PBF Energy Inc (PBF) 2019 Q1 法說會逐字稿

Good day, everyone, and welcome to the PBF Energy First Quarter 2019 Earnings Conference Call and Webcast. (Operator Instructions)

It is now my pleasure to turn the floor over 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 the 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 safe harbor provisions under federal securities laws. There are many factors that could cause actual results to differ from our expectations, including those we describe in our filings with the SEC.

Consistent with our prior quarters, we will discuss our results excluding certain after-tax special items of approximately $375 million, which are primarily comprised of a noncash, lower of cost or market, or LCM adjustment, which increased our reported net income and earnings per share.

As noted in our press release, we'll be using certain non-GAAP measures while describing PBF's operating performance and financial results. For reconciliations of non-GAAP measures to the appropriate GAAP figure, please refer to the supplemental tables provided in today's press release.

I'll now turn the call over to Tom Nimbley.

Thanks, Colin. And good morning, everyone, and thank you for joining our call today. Our results for the first quarter reflect not only the challenging market conditions in terms of narrow crude differentials and weak product margins, particularly gasoline, but also the intentional efforts of PBF Energy to shift the majority of our 2019 major maintenance activities into the first quarter and the beginning of the second quarter.

As with most merchant refiners, we recognize the challenging market conditions where gasoline margins were flat to negative at times as an opportunity to do more work in a period with weak returns. Four out of our 5 refineries conducted turnarounds or significant maintenance during the quarter, which reduced our throughput and increased our expenditures. However, by moving the majority of our 2019 maintenance activity into the first quarter, we believe our actions have put our entire refining system in the strategically favorable position of being able to operate unimpeded for the remainder of the year.

Turning to the market, we had a rough start to 2019. People believe we would be awash in gasoline and refiners could do nothing right. I and several other of my colleagues, industry colleagues, made comments that the markets would correct. It is important to note that as of last week gasoline inventories were 10 million barrels below last year and 5 million barrels below the 5-year average. The refining industry will not keep running blindly at high utilization rates if roughly 50% of our production, i.e., gasoline, is not making any money. The markets will and did correct.

One area that remains a challenge is the narrow light heavy differential being largely driven by the externally driven supply constraints for heavy sour crude oil and a well-supplied light crude oil market.

Similar to the gasoline environment in the first quarter, we do not see this market condition as sustainable in the long term. Refiners will not continue to purchase noneconomic feedstocks when there are alternatives. PBF and others have taken measures within our system to adjust inputs and in some cases even lighten the slate, which is another way of saying backing out heavy crudes. It will take longer to correct in gasoline, but we believe that the light heavy differential will widen out as a result of some of those barrel (technical difficulty) upstream and eventual increases in supply from OPEC+, Alberta and others.

We are starting to see the beginnings of this correction as the spreads for high-sulfur fuel oil have started to widen out, which is a leading indicator for improvement. Strong economic activity and growth should continue to support demand for both gasoline and distillates. Global refining capacity additions are being delayed, and we expect to see -- to continue to see some capacity rationalization as marginal refineries struggle to compete in an increasingly volatile market.

With that as a favorable backdrop, we are also rapidly approaching the implementation of the IMO 2020 (technical difficulty) standards. We believe that this should have a positive impact on distillate demand with a drag along effect for gasoline and jet, and it should also be positive for the light heavy and clean dirty spreads for feedstocks as the industry tries to accommodate the low-sulfur requirements for products.

As we have said many times in the past, the best way to take advantage of opportunities in the market is to have our assets operating well. We intend to run our assets safely, environmentally responsibly and reliably, which will lead to profitability in an improving market.

Now I'll turn the call over to Erik to go over our financial results.

Thank you, Tom. Today, PBF reported an adjusted first quarter loss of $1.18 per share. First quarter EBITDA comparable to consensus estimates was a loss of approximately $27.7 million. PBF's effective tax rate for the quarter was approximately 26%, and for modeling purposes, please continue to use an effective tax rate of 27%.

Our first quarter results included $29.5 million of RIN-related obligations. At prevailing pricing, we expect full year 2019 RIN expense in the $125 million to $150 million range, which is down from our original estimate but remains subject to change. Consolidated CapEx for the quarter was approximately $261 million, which includes $250 million for refining and corporate CapEx and $11 million incurred by PBF Logistics. Our CapEx guidance for the year remains $625 million to $675 million, which includes $150 million for our strategic projects.

We ended the quarter with more than $2 billion of liquidity, with approximately $1.7 billion at PBF Energy and $350 million at PBF Logistics. Our quarter end consolidated cash balance was approximately $420 million, and our net debt to cap was 34%. We are pleased to announce that our Board has approved a quarterly dividend of $0.30 per share.

Finally, last week, PBF Energy announced the drop-down transaction of the remaining 50% interest of the Torrance Valley Pipeline Company with PBF Logistics at an acquisition cost of $200 million or 8x EBITDA. PBFX successfully raised $135 million of new common equity in an oversubscribed offering that fully finances the partnership's organic growth targets through 2020. Importantly, for PBF Energy, the $200 million of cash consideration will further strengthen the balance sheet.

We remain committed to the partnership and the growth that it provides for both entities, and I encourage you to listen to the PBFX earnings call later this morning for more color on the acquisition.

Now I'll turn the call over to Matt.

Thanks, Erik. Our total throughput averaged approximately 745,000 barrels per day for the quarter. As Tom mentioned, with the exception of Toledo, every one of our refineries conducted significant maintenance in the quarter. We completed a 50-day turnaround on the Torrance coker and other units and were able to come back up in March. Since completing its work, Torrance has run well into the second quarter and is well positioned to deliver strong results.

On the East Coast, we are wrapping up turnaround work on Delaware's coker and the plant should be online this weekend. We're targeting a 4-year run on that coker, which would be a record for any fluid coker in the world. Prior to our ownership, the normal cycle was 2 years. We're currently conducting some work at Paulsboro which should be wrapped up in the next 2 weeks. Finally, on the Gulf Coast, we identified some needed maintenance at Chalmette that we elected to advance in light of the weak product margins.

We remain intently focused on the aspects of our business that we can control. In the first quarter, we consciously took the strategic step to increase our maintenance activities during the weak period. This made a challenging quarter worse from a financial perspective but set up a net positive position for the company as it has a clean run for the remainder of the year. By the end of the second quarter, we expect that we will have completed 100% of our major maintenance for our entire refining system and will have expended 75% of our total CapEx for the year.

We are progressing with our strategic investments in the Chalmette coker and the Delaware City hydrogen plant. Both projects are on schedule, and we expect the coker to be in service in the end of the year and the hydrogen plant to be in service in the first quarter of next year. By front loading the year, we firmly believe we have put all of our refineries in the best position possible to benefit from the improving market conditions with an even better outlook.

Operator, we've completed our remarks, we'd be pleased to take any questions.

(Operator Instructions) Our first question comes from Roger Read of Wells Fargo.

I guess a quick question for you to follow up on the initial comments about the crude diffs. I mean, one of the main crudes that really held back in Q4 that really reversed in Q1 with WCS and the cut in production up there. Planned maintenance looks fairly high this summer. It looks like Canada would've been tight whether the market had been adjusted or not. And I was just curious how you think about that flowing through the widening of the light heavy?

I mean, I know Canada is only a small portion of global crude, but it is an important heavy crude in North America. So maybe -- you said it would take a little longer for it to clear up than with gasoline, is this a -- we've got to wait till Q3 or maybe it's even Q4 before we get relief on the light heavy spreads?

My own view, and we have others who might opine, but typically you're right, Roger. Obviously, the maintenance period is underway, and that is the typical time that the upgraders do their work. So it would've been tight anyway, we had actually envisioned that. But obviously, the decision by the former Premier to force the mandated cuts wasn't a step to intervene in the markets. That was certainly a negative for people who were running a WCS as indicated by the shift in the differential from the fourth quarter to first quarter.

I believe it -- and if you couple that with the fact that you've got all these other external influences, whether it'd be Venezuela, Iran, OPEC, non-OPEC, but your point was on Canada. We believe that we will probably -- I think, it's fair to say that we've kind of hit the peak, and we expect that we'll see some widening. In fact, looking at the market indicators from yesterday, I think we're up around $24 or $23.50 on a -- CS differential of Brent.

So we think it's going to be increasing, and of course, with the specter of IMO on the horizon, we would expect that would add additional pressure. We are seeing the spreads on fuel oil widening out a bit, which may be a leading indicator.

Okay. So -- I mean, I guess it does sound like maybe not an immediate clear up, but back half of the year things should get a little bit better on that front?

Roger, it's Matt. I would -- I think our house view specifically to Canada is by the end of the second quarter the market looks very different from it is -- where it is today. You mentioned the maintenance. The maintenance always seems to go. It coincides with the thaw that's going on there now. So we are seeing it widening, and like I said, by July 1 we think it's a very different picture than it is today and has been.

Okay, great. And then Erik, just a quick question for you. Tough quarter, obviously, on the cash side. Imagine you had a few days of moving things around fairly aggressively. But you now have everything with a pretty positive run rate for the remainder of the year. You got the incremental $200 million from the PBFX drop down.

What's the outlook for cash here? And what would you want to do? Is it -- debt was up a little in Q1, whittle that back down? Is there another step with it? Or how should we think about uses of free cash?

So we borrowed about $250 million on our ABL during the first quarter. That's really working capital driven. We've built some inventory during all of this accelerated maintenance. That's going to work its way through the system through the remainder of the second quarter. We expect that $250 million to be back down to nil by the end of June. And ultimately, it's going to be continue to strengthen the balance sheet.

So I think -- we've still got some CapEx that's going to flush through second quarter in the form of cash. But, ultimately, from our perspective, once we're through second quarter, we have a very clean runway here from a CapEx perspective and then it's all systems go.

Our next question comes from Manav Gupta of Crédit Suisse.

I just wanted to dig a little bit into the recent MLP drop. I don't even remember when was the last time a refiner dropped assets to the MLP and raised public equity for it. I think MPC did it back in 2017, but not after that. You can correct me if I'm wrong. So you raised $135 million in new common equity from your last drop. I'm just trying to understand, how did you manage to pull this rabbit out of the hat? I mean, I think this magic trick was lost to the refiners, so how did you manage to revive it?

Manav, it's Erik. We've spent a lot of time over the past 2 years with our MLP investors. We felt like the market was there. We've been very upfront from a drop-down perspective. The remaining 50% interest that PBF owned in Torrance Valley Pipeline made logical sense, very clean transaction, easy to work through with conflicts committee. And quite frankly, we've done a lot of the legwork on the front end; and at the same time, we got our IDR structure cleaned up during the first quarter. So we had pretty positive response from investors, some old money and some new money coming in that ultimately said, "Look, you've got a clean structure. It makes sense."

I think our plan too is this basically sets the pathway now for us to not have to access the public equity market in the MLP to fund our internal drop-down and organic strategy through 2020. So there's a bit of getting into the market, over funding the deal from an equity perspective that really sets us up for, kind of, 18 to 24 months here.

Manav, I'll just make one other point on the MLP. I think -- we work very hard. I think MLP is on so much firmer ground in terms of addressing issues that the market spoke to us about. And over the last year, we've cleaned up the rail contract Erik mentioned. We cleaned up the IDRs. We've executed on third-party acquisitions. We've executed on organic projects, and obviously, we executed on the sort of most logical drop-down that was in our system. Those are the 3 legs to that business, and we were very, very pleased that the market supported us in that effort.

I mean, very smartly done, guys. I have a quick follow-up. If you could talk a little bit about what's happening on the gasoline side, especially, on the West Coast? You're running very -- a lot harder in 2Q than in 1Q. So outlook over there and how you expect to benefit from what's going on, on the West Coast gasoline market?

Well, obviously -- and the overall strategy, we, obviously, like the West Coast. And it's -- to a large extent because we've seen this movie before. The supply chain is rather long, and it's obviously an [islandized] products slate in California versus the rest of the world. So when you have these opportunities that come about either because of significant plan, but in this case unplanned downtime, and you all follow the amount of unplanned downtime that occurred in the late part of the first quarter -- mid-to-late part of the first quarter, you get these rather extraordinary opportunities.

So we've had very good -- gasoline cracks or very good cracks overall out in California. I'm superstitious, so I'm knocking on the tabletop. We have been able to run -- and I'm very proud of the people of Torrance because in the past it has been more the norm that Torrance has created the opportunity as opposed to benefiting from it. But as you say, we've got the turnaround behind us in the first quarter -- middle of the first quarter. And we've been able to run pretty strongly beginning March and continuing through today. So it's a favorable environment.

Our next question comes from Blake Fernandez of Simmons Energy.

Erik, I think you already addressed some of the balance sheet questions, but one of things I was just hoping you could dig a little deeper. We've definitely sensed some concerns on equity issuance given the difficulty in the quarter and the balance sheet where it was. Obviously, you've alleviated some of that with this drop. I was just hoping you could kind of confirm what you think you need from a cash perspective to keep on the books. And also if you could elaborate a little bit on the working capital impacts and how you see that going forward?

Sure. Let's go in reverse order. So we had about $100 million of negative working capital during the quarter, so in terms of working capital draw. One thing I think we want to point out, the drop-down was not a direct tie to first quarter. We felt very firmly that putting in place a long-term balance sheet, essentially restructuring and refinancing our ABL as well as the acquisition revolver at PBFX in 2018 was the prudent move which would ultimately allow us enough flexibility to get through quarters like this.

And ultimately, from our perspective now, I think we've obviously got a few hundred million dollars' worth of CapEx that's going to roll through during the second quarter here. And again, that kind of puts us -- the only projects that we'll really be working on are the strategic projects for the hydrogen plant and the rest of the coker restart down at Chalmette through the end of the year.

From a cash perspective, it does depend on where hydrocarbon prices are. But ultimately, we would say it's probably prudent to keep anywhere from $250 million to $500 million of cash on the balance sheet at any point in time. We will at times use that ABL that is essentially is backed 100% by inventory receivables and cash. When we have periods of building hydrocarbon working capital, we will go ahead and borrow against that and then, ultimately, as we run those barrels convert them into products, ultimately sales and then receipts. We will then pay down the revolver.

Okay. That $100 million of working capital I suspect you're expecting that to reverse at some point here over the next quarter?

Yes. We should see that reverse through during the second quarter.

The second question is on turnarounds. It's pretty clear your system's going to be up and running for the balance of the year. I know you probably don't want to give too much color on 2020, but just -- I presume you're going to be largely up and running for IMO next year. But can you just kind of confirm that the turnaround activity you've accelerated here should, kind of persist or take it off the system for a while to where you don't have to do a lot of activity next year?

Well, we'll have a -- we do have some turnaround activity in Toledo that is planned for 2020. Beyond that, I think it's going to be somewhere around a normal turnaround year, 5-year average type to slightly lower than that.

Our next question comes from Justin Jenkins of Raymond James.

I guess maybe be on the theme of IMO 2020. Tom, I'm curious if given some of this skepticism in the market today if any changes to your expectations on how that unfolds as we approach summer months here and gasoline demand? And maybe how your expectations unfold on how the new demand for marine fuel is met here in 2020?

I really remain rather convinced that IMO is going to go, and it's going to go as planned. There's lots of chatter about it, but if you listen -- even the U.S. Coast Guard who is the representative to the IMO for the United States came out, I think, early this week or late last week and said that IMO is going to go, and it's just a question of getting everybody lined up to make sure that they understand the rules.

There's 1 more meeting, I think, I forget if it's in May or June, that they're going to go and deal with issues like if you have noncompliant fuel on board and you pull up to a port and what do they do with that? Do they force you to pump it off, or they give you something there? But those are basically fixing things around the edge.

We expect that the IMO is going to go into place -- there's actually a letter I think that was sent by 20 senators this morning to Donald Trump. Or yesterday it was sent to him saying that this is good for the United States because of the favorable energy position we're in, and it's good for the environment and we should support full implementation of IMO. And I believe that is going to happen.

As for the ramifications, I think they are is what we've talked about. And I'm absolutely convinced that nothing's changed in that regard. We're going to see an increase in distillate demand. I think in the initial stages you're probably going to see some of the shippers just go right to a very ultra-low-sulfur diesel type of fuel because that's already in existence with ECA fuels, 0.1 sulfur. So we'll get a bump in distillate demand. There'll be carry on floor under jet and gasoline because the spreads widen out too much. If gasoline goes significantly below, you're going to take gas all out of the cat crackers, and you're going to make compliant fuel.

And the thing that I think has the most legs is sulfur becomes the enemy here. You're moving from 3.5% sulfur as an output that you can dump sulfur into today, that going down by 83% to 0.5%. And so I would expect that you'll see very wide or much wider heavy fuel oil spreads versus distillate, and that will spread into light heavy differentials widening out.

So for a complex refiner, it's not the best time in the world right now and hasn't been. But complex refiners have all the knobs to turn to deal with any market environment we have. And we believe we're going to be going into a market environment that the complex refiners will be rewarded.

Our next question comes from Brad Heffern of RBC Capital Markets.

Tom, I just was hoping you could expand on some of the -- your prepared comments about shifting your crude slate. I think heavy refiners tend to run sort of max heavy pretty much all the time, so it's interesting to hear that you're shifting away in favor of light. So I was wondering if you could give some examples of the facilities that are doing that. And any sort of color on how much bandwidth you have to shift to light in favor -- or shift from heavy in favor of light?

Sure. And even I'll comment. I think -- I heard that Joe Gorder in Valero in the call talked about they're shifting to lights. And those are the knobs that I referred to earlier. We don't sit in a vacuum. We actually look at the economics and try to run these plants.

But specific to your point, obviously, we've got 5 refiners. Toledo runs all light sweet crude, so that's base. That's already there. And if you really look where we play -- the West Coast refinery runs predominantly the California crudes and that -- we are still seeing attractive economics on those, particularly with these cracks. So we really don't have any desire to lighten up, specifically out in Torrance.

So the emphasis is on 2 East Coast refineries and Chalmette. We actually did run a fair amount of LLS, swapped out Mars and ran LLS because the spreads were too narrow, and it was not economic to run Mars down in Chalmette. We ran 1 of the crude units basically almost completely on light crude, and we continue to look for other opportunities. So notionally 60,000 barrels a day that we can put in -- we can run more than that, but we were doing that in the month of March.

On the East Coast, we have the capability to run a lot of sweet crude. We've proven that before when we had the rail economics with Bakken. When we first -- several years ago, we were running north of 100,000 barrels a day of Bakken into Delaware. We are now running a fair amount of other waterborne light sweet crudes and some Bakken in there. We can run 60,000, 70,000 barrels a day without a problem if the economics say to go that way.

Paulsboro typically we've been running medium sours, but even in Paulsboro now, we're running a fair amount of light sweets, a lot of them coming down from Canada, Terra Nova and some crudes like that and other crudes that we're sourcing from the rest of the world. In total, we can do a fair amount. We can run, certainly, the smaller crude unit in Paulsboro 100% on sweet.

I would say this though, when refiners like me, or anybody else who have complex refineries, say that they can run all this sweet crude, it usually comes with a capacity cost. The units are not designed to go from Maya to Brent or TI and allow you to run it the same way. So I actually think you're going to see that going forward, and that's part of the reason the utilization may even stay a little bit low. Because if the economics favor running light sweet crudes, we're going to run light sweet crudes, but you're not going to be able to run them at the capacity that you would if you had a more balanced slate, if that make sense to you?

Yes. Perfect sense. And then I know you guys aren't directly affected by it, but I was wondering if you had any thoughts on the crude by rail bill in Washington State? And any thoughts about if that does, indeed, end up getting signed whether that might free up some Bakken for the East Coast system once again?

We really don't have a view as to whether or not it's going to get signed. There'll be a lot of -- back in -- it's probably not, but the impact on the refiners in the state of Washington who run rail, I know, U.S. Oil, which is now something else, bought by [Par], ran quite a bit of that.

Interestingly, I think -- if it did, it would, obviously -- you would have some Bakken that would have to be sourced elsewhere. We're looking at it right now. I mean, obviously, there's economics to haul Bakken to the East Coast today, but you have to have the supply chain in place. We're bringing in maybe 8,000 or 10,000 barrels a day of crude into Delaware. We'll look to do more of that, but we firmly believe that we're going to get a correction on the heavy side. And we're ready and we're lined up to go ahead and implement that, and that will only be exacerbated with IMO.

Our next question comes from Phil Gresh of JPMorgan.

Yes. A couple of questions here just on the OpEx side. First one would be, on the East Coast, obviously -- I presume that the first quarter was fairly impacted by the maintenance. And when I say this, I don't mean on a per barrel. I'm thinking more like on an absolute nominal basis. Looks like there's about $175 million OpEx. And if I think about where it was last year, it was up about $40 million year-over-year versus 2017. So I'm just trying to understand how we should think about East Coast OpEx on a, perhaps, a nominal basis or whatever color you can provide moving forward?

I'd say this. You are absolutely right. The East Coast refineries, particularly Delaware City, which had significant work -- and of course, we did have an unplanned downtime there because of a fire, which took us -- one of -- took the crude unit off for a period of time. Actually, their operating costs were quite high in the first quarter. We have made it very clear to the good people of Delaware City that they are going to eat that and they're going to bring it in on budget for the full year. But a lot of it was driven by, particularly in Delaware, by the amount of downtime that we had.

Also we have pretty high energy cost in the first quarter because of the weather conditions. We had very high energy cost in California, but even the rest of the system when the temperatures got down to minus 30 wind chill factors. That's behind us now, and as we move forward -- and the expectation is we're going to hit our budget. I made it very clear to all the refineries that we have front loaded this thing. We haven't increased it.

So if I think about last year, is that a more normal run rate call it, $4.70, $4.75 a barrel is more normal?

Yes. Absolutely.

Okay. One additional OpEx question just on Torrance with the drop-down. Should we expect to see that there would be an impact to the refining OpEx because of the drop-down?

No.

No.

That cost is going to be picked up in their cost of sales. So no impact to refinery-related operating expenses.

Okay. And then last question just with the drop-down and as you look ahead, and you talked a bit about the strategy of PBFX. Should we be thinking of this as continuing to be a drop-down story over the next 1 to 2 years in terms of how cash might flow back to the parent company?

I think at this point we've really evolved since 2014 from pure-play drop-down to a much more multifaceted approach to growth through organic projects as well as third-party acquisitions. Clearly, doing third-party acquisitions that's the most difficult thing to forecast. We're always looking at a variety of different opportunities that really kind of jibe with PBF Logistics, primarily when we see opportunities where the logistics company can ultimately lever its relationship with the parent company or sponsor. We're probably more focused today on organic-related projects, so we've been spending some money through the end of '18 and now into '19.

We're going to see, clearly, an incremental on an annualized basis $25 million coming in, in terms of EBITDA to the partnership. We probably for 2020 have another $10 million to $15 million of EBITDA that ultimately is going to be a result of what we're spending today. So the focus is really more driven by organic projects and third-party acquisitions. The Torrance Valley Pipeline was probably a bit unique in that all of the front-end work was done in conjunction with the 2016 acquisition of the preliminary 50% interest. And so this was really a cleanup transaction more than anything else.

Our next question comes from Benny Wong of Morgan Stanley.

Just wanted to get update and touch on the sourcing side a little bit, particularly with the White House ending the Iranian waivers. How is that going to affect your strategy going forward? Sounds like sourcing more domestic light crude may be part of that. And do you expect OPEC to really ramp up and make up for that shortfall?

Your guess is as good as mine, but I believe they actually will. The reality is I don't think OPEC wants $85 crude because it's going to impact demand, and they're targeting for a window here. I think they, obviously, see the opportunity here. Looking at this clearly of -- the sanctions against Iran afford an opportunity for other people who produce that type of crude to fill that void, and they should go ahead and take advantage of that. So we expect them to ultimately open up. Plus, there's huge economic incentive at these prices. So we expect that to be part of the correction, if you will, that we see going forward.

In the interim, we have been able -- and, of course, we have Venezuela, and that continues to be in flux, and it looks like it's escalating. We don't know what might happen there, but sooner or later, that situation is going to be resolved, and then there's going to be huge amount of investment put into Venezuela to try to see if you can improve not only the crude production there but probably even the refining situation.

But we have been able to commercially source other crudes that really have been backed out by the Saudis and crudes moving to the east and by the situation with the sanctions against Iran and Venezuela. Much of those grows from Colombia, Mexico and other places. So we can get the crude, and as it becomes economic and as their dips widen out, and of course, we expect Canada to open up the taps. We expect to be able to source what we need.

Great. Appreciate that, Tom. And just wanted to touch up on the RIN expense guidance. Just wanted to get your outlook on RIN prices behind that expectation. And we've been hearing -- or EPA signaling they'll be issuing less small-refinery waivers. Just wondering if we should expect that to put upward pressure on RIN prices?

No. I don't expect any change in the small-refiner exemptions. And I think -- and to this point, Secretary Wheeler has stuck with what was a deal. And I think the administration has navigated this issue in a reasonable fashion. One needs to take a step back. But no, I do not expect a decline in small-refiner waivers. And therefore, there is a surplus of RINs, which should moderate the price of RINs, full stop.

And our next question comes from Doug Leggate of Bank of America.

This is Kalei on for Doug. A lot has been touched, so just a couple of quick ones for me. Firstly, just can you talk about your remaining droppable assets at PDF? And whether or not this evolves as you bring on your coker and your other logistics projects later this year? And also you talked a lot about your market views, but just to clarify, do you remain to stay in max diesel mode this summer?

Let me take the last one, and I'll turn it back to Erik or Matt on the drops. Right now, we are running -- obviously, we're not running max diesel, and we haven't been. We're back into a very favorable gasoline market. And with the inventory situation and the fact that the economy continues to be -- we've got full employment. Demand is hanging up at 9.3 million barrels a day or so. We really haven't exported as much as we did in the past because of problems in exporting gasoline, weather related.

So we could have a situation where gasoline, which has been really the -- obviously, the commodity there that's pulled the heavy lifting, as my commercial VP -- President would say, "Hey, this is -- this could have some legs." And if it has legs, then we're going to wind up, obviously, continuing to run in a -- more of a maybe not max but very heavy gasoline mode, which then sets up a possibility for a relatively tight environment on distillate going into IMO. And once IMO hits, my guess is, at least in the beginning as this price probably adjusts quickly to the upside on distillate, that we'll be running max distillate for a significant period of time.

And on the MLP growth side, what we would point to is last year in the first quarter of 2018 we laid out a $100 million organic growth plan over a 4-year period. We've probably only eaten into about $5 million to $7 million of that EBITDA. So really the key focus is on, call it, the remaining $90 million to $95 million worth of organic-related projects that ultimately are somehow linked back to the sponsor's geographic footprint on refining. And ultimately, what we've done now is as a result of doing the Torrance Valley Pipeline drop, we've elongated the runway there. So we've got another, call it, 4 to 5 years that we can ultimately use that $95 million.

Then with respect to the drop-down EBITDA, we still have a variety of different storage facilities at the refineries. There are marine facilities, various pipelines, kind of your traditional MLP-related assets that still sit at the refining company, at the 5 refineries. But ultimately, our key focus right now on an internal strategy is on the organic side of things and that kind of coupled with the third-party acquisition strategy.

Our next question comes from Prashant Rao of Citigroup.

I wanted to focus on the East Coast a little bit. The guidance, obviously, implies that you'll be running at an almost flat-out utilization and the back half, you indicated [distillate] system overall as well. But -- sort of wanted to get your take on the cracks outlook, like a Brent crack. You talked about crude differential outlook, but I wanted to focus a little bit on the product side.

Last year, we had some oversupply issues. Obviously, indicated cracks in 4Q were in almost a negative territory. Things have cleaned up quite a bit. Just wanted to get a sense of how you see this playing out as we go through IMO, specifically for PADD 1, and kind of what that utilization, what that guidance underwrites in terms of your view?

I think -- we expect relative to IMO and its impact to be the same in PADD 1 as it's going to be in -- throughout the world most likely is that you'll initially see an increase in -- significant likely increase an ultra-low sulfur diesel. Because as I said before, my belief is people are going to start to burn compliant ECA fuels and make sure that they don't have any compatibility issues while -- and then, they'll adjust to a 0.5 fuel. So we expect to see a relatively favorable margins on ULSD across the system, including the East Coast.

And frankly, we'll see -- the forward curves has us going down to $4 and then at the end of the third quarter into the fourth quarter on gasoline. We will see gasoline come off seasonally, as it usually does. And we will see gasoline come off seasonally because we'll be putting light ends of butanes and back into gasoline. But I would not at all be surprised if we see more strength in gasoline. Because as I said, we've got to come up with 3 million barrels a day of new light product demand when IMO hits that isn't there today. And that will ultimately put a floor under all of these light products, jet, gasoline and diesel.

Okay. Appreciate that. Maybe switching to Canada real quick. A 2-part question. One, as we get into IMO, I just -- I wanted to get your thoughts on how quality diffs versus transport diffs play off of each other for Syncrude. I mean, for the bigger distillate cut actually coming out of the [ASEAN Syncrude], do you expect the quality to eventually show up. But obviously, Canada is having some transportation issues, which they're working through right now. So just wanted to get your high-level thoughts on that.

And then also, if any -- if in the market there's been any commentary from where you sit on the rails potentially being able to free up capacity beyond what their sort of public comments have been, in terms of what their earnings calls and what their ramp, I think we talked about, maybe through 2020?

On the first issue, obviously, Syncrude is a premium crude in terms of its sulfur content. In fact, we run -- the Syncrude that we run in Toledo, we -- Toledo basically cracks or feeds all of the 650-degree-plus material, atmospheric resid, right into the FCC. And we can only do that because of the quality of the crude, and Syncrude is a premium quality crude.

As regard to its impact on IMO, I think it will probably benefit. The light sweet crudes will likely benefit because of additional demand because sulfur is the enemy. At the same time, those crudes tend to very little 1050 plus, very little bottoms that really could go into a fuel oil pool, but they could become a blending component for us. So I think it would be somewhat favorable.

As regards to the rails, I think the initial -- somebody came out, I don't know if it was CN this morning or yesterday saying that, "Rail is a temporary solution." And they intend to provide that temporary solution until the pipelines are built. So you can decide whether or not you -- when you want to believe the pipelines will be built.

But rail will be there, and there's, obviously, active efforts. The minister also in Alberta wanted to get active in the railroads. We'll see how that goes with the new change in leadership that has taken place as of, I guess, Tuesday. But the rail situation is going to be there. There is going to be some give and take as to whether or not that's privatized or whatever, but that's probably the way it's going to go.

Great. And if I can just sneak one quick on cash flow. On the delta year-over-year in terms of investing cash flows, is it safe to assume that the majority of that, if not all of it, was due to turnarounds in maintenance? And a quick follow-up on that is sort of what should we expect kind of a run rate to be for the rest of the year given low maintenance activity?

Yes. I mean, from what we can control in terms of our CapEx, right, we're going to be through. If we think about our overall maintenance and turnaround budget of about $0.5 billion, we should be through the vast bulk of that by the end of June 30 in terms of cash out the door. We've, obviously, got $150 million worth of strategic CapEx. It's probably a little more back end weighted, and that's going to be what we're spending through the remainder of the year to get the hydrogen plant set up in Delaware City as well as getting the coker restarted down at Chalmette.

Our next question comes from [Silivio Mitalado] of Mizuho.

This is Paul Sankey. Can you hear me? Just a follow-up, really. I think you've referenced to your book. But, Tom, what's the outlook for Canada and for rail economics?

Okay, Paul. We -- I mentioned it, it's certainly starting to widen out. Versus Brent we were down at $16, $17, with $20 -- almost $22 as of yesterday. There is some inclination that the premarket-driven new Prime Minister will exceed and go along the lines of where Imperial and Suncor and Husky are trying to press. They want a free market. They want to be able to -- obviously, they have an integrated model.

So we are seeing indications that in fact that it's starting to loosen, and it is our belief that it will be modular transportation, quality transportation, economics driving where the WCS goes as they come out of turnarounds. And that, we're looking at probably something back in the $23, $24, $25 differential versus Brent as more the norm and that we would -- that would be economic for our East Coast system.

Got it. Just a further question. Did you -- yes, you did mention rail. It's probably partly because of the drama around Anadarko. But we haven't heard a lot since about M&A in refining recently. Is there anything to add from your perspective on market conditions or equivalent?

It just continues to be we look at everything that comes up. There's not a whole lot coming up, but if there's something that, that would work, we would certainly continue to be interested in it. But right now, there's nothing that we see that we got nailed down. And so we're focusing on trying to figure out how to come out of the first quarter and move forward for the rest of the year.

Our next question comes from Matthew Blair of Tudor, Pickering, Holt.

I was hoping you could disclose your heavy Canadian crude-by-rail volumes in Q1. And then what's your outlook on these volumes for Q2?

What did you say, Tom? We would -- you thought we'd be up around 60 a day in Q2?

We're going up to about -- in the second quarter -- this is Tom O'Connor. In the second quarter, we'll be gravitating back up into about a 65 to 75 KBD. And in the first quarter, the numbers were lower, in the 50 area, with having peaked in the first -- in January, leading out of the WCS price collapse of the fourth quarter, and those barrels (technical difficulty) throughout the quarter.

Got it. And then your overall throughput in Q1 was higher than your production levels at your refineries, which is maybe a little unusual. Does this mean that you have some intermediate inventory built up? And would that have any positive or negative implications on margin capture into Q2 if you have to work that off?

We absolutely built some intermediate working capital as well as just hydrocarbons related to buying crude, and ultimately that'll work its way through the system in the second quarter. We had a use of cash with respect to that working capital during the first quarter that we think will revert back to a positive benefit during the second quarter. So absolutely, we were storing some intermediates that ultimately we didn't want to sell at a massive discount that will be reprocessed and converted to clean products, as refineries come back online.

Our next question comes from Jason Gabelman of Cowen.

Yes. So it seems that if IMO plays out the way that you expect it to, you'll certainly generate a lot of cash in the back half of the year and into 2020. I'm just wondering how you're thinking about how you're going to deploy that excess cash between paying down debt and returning cash to shareholders and if you're going to potentially look to increase shareholder returns in a more sustainable way?

Yes. What I would say is we've had a pretty consistent dividend since we started the company from a public perspective in 2012 at $1.20 per share. And so our returns have been relatively consistent. We've done some share buybacks. Those have been in the rearview mirror at this point in time. But ultimately, I think, we try to be a little more prudent and not spend that cash until we actually have generated it.

So from our perspective now, the key was getting through the first quarter. We clearly have done that, and now we're focused on second quarter performance. And ultimately, we will respond accordingly to what the market gives us through the second half of the year. But we've got a pretty strong balance sheet now. Our prepayable debt kind of moves up and down depending on hydrocarbon prices. But ultimately, we've gotten the vast bulk of that down to 0. And so from our perspective, it's continue to improve the balance sheet.

Got it. If I could just ask a follow-up. I appreciate your comments about your outlook on kind of the heavy and medium sour market in the second half of the year. But are you seeing any indications more near term that supply from the Middle East to the U.S. is increasing? Or is it still kind of at these multiyear low levels in terms of imports?

It today remains at the multiyear low levels of imports. We'll see what happens. I think the Saudis want to make sure that when they -- I think it is tomorrow -- was it today or tomorrow that the sanctions go in place? They want to make sure that in fact that happens and there's no surprises on this. So -- but right now, obviously, they're at record lows, 30-year lows, I guess, in the amount of barrels that are moving to the U.S. We do expect that to change, but it hasn't yet.

Our next question comes from Neil Mehta of Goldman Sachs.

The first question is just on capture rates. In a higher crude price environment, Tom, I was hoping you could talk about the impact that has on bottom of the barrels and capture rates, as we think about modeling it for 2Q?

Yes. Obviously, there is an impact there, and it is basically focused on 2 commodities. Coke, if you are making a lot of coke, and we are coking a refined system, as the price of crude goes from $50 to $80 your margin on coke goes from $0 to $5 to $0 to $5. So actually, you lose another $30. So what you're selling for, you lose another $30.

So there's clearly an impact in the rising market on capture rate from coke to secondary that is somewhat inelastic, that doesn't move as quickly with the market as the light ends, particularly propanes, butanes. And so we'll see a widening of the margin loss versus crude on coke and propane. And you just take a look at the yield that we have of those 2 commodities, and you can calculate what it would be.

That being said, markets are efficient. Usually they are efficient unless they are artificially influenced as they are today. But what happens is as the price of crude goes up and those differentials widen out on those co-products, the light heavy spreads correct. In other words, if you're running a crude that has a lot of coke producing in it, you're going to have to get paid for that, and the differential will widen out. And that's what we will expect to see, particularly when IMO hits.

To that point, the $75 current range of that crude that Brent's in is a sweet spot for us. So we're not concerned about low-value product loss at this level because it also, as Tom said, spurs production and incentivize production. So we actually, sort of, like where the crude price is now.

Okay, that's great. And then the follow-up is just on California. A lot of noise and speculation right now about constraints in California crude supply potentially over time with the bill passing through the assembly. Just any thoughts on that? And what are boots on the ground saying about this risk?

We are not concerned about something being passed that would restrict waterborne deliveries or things of that nature. California is a different country. We all understand that. But the reality is, if you took something draconian like that you could run the risk of shutting down a number of refineries in the state of California. That is simply not going to happen. So we are not worried about having those type of constraints being posed. California likes to be different, and that has actually worked to our advantage, but we don't see that as a real risk.

This concludes the Q&A portion of our conference. I'd be happy to turn the call back over to Tom Nimbley for closing remarks.

Well, thank you very much everybody for joining our call today. We look forward to our next call when, hopefully, we'll have a better story to report to you. Thank you very much.

This does conclude today's PBF Energy First Quarter 2019 Earnings Conference Call and Webcast. You may now disconnect your lines. Have a good day.