil in the U.S., there is clearly a lot of discussion in terms of decline rates versus DUCs versus the overall rig count. And ultimately, it probably translates into I think probably the surprise ultimately could be in the marketplace, which I don’t think I can say with strong conviction today is that you could have a wider light heavy differential, which is also being driven by light strength as opposed to being driven by heavy weakness.

Right. Okay, interesting. And then Tom, you have given a lot of commentary on product markets, I guess one follow-up would just be as we slip into September and we start moving into winter grade gasoline, how do you think that, that feeds into this whole dynamic of current crash spreads in the summer being fairly soft and trying to get the utilization back up, but also needing to reduce inventories? It sounds like you are a little bit more optimistic on gasoline, but then we do have that seasonal dynamic coming?

Yes, it’s good question. We have debated it internally. My guess is there will be economic considerations as to whether or not you fully put all of the light ends the butanes into the gasoline pool, you have to put a certain amount in just to make turn the engines over and the depth of went in the middle of the winter. But in fact, we are looking at real hot if you if all of a sudden everybody starts improving or increasing gasoline yield and the gasoline crack goes down. My guess is you are going to have economics that are going to say, either don’t put all of the light ends into the pool or you are going to have to make some assessments elsewhere. I also have a suspicion and this is just my own opinion, that like everything else that is going on in the world. We are not going to see the new normal be okay. It’s labor days past. Everybody’s going to go back to hunkering down. Because people didn’t go on vacations people didn’t travel, and you are not going to get on a plane for some period of time so I actually think that there may be some more strength in the post summer season in gasoline not to the same level it is in the summer. Don’t get me wrong. But that in combination with the fact that you may not have the same economics that you had before for an upgrade on some you may not see all of the light ends go back into the gasoline pool.

Okay, got it. Erik, very quickly, just on this working capital dynamic that you are referencing, how do you expect that to play out for the second half of the year is that going to continue to be the approach and when might we see some reversal from a cash hold perspective?

We could potentially see a reversal what I would guide to is the only way we really can say there would be a reversal as it’s roughly about 3 million barrels shifted in terms of having extended payment terms that now have shorter dated payment terms and the easy way to think about it is if crude by rail comes back, then we will see a onetime shift back in terms of positive working capital back in. But I think we felt very comfortable that excluding that phenomenon. Overall, the normalized level of working capital coming out of April increased in May and June. It just happened to be offset by 3 million barrels of shorter dated payment terms.

Okay, great. Thanks a lot

Next question is from Neil Mehta of Goldman Sachs.

Good morning team. Thanks for taking the time. I guess the first question is around 2021 capital spending, as you think about where that level will shake out, any early guidance would be helpful, recognizing there is a kind of uncertainty there?

Yes, what we said we expect ‘21 CapEx to actually be significantly below what we expect in 2020 to be. And so what we have to remain agile to react to the market so I would expect CapEx in ‘21 to be in the $500 million to $600 million range, which is $200 million below what we thought ‘20 was going to be, but to the extent the pandemic continues and gets worse, that would be adjusted down. And to the extent that that the world becomes normalized, there may be creep to it, where it would grow. So we are continuously, risk managing our business for the marketplace we are in, but we think the 2021 capital plan will be, like I said, significantly below where we thought ‘20 was originally going to be and then we will react to what the market is at that time.

Thanks, Matt. So as a two part follow-up to that, so to the extent that you are lower than the $500 million to $600 million base case, what are the levers that you have, you can pull on? And the follow up there is around further asset sales, monetization to your products helped pull some cash into the business. Are there any other levers that you have to strengthen the balance sheet? Thank you.

The answer to the second question is yes, there is certainly things we can do. I don’t know that makes sense to get into that now. But just in terms of running a refinery, you are continuously managing and hydrating different risks in terms of where you are going to allocate capital and what equipment you are going to address it when and utilization will clearly play a part in that. And so it’s something that we actively manage. We didn’t anticipate going into ‘20 that our capital plan would be where it is today, but we have successfully done it. That’s what we pay a lot of engineers to figure out on a daily basis.

Thanks.

Your next question is from Jason Gabelman of Cowen. Your line is open.

Good morning.

Good morning.

I wanted to ask you about an environment that we could get into operationally where gasoline and diesel continue to rebound and jet doesn’t. It seems like that alone could limit refinery utilization. Are you exploring ways to increase utilization back up to 90% above to kind of match a potential new demand profile for the country or do you see a natural limit to how high utilization could go even if diesel and gasoline fully return to normal demand?

That’s a great question. Let me just give a little backdrop on it though. You saw what the industry was able to do. And frankly what we were able to do, we got our jet production down, somewhere between, which typically runs 10%, 11%, 12% of our yield, we got it down to as low as 2%. We did that by taking all the normal steps that you take to either convert a distillate to gasoline, jet to heating oil or ULSD, but jet to gasoline. But we were able to do a lot more during the pandemic and we will continue to have that capability in response to the precipitous drop in jet demand, because the utilization in the industry was very low. So, this leads into your question, we were actually able to put jet fuel into the cat cracks, but because we had spare cat cracking capacity, we had spare hydro-cracking capacity. Not only was the crude utilization low, but all the downstream units will also. What you wind up having additional flexibility to predominantly target, first it was gasoline, but then jet and turn jet into both gasoline and distillate. And we continue to learn from that and we continue to find ways that we think we are going to be able to do that going forward. So, we do believe we will be able to get even in a depressed demand – a jet demand environment, get utilization up from where it is today and significantly up from where it is today. However, I am not convinced that we could get to full utilization in this industry, if jet demand is where it is today, because sooner or later when you are running your cat crackers with gasoline oil or you are running your hydrocrackers, which feedstocks that are coming off the crude unit, you don’t have that flexibility that I just referenced, because that those units of spare. If there is good margins, those units are going to be relatively full. And then you are going to run out of the ability to contain jet at some point. And it would be a good chance that, that would put a ceiling on utilization, but it will be much higher than where it is today.

Great, thanks. I appreciate that color. That’s really helpful. And then kind of tangentially to that, it seems like the pandemic is creating clearly differing views on where the world is going. And I am wondering if you are exploring any investments outside of kind of your core refining business or maybe changing kind of how you process your intermediates right now maybe into new demand verticals that you think have a better chance of growing in the future?

Yes. First of all, let me just be clear and I think we have told you everybody before, our strategy is very much focused on obviously getting through the pandemic, hoping to get back to some level of normalcy and then generating cash and de-levering the company. That is goal number one and Erik laid that out as our target is $1 billion of debt that we just did. However, after that, we do have plans and I have been looking at and we have actually talked, I think to you on previous calls, there is an opportunity for us to do something with Shell and Martinez in the renewables area. There is some other opportunities that we were looking at prior to the pandemic in Delaware City, along the same vein. We do feel the need in terms of that prioritization that I gave you is get back demand. Demand queue was everything. Utilization goes up. Cracks go up. The diffs go up the wider, generate the cash, de-lever the company and then diversify the portfolio in some manner.

Great. Very clear. Thank you.

Your final question is from Matthew Blair of Tudor, Pickering & Holt.

Hey, good morning, Tom. Just looking at the West Coast and looking at that $0.05 gross margin in Q2, do you think it’s fair to say that you faced some extra headwinds in this low demand environment from your merchant position and lack of retail or is that not accurate?

I think that’s clearly accurate. I am – I have never necessarily been a fan of retail going back to my Tosco days when Tosco own Circle K, but candidly, obviously, some of our competitors have benefited massively during a period of time when the spot prices were crashing and the retail lacks both down and up. And that certainly was a factor as I mentioned when we got to the immediate trough, we actually had I think it was negative – it’s almost double-digit negative gasoline cracks in California for a period of 7 to 10 days. And in the month of April, the gasoline for the – 3.21 to 4.31 depending upon which region you are looking at, was about $2. So, that type of merchant crack that we were dealing with being an emerging [ph] refiner and not having a tailwind from retail certainly was a negative factor for us versus Valero or MPC.

Got it. I will leave it there. Thank you.

Thank you.

That concludes our question-and-answer session for today. I would be happy to return the call over to Tom Nimbley for closing remarks.

Thank you very much. Thanks for joining the call. We look forward to hopefully having a much better call or better news for you on our third quarter. Everybody be safe, stay healthy. Thank you.

This does conclude the PBF Energy second quarter 2020 earnings conference call and webcast. You may now disconnect. Everyone, have a good day.