PBF Energy Inc.

Good day, everyone, and welcome to the PBF Energy second quarter 2020 earnings conference call-in 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 over to Colin Murray of Investor Relations. Sir, you may begin.

Thank you, Leah. Good morning and welcome to today's call. With me today are Tom Nimley, our CEO, Matt Lucey, our President, Eric Young, our CFO, and several other members of our management team. A copy of today's earnings release, including supplemental information, is available on our website. Before getting started, I'd like to direct your attention to the Safe Harbor Statement contained in today's press release. 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 describe 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 $642 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'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. I'll now turn the call over to Tom.

Thanks, Colin. 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. We are 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 a daily basis, we require masks 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 US Gulf Coast and yields were shifted in accordance with gasoline demand dropping much more than distillate. Crude oil production continued unabated, culminating with the lowest price ever recorded for crude oil in late April. Since then, the market has done a lot of work towards cleaning up inventory balances, but we still have a lot of work to do. Utilization rates will likely stay on the low end of the range until the product surplus can be absorbed. Gasoline balances look far better than distillate, but just as the crude market had a miraculous recovery over the past few months, so will oil products. During the quarter, we significantly reduced expenditures. We were very measured in deploying cash into the opportunities presented by the disruption in the marketplace. In hindsight, we may have been too conservative. However, deploying incremental cash into working capital, given the uncertainty we and society were facing and the demand destruction we were witnessing, would have reduced our overall liquidity. We have moved past the low point in demand for most products, but the market is still rebalancing. There is a significant amount of product in inventory and it will take time for demand to work through that. The market is currently given few signals to materially increase utilization rates. The term structure of all the relative values we are watching are saying that product inventories, or more importantly, distillate inventories, need to draw more before utilization rates will have incentives to materially increase. This rebalancing has happened quite quickly for gasoline and for crude. Distillate will take a bit more time. With that, I will turn the call over to Matt to provide an update on our operations during the quarter and the steps we are taking moving forward.

Thanks, Tom. As Tom mentioned, we have taken aggressive steps to manage our refining system in response to market conditions. Overall, we ran our refining system at approximately 70% of capacity, with the East Coast and MidCon 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've 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 to 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 out of our own workforce, which has allowed us to reduce headcount, reduce it 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 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 40 to 50 cents 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 initiated 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 referment to Torrance for blending. Our marketing team has increased rack 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'll turn it over to Eric 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 the 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 five 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 and 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 swings 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've completed our opening remarks, and we'd be pleased to take any questions.

In a moment, we will open the call to questions. The company requests that all callers limit each turn to one question and one follow-up. You may rejoin the queue with additional questions. At this time, if you would like to ask a question, please press star 1 on your touch-tone telephone. To withdraw yourself from the queue, you may press the pound key. Your first question comes from Manav Gupta, of Credit Suisse.

Hey guys, can you hear me? Yes. Okay, so Tom, we keep hearing these news items where, you know, Google is saying we'll probably bring back employees second half of next year or Facebook is saying we're not bringing back employees, there's no timeline. I'm trying to understand What's 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, multifolded. But let me just say that we certainly saw Google's announcement, but Californians love to drive. And they're going to continue to drive when this pandemic passes. If you actually look, and I'm sure you do, look at PADD 5 in California, we're 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 Pad 5 was 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 Pad 5, where utilization has been around 70%. and it has helped clean up the inventories and the cracks have responded. Physical cracks, I don't know what they closed at yesterday but the day before were about $13 both in San Francisco and in Los Angeles. So my personal opinion is we've passed the lows. Obviously, it's all going to be a function of whether or not there is a second wave or a third wave, but assuming nothing extraordinary happens, I believe that we have passed the lows and demand will continue to creep up, not only in Pad 5, but across the country. Typically, people say California's long, or Pad 5 is long, one and a half refineries. That is very seasonal in a normal market. It's not long at all in gasoline seasons, actually nine months a year perhaps. So I think we're 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're seeing, Tom, here is during the summer, when you look at screens, were pretty much neck-to-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 PSX report a negative EBIT from their mid-con, but today they did. And even in your case, the gross margin at Shellmate was much better than the one at Toledo. So I'm just trying to understand what's driving this variance where Gulf Coast is coming in a little stronger than expected, and MidCon 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 MidCon first. We obviously had the catcracker 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 big continent. Now, when you shift to Chalmette, frankly, it's the crude difference. did have a reasonably good crude differential. In fact, 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're 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 asking my questions.

Your next question is from Roger Reed of Wells Fargo.

Hey, thank you. Good morning, guys. Morning, Roger. And since my dogs are running around, if you hear any barking in a minute, that's probably why. Quick question for you on the OpEx side. So we've got the guidance to save $250 million in 2020. A lot of moving parts, it sounds like here. And I was wondering if you could kind of work the reconciliation force of what makes up the 250 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're 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'm not sure that precisely what you're referring to in regards to 250. We guided last quarter to $140 million of operating expense savings in 2020, and we'll exceed that. What I said in the comments was that 140 consisted of about $110 million of non-energy related savings. We've increased that from 110 to 145. We've had significant CapEx reductions in this year, which get as well and above $250 million. Those are the numbers for 2020. In regards 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, $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're actually in a better position. 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're taking I think will position the company to not only absorb the increased costs 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, it's in the press release. It said, 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 back to the numbers that we're talking about. Maybe it's a different time frame for the 250, but that's, I don't know if you can help us there. That's what I'm trying to get to is the The $145,000 up from the $110,000 versus the $250,000, and it doesn't sound like that includes CapEx, so I was just trying to make sure I understood point A to point B here.

Roger, hey, this is Colin. Sorry, the $250,000 is a kind of total expense savings, which also includes the salary reductions that we put in 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 of now more than 250 with our increased expectations for operating expenses.

Okay, so the 110 was embedded in the 250. If that's now 145, we add that to the 250 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 last, I guess, let's call it exit rate of Q2 to what is now the last day of July in terms of as you look across your various regions, you know, things that look better as we think about gasoline, diesel, and jet fuel. And if you can give us any sort of regional breakdown, that would be great as well.

Well, certainly, I alluded to it in the first question from where we are. frankly pads one, two, four for that matter, and five have all improved in terms of the inventory levels. They're getting pretty close on even distillate, but everything but yet to where we're starting to get within the band of the five year average. The only one that remains above that band is pad three. We have seen improvements in all of the other pads. Demand has increased. The four-week movement average after Wednesday's report is about 8.7 million barrels a day on gasoline, 3.6 on distillate, and that's up a fair amount. Obviously, it's up a huge amount from the lows that were seen at the trough. Jet demand remains obviously very much impaired, but is actually incrementally moving up as well. What we've seen, we have started up a number of units that we had shut down and idled completely during the trough. The Paul Toro catcracker has been started back up. The Toledo catcracker has been started back up. We continue to watch it very closely, but we do have the ability to and have slightly increased utilization. Utilization itself in the country is now, and the industry is almost at 80%. We're below that. We're going to be very disciplined and make sure that this light at the end of the tunnel is not a train, and we continue to see it creep, but we think creep upward in demand, and that will help us correct. So regionally, Pad 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 capacity that exists in the Gulf Coast, we need a good export market to clear the barrel. We don't have that on gasoline right now. We're still a net importer on gasoline into the country. We have pretty good distillate exports, and the forecast going forward, at least as I read some of the prognosticators, is that exports into Latin America, both on gasoline and distillate in the third quarter, will increase. And that should help further improve the situation in Pad 3. You all see the distillate inventories are very high, and they're very high in Pad 3. 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 segue from those comments on the Gulf Coast there. to a broader question on utilization levels and also sort of asset 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 become more normalized? I think we all sort of think if we get into the 80s that we should start to see if demand can support that, that makes sense to see start to think that margins move within sort of a normal range historically, even though they'll 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've been seeing both globally and in the U.S., that would be helpful too. Particularly on the Gulf Coast, we've seen there's been some surprises there. Some of the major assets that are either being marketed or or, you know, have crude units down. So any color there, you know, given your experience going through cycles would be helpful.

Yeah, absolutely. In terms of the margin, I would agree that, well, I back up a little bit when you say, well, utilization would be necessary or would be bent to a capture rate that allows you to stay break-even or start making money. Well, obviously... is going to be a function of the utilization rate, the crack spread, and the crude differential. But assuming that those things kind of equilibrate, then I think, yes, you can get to certainly where you're not draining cash if you've got a utilization buying large over 80% where the industry is getting close. We're not quite there yet, but we're 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 three dollar cracks on place that's just that's insane and the industry has to be very disciplined here on in terms of I am personally convinced that there will be rationalization permanent rationalization in the this business at to what level I don't know I but speaking to where we are today if you take a look at The United States. There's been about almost 850,000 barrels a day of capacity that has been shuttered completely. Some of that may be temporary, some of that may be permanent. I include in that PES, so we know that one's 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're going to shut down on August 1st temporarily. They'll watch the margins. Holly Frontier has indicated that they're going to turn their Cheyenne plant from a fuels plant operation into a biofuels. And Marathon has a couple of refineries down, and we don't know what the long-term longevity is. But there is going to be continued rationalization. Similarly, there's probably 600,000 or 700,000 barrels a day of capacity that's been shuttered temporarily, at least, in Europe. And I think there's more to come on that over the next year or two. And if you just back up for a moment, the margins in Singapore have been negative for the last two, three 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 we're losing less money than other parts of the globe. But All right.

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

I've been now on the plant for six months, as of tomorrow, and everything we know about the plant has reconfirmed what we thought about the plant 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, even dah, 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've known about the people, about the steel, the capabilities of the refinery is as strong as we thought, and we've been impressed tremendously by the asset and by the people there. We just haven't been able to demonstrate it.

Okay. Thank you very much for the time this morning, gentlemen. I'll turn it over.

and once again to ask a question that is star one on your touch tone telephone. We'll move next to Doug Leggett of Bank of America.

Good morning, everyone. I will make the same apologies for dogs barking if that happens in the background.

I hope everybody's doing well out there.

Guys, can we talk about the balance sheet a little bit and just what do you see as your route to success? De-leveraging in light of everything that's been talked about so far. And I guess the logical question would be where do 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 and increasing the path to free cash flow and then we have always viewed this most recent billion dollar bond deal on the secured side as an insurance policy and so the plan would be it's a five-year piece of paper with a no-call provision for two 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 two years. That's ultimately our goal. I think we've been de-levering 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, we hope you're right on the trajectory, but let me just try one other one, if I may, guys. It's a question I asked a little 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'm just wondering if you can walk us through how you see the dynamics there. on heavy oil differentials and perhaps confirm whether you believe that flotilla 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, we're sitting here today with, you know, roughly about 10 million barrels year-on-year from crude oil production, which is not on the market. You know, we're sitting there with, you know, roughly two to three of that is coming out of the U.S., and the remainder of that would be from OPEC and OPEC+. leaving in that range 7 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.

Good morning, everyone. Thanks for taking my question. Just wanted to get an update on your perspective on what you're 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 strengthening is coming from, how resilient it could be, and if there's any kind of seasonal inventory building factors kind of embedded in there.

From what we see, I think that The export demand has held up nicely on distillate. It's 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 distillate 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 of 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. I'll just leave it at that for the Gulf Coast. There's not much activity and other parts of the country, certainly on an export basis. So I think we'll 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.

Great. Thanks for those thoughts. I really appreciate it. My second question is, earlier this month we've 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 from everything we've heard from Enbridge and energy transfers, the pipelines they believe are operating and will continue 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 shut down, but Enbridge is also looking at ways to source barrels. They indicated as much in their earnings call. We haven't heard much of that, but we'll have to watch that closely. As regards DAPL, if indeed that line were to be shut down, and again, I don't think it's going to be shut down, but it's obviously going before an appeals court, and that will ultimately be a decision to be made by the judges. But we would likely see, obviously, the Bakken differentials weakened 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 J.P. Morgan.

Hey, good morning. I wanted to follow up on the commentary around The sour barrel is coming back to the market. And just to get your view on actually the shale side of things, we've seen a 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. light sweet crude differentials moving forward? Is this what we're seeing now? Is this a new normal in your view, or could things widen back out?

Phil, it's Tom. You know, in terms of this question, I think, you know, a couple important things to look at. You know, as we are talking about the market coming back in terms of it's on the demand side of the equation and more sour coming back onto the market, you know, I think we can sit here today and say that we're past the narrow point of what we've seen on the light heavy differentials, right, when it got in, you know, almost flat and we're starting to see some trajectory of it moving out, you know. OPEC changes for August will probably be more felt come September, which will then correspond in terms of demand. And as it relates specifically to shale oil in the U.S., there's clearly a lot of discussion in terms of decline rates versus ducts 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've given a lot of commentary on product markets. I guess one follow-up would just be as we flip 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're a little bit more optimistic on gasoline, but then we do have that seasonal dynamic coming.

That's a good question. We've 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 turn the engines over in the middle of the winter. In fact, we're looking at it real hard. If all of a sudden everybody starts improving or increasing gasoline yield and the gasoline crack goes down, my guess is you're going to have economics that are going to say either don't put all of the light ends into the pool or you're going to have to make some adjustments elsewhere. I also have a suspicion, and this is just my own opinion, that like everything else that's going on in the world, We're not going to see the new normal be okay. Labor Day has passed. Everybody's going to go back to hunkering down because people didn't go on vacations. People didn't travel. And you're 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. Eric, very quickly just on this working capital dynamic that you were 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 might we see some reversal from a cash flow 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 is 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 one-time 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. Mm-hmm.

Your 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's a kind of uncertainty there.

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

Thanks, Matt. So 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 can pull on? And the follow-up there is around further asset sales. monetization to air 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's 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're continuously managing and High grading, different risks in terms of where you're going to allocate capital and what equipment you're going to address and 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've successfully done it. That's what we pay a lot of engineers to figure out on a daily basis.

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

Morning. I wanted to ask 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, you know, 10%, 11%, 12% of our yield. We got it down to as low as 2%. We did that by taking all of the normal steps that you take to either convert distillate to gasoline, jet to heating oil, or ULSD, or jet to gasoline. But we were able to do a lot more during the pandemic, and we 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 catcrackers because we had spare catcracking capacity. We had spare hydrocracking capacity. Not only was the crude utilization low, but all the downstream units were low. So we wound 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're going to be able to do that going forward. So we do believe we'll 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'm 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're running your cat crackers with gas oil or when you're running your hydrocrackers with feedstocks that are coming off the crude unit, you don't have that flexibility that I just referenced because those units are spare. If there's good margins, those units are going to be relatively full. and then you're 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'll 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'm wondering if you're 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 told 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 Eric laid that out as our target is the billion dollars of debt that we just did. However, after that, we do have plans and have been looking at and we've actually talked to I think you on previous calls there's an opportunity for us to do something with Shell and Martinez in the renewables area there's 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 cures everything. Utilization goes up. Cracks go up. The dips go up. Go wider. Generate the cash. De-level 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.

Good morning, Tom. Just looking at the West Coast and looking at that five cent gross margin in Q2, do you think it's fair to say that you face 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've never necessarily been a fan of retail, going back to my Tosco days when Tosco owned 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 lagged, both down and up. And that certainly was a factor, as I mentioned. When we got to the immediate trough, we actually had almost double-digit negative gasoline cracks in California for a period of 7 to 10 days. And in the month of April, the 321 or 431, depending upon which region you're looking at, was about $2. So that type of merchant crack that we were dealing with, being a merchant refiner and not having A tailwind from retail certainly was a negative factor for us versus, say, Valero or MPC.

Got it. I'll leave it there. Thank you.

Thank you.

That concludes our question and answer session for today. I'd 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 on webcast. You may now disconnect. Everyone have a good day.