Good day, everyone, and welcome to the PBF Energy First Quarter 2019 Earnings Conference Call and Webcast. At this time, all participants have been placed in a listen-only mode. And the floor will be open for your questions, following managements prepared remarks. 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 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 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 item of approximately $375 million, which are primarily comprised of a non-cash 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 will be using certain non-GAAP measures while describing PBF's operating performance and financial results. For reconciliations of non-GAAP measures to 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. 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. The gasoline margins were flat to negative at times as an opportunity to do more work in a period with returns. Four out about five refineries, conduct turnarounds or significant maintenance during the quarter, which reduced our throughput and increased our expenditures. However, by moving a 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 into the market. We had a rough start to 2019, people believe we would be a wash 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 five-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, the heavy sour crude oil and a well-supplied light crude oil market. Similar to the gasoline environment in…

Thank you, Tom. Today, PBF reported an adjusted first quarter loss of $1.18 per share. First quarter EBITDA comparable to consensus estimates with a loss of approximately $27.7 million. PBFs 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 a $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 remained $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 dropdown 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 is 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 40-year run on that Coker, which would be a record for any Fluid Coker and the world. Prior to our ownership, the normal cycle was two years. We're currently conducting some work at Paulsboro, which should be wrapped up in the next two 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 this strategic step to increase our maintenance activities during the week 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 we expanded 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 hydrogen plant to be in service in the first quarter of next year. By frontloading 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.

Yes. Good morning. In fact you glad to have Q1 behind you now.

Yes, I think.

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, it really held back in Q4 that really reversed in Q1 with WCS and the cutting production up there. Plant maintenance looks fairly high this summer. It looks like Canada would have 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, heavies. 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 then with gasoline. Is this - we got to wait until 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 that maintenance period is underway and that's the typical time that the upgrades do their work, so it would have been tied anyway. We had actually envisioned that, but obviously the decision by the former Premier to force the mandated cuts was a step to intervene in a market that was certainly a negative or people who were running WCS as indicated by the shift into differential from the fourth quarter to first quarter. I believe that - and you couple that with the fact that you've got all these other external influences, whether it be Venezuela or 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 WCS differential of Brent. So we think it's going to be increasing. And of course with the specter of IMO on horizon, we would expect that would add additional pressure. We all have seen the spreads on fuel little widened out a bit which maybe a leading indicator.

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

Roger, it's Matt. I think our house view specifically [indiscernible] is by the end of the second quarter, the market looks very different from it is the where it is today. You mentioned the maintenance, the maintenance always seems to go, it coincides with the saw that's going on there now. So we're 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. Thanks for that. And then Erik, just a quick question for you. Quarter obviously on the cash side, imagine you had a few days and 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 from the PBFX dropdown. What's the outlook for cash here and what would you want to do? Is it - debt was up a little in Q1? Widdle that back down. Is there another step with it? Or how should we think about uses of free cash?

Yes. So we borrowed about $250 million on our ABL during the first quarter that's really working capital driven we 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 beat back down to nil by the end of June and ultimately it's going to be continued to strengthen the balance sheet. So I think we've still got some CapEx that's going to flesh 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.

All right, great. Thank you.

Our next question is comes from Manav Gupta of Credit Suisse.

Hey guys, I just wanted to deep dig a little bit into the decent 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 raise 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 hack. And then I think this magic trick was lost of the refineries, so how did you do manage to revive it?

Manav, it's Erik. We've spent a lot of times over the past two years with our MLP investors. We felt like the market was there. We've been very upfront that from a drop-down perspective. The remaining 50% interest that PBF-owned in Torrance Valley Pipeline made logical sense, very clean transaction and 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 to clean structure it makes sense. I think our plan two 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 an 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 months to 24 months here.

Manav, just make one other point on the MLP, I think we've worked 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, Eric mentioned we cleaned up the IDR's, 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 three legs to that business. And we were very, very pleased that the market support us in that effort.

No, I mean they 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 - lot harder in 2Q and then 1Q. So outlook over there and how you expect to benefit from what's going on the West Coast gasoline market?

Well, obviously - and the overall strategy we obviously like the West Coast. And it's to a logic stance because we've seen this movie before. The supply chain is run along and it's obviously an Island Ice products slate in California versus the rest of the world. So when you have these opportunities that come about either because of a 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 and very good cracks overall out in California, superstitious. So I'm knocking on the table, top of that we have been able to run and I'm very proud of the people of Tolerance, because in the past has been no more than norm that Tolerance has created the opportunity as opposed to benefiting from it. But as you say, we've got to turnaround behind us in the first quarter, the 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.

Thanks for taking my questions guys.

Our next question comes from Blake Fernandez of Simmons Energy.

Hey, guys. Good morning. Erik, I think you already addressed some of the balance sheet questions, but one of the things I was just hoping you could dig a little deeper. We've definitely sent 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 a $100 million of negative working capital during the quarter. So in terms of working capital draw, one thing that I think we want to point out, the dropdown 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 $100 million 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 will really be working on or 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 in any point in time. We will at times use that ABL that 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 of the quarter?

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

Okay. Thank you. The second question is on the turnaround. It's pretty clear your systems 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. I have five year average type to slightly lower than that.

Okay. Thank you, guys.

Our next question comes from Justin Jenkins of Raymond James.

Great, thanks. Good morning, everyone. I guess maybe on a theme of IMO 2020 time. I'm curious if given some of the 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 fuels met here in 2020?

I really remained rather convinced that IMO is going to go and it's going to go as planned. There's a lots of chatter about it, but if you listened to 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 understand the rules. There's one 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 non-compliant fuel onboard and you pull up to a port, what do they do with that? They push you to pump off or they give you something there? But those are basically fixing things around the edge. We expect that the IMO is to go into place. There's actually a letter, I think that was sent by a 20 senators this morning to Donald Trump. Yesterday, we sent to them 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 as what we've talked about. And I'm absolutely convinced that nothing has 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 it's already in existence with echo fuels, 0.1 sulfur. So we'll get a bump in the additional demand. There'll be carry on floor under jet and gasoline because the spreads widened out too much. If gasoline goes, they're significantly below, you're going to take gas or a lot of the cat crackers and you're going to make it 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 expect that you'll see very wide or much wider heavy fuel oil spreads versus desolate and that will spread into a light-heavy differentials widening out. So for a complex refiner, it's not the best time in the world right now and it hasn't been, but complex refiners have all the knobs to turn to deal with any market environment we have and we believe whether they're going to be going into a market environment that the complex refineries would be rewarded.

Perfect. I appreciate all that detail, Tom. I'm going to leave it there.

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

Hey, good morning everyone. Tom, I just was hoping you could expand on some of the 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 you are doing that and then 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. I'll even comment. I think I heard that Joe Gorder and Valero in the call talked about they are shifting to - those are the knobs that I referred to earlier that 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 five refineries. Toledo runs all the light sweet crude. So that's base and 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 turns. So the emphasis is on the two 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 one 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 have proven that before, when we had the rail economics with Bakken, when we heard a 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 crude and in 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 of the crews like that, and other crews that were sourcing from the rest of the world. So in total we can do a fair amount that we can run certainly the smaller crude unit in Paulsboro, 100% on sweet. And 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 that 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 makes sense to you.

Yes, perfect sense. Thanks. 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 and 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 and it's probably not, but the impact on the refineries in the state of Washington who run rail, I know U.S. oil, which is now something else by far ran quite a bit of that. Interestingly, I think if it did, it would obviously have some Bakken that would it have to be sourced elsewhere? We're looking at it right now, I mean, obviously there's economics to all Bakken to the East Coast today. But you have to have the supply chain in place. We're bringing in maybe 8,000 to 10,000 barrels a day of crude into Delaware. We'll look to do more of that, but we firmly believe that we are 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.

Okay. Thank you.

Our next question comes from Philip Gresh of JP Morgan.

Hi, good morning. 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 an absolute nominal basis. It looks like there's about 175 million of OpEx. And if I think about where it was last year, it was, it was up about 40 million year-over-year versus 2017. So I was 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?

Yes. I'd say this, you are absolutely right. These cost 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 want to the crude unit or 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 costs in the first quarter because of the weather conditions. We had very high energy costs in California, but even the rest of the system when the temperatures got down through minus 30 a windshield 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 of the refineries that we have front loaded distant, we have an increased it.

So if I think about last year's at a more normal run rate call it 4.70 or 4.75 a barrel is absolutely more normal.

Yes, absolutely.

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

No.

No. That cost was going to be picked up and their cost of sales. So no impact to refinery related operating expense.

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 one to two years? In terms of how cash might flow back to the parent company?

I think at this point, right, we've really evolved since 2014 from pure play drop-down to a much more multifaceted approach to grow 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 jive with PBF logistics, primarily when we see opportunities where the logistics company can ultimately will lever its relationship with the parent company or a sponsor. We're probably more focused today on organic related projects. So we've been spending some money through the end of 2018 and now into 2019. We're going to see clearly an incremental on an annualized basis, $25 million coming 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. 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 clean-up transaction more than anything else.

Okay. All right. Thanks a lot.

Our next question comes from Benny Wong of Morgan Stanley.

Great. Thanks guys. Just wanted to get update and touch on the sourcing side a little bit, particularly with the White House, and into Iranian reverse. How's that going to affect your strategy going forward? It sounds like sourcing more domestic light crude might be part of that, and do you expect OPEC to really ramp up and make up for that shortfall?

Well, 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 are targeting for a window here. I think they obviously see the opportunity here if they're looking at this clearly of the sanctions against Iran afforded an opportunity for other people who produced that type of crew to fill that void and it should to 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 correct unit, 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 the situation is going to be resolved. And then there's going to be a huge amount of investment put into Venezuela to try to see if you can improve not only the crude production, but probably even the refining situations. But we have been able to commercially saw us other crudes that really have been backed out by the Saudis and accrues moving to the east and by this situation with the sanctions against Iran and Venezuela. Most of those crews from Columbia, Mexico and other places so we can get the crew, and as it becomes economic and ethnic dish right now, and of course we expect Canada opened up the tabs. We expect to be able to source what we need.

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

No. I don't expect any change in the smaller refiner exemptions. And I think to this point, Secretary Weller as stuck with what was a deal and I think the administration has navigated this issue in a reasonable fashion when you take a step back. But now 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.

Great, thanks guys.

Our next question comes from Doug Leggate of Bank of America.

Hey, guys. This is Clay on for Doug. A lot hasn't been touched though, just a couple quick ones from me. Firstly, just can you talk about your remaining drop of elastic, that PBF and whether or not this evolves as you bring on your coker and your other religious projects later in this year? And also you've talked a lot about your market views, but just to clarify, do you remain to stay in max distillate 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 distillate. You 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 explored it as much as we did in the past because of problems and exporting gasoline, weather related. So we could have a situation where gasoline, which has been really - obviously the commodity has pulled the heavy lifting as my Commercial VP, President would say, hey, this is a - 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 match, but the very heavy gasoline mode, which then sets up a possibility for a relatively tight environment on distillate going into IMO. Once IMO hit, my guess is at least in the beginning as this price probably adjust quickly to the upside on distillate that will be running match 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 at $100 million organic growth plan over a four-year period. We've probably only 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 sponsors 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 at four to five years that we can ultimately use that $95 million. Then with respect to the dropdown EBITDA, we still have a variety of different storage facilities at the refineries there, marine facilities, various pipelines, kind of your traditional MLP related assets that still sit at refining company at the five 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.

I appreciate the answers guys. Thank you.

Our next question comes from Prashant Rao of Citigroup.

Good morning. Thanks for taking the question. I wanted to focus on the East Coast a little bit. Look guidance obviously implies that you'll be running at almost flat out utilization in the back half as you indicated just recently overall as well. But sort of wanted to get your take on the cracks outlook, Brent crack. You've talked about crew differential outlook that I wanted to focus a little bit on the product side. Last year, we had over supply issues obviously indicated cracks in 4Q in all of the negative territory. Things are cleaned up quite a bit. So 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 with that guidance under rights in terms of your view?

I think we expect relative IMO and its impact to be the same in PADD 1, it's going to be throughout the world, most likely is that you'll initially see an increase in a significant - likely increase in ultra-low sulfur diesel, because as I said before, my belief is people are going to start to burn client eco fuels and make sure that they don't have any compatibility issues and while - and then they'll just adjust to a point biofuel. So we expect to see relatively favorable margins on ULS across the system, including the East Coast. And frankly, we'll see the forward curve how this is going down to [indiscernible] at the end of the third quarter into the fourth quarter on gasoline. We will see gasoline more seasonally as it usually does. And we will see gasoline come off seasonally because when we put in light ends or butanes and back into gasoline. But I would not at all be surprised if we see more strengthened gasoline because as I said, we got to come up with 3 million barrels a day with light product demand when IMP hit. That isn't there today and that will ultimately put a floor under all of these light products, jet gasoline and diesel.

Okay. Thank you. Appreciate that. Maybe switching to Canada real quick, two part question. One, as we get into IMO, I wanted to get your thoughts on how quality dispersive transport get to play off of each other for Syncrude and into the bigger distillate cut natural coming out of the assets and Syncrude, did you expect the quality differential show up, but obviously Canada is having some transportation issues, which we're working through right now. So just wanted to get your high level thoughts on that. And then also if - in the market there's been any commentaries from where you sit on the rails potentially being able to free up capacity beyond what they should have public comment have been in terms of with their earnings calls and what they ramp, I think that you talked about maybe through 2020?

On the first issue, obviously Syncrude is a premium growth in terms of sulfur content and in fact we run, Syncrude that we run in Toledo. At Toledo basically crack or feeds all of the 650-degree plus material atmospheric [indiscernible] right into the FCC and we can only do that because of the quality of the crude and Syncrude is a premium quality growth. As regards to its impact on IMO, I think it will probably benefit the light sweet crews will likely benefit because of additional demand, because software is the enemy. The same time, those crudes tend to have very little 1050 plus, very little bottoms that really could go into a fuel oil pool, but they could become a blending component for it. So I think it would be somewhat favorable. As regards the rails, I picked the initial, just somebody came out I don't know if it was seeing 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 win you want to believe the pipelines will we build. But rail will be there and there's obviously active efforts the minister also in Alberta, I 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 real situation is going to be there. There is going to be some give and take as to whether or not that's a privatized or whatever. But that's probably the way it's go.

Great. And then if I could just make one quick one on cash flow. On the Delta of year-over-year in terms of investing cash flows. I safe to assume that the majority of that it's not all of those ones. Do you do turnarounds and maintenance and I guess the follow-up, I'm 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 turnarounds budget of about $0.5 billion and should be through the 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 in waited. 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.

Thanks very much for the time and the answers guys. I'll turn it over.

Our next question comes from Silvio Micheloto of Mizuho.

Hi, guys. This Paul Sankey. Can you hear me?

Yes, we can Paul. How are you?

Hi, guys. Yes, thanks for all the details. Just the follow-up really I think you've referenced table. So what's the outlook for Canada and for rail economics? Thanks.

Okay. Paul. I mentioned it's certainly starting to widen out, it versus Brent we were down at $16, $17 with a $20 almost $22 as of yesterday. There's some inclination that the free market driven new Prime Minister will exceed and go along the lines of where Imperial and Suncor and Husky or trying to press, they want a free market, they want to be able to, obviously they have an integrated model. So we are seen indications that - in fact that is thought in the loosen and it is our belief that it will be module 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 is more the norm and that we would be economic or East Coast system.

Got it. Just for the questions. Thanks for the kind of the commentary. You did mention rail. It's probably partly because of the drama around Anadarko, but we haven't heard a loss of about M&A in refining recently. Is there anything to add from your perspective on market conditions or equivalent? Thank you.

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

Understood. Thanks, Tom.

Our next question comes from Matthew Blair of Tudor, Pickering, Holt. Your line is open.

Hey, good morning everyone. 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 a Q2? But you say, Tom, we thought we'd be up around 60 days.

We're going up to about the second quarter. It's Thomas O'Connor. In the second quarter will be by our gravitating back up into about a 65 KBD to 75 KBD. And in the first quarter 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 waned all throughout the quarter.

Got it. And then your overall throughput in Q1 was higher than your production levels that you're refineries, which it's 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 will 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 intermediate that ultimately we didn't want to sell at a massive discount that will be reprocessed and convert it to clean products as refineries come back online.

Got it, thank you.

Our next question comes from Jason Gabelman of Cowen.

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

Yes. What I would say is we've got 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 as 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. 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 of repayable debt kind of moves up and down depending on hydrocarbon prices, but ultimately we've gotten the vast bulk of that down to zero. And so from our perspective, it's continued to improve the balance sheet.

Got it. Thanks. And I could just ask a follow-up, I appreciate your comments about your outlook on kind of a heavy and medium shower 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 multi-year low levels in terms of imports? Thanks.

It today remains at the multi-year low levels of imports. We'll see what happens. I think the Saudis want to make sure that when the - I think it is tomorrow, or is it today, tomorrow that the sinkage go in place. They want to make sure that in fact that that happens and there's no surprises on this, but right now obviously they are 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.

Thanks for the time.

Our next question comes from Neil Mehta of Goldman Sachs.

Hey. Good morning, Tom. 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 two commodities. Coke, if you are making a lot of coke and we are coping or refining system as the price of crude goes from 50 to 80, you are margin on coke goes from 0 to 5 to 0 to 5. So you actually - you lose another $30 what you're selling before, you lose another $30. So there's clearly an impact in a rising market on capture rate from coke. The second area that is somewhat inelastic that doesn't move as quickly with the market is the light ends, particularly propanes, butanes. And so we'll see a widening of the margin loss versus crude on coke and propanes. And you just take a look at the yield that we have of those two commodities and you can calculate it would be. That being said, markets are efficient. Usually they are efficient unless - artificially influence as they are today. But what happens is as the price of crude goes up and those differentials, why now it on those coke products, the light heavy spread is correct. In other words, if you're running 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 where we will expect to see particularly when IMO hits.

To that point, the $75 current range that crude difference 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 production and incentivize production. So we are actually sort of like where the crude prices now.

Okay, that's great. And then the follow-up is just on California. A lot of noise, a 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 types of constraints being imposed. California license do be different and that is actually worked to our advantage, but we don't see that as a real risk.

Okay. Thanks, Tom. Appreciate it.

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 and hopefully we'll have a better story to read 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.