Good day, everyone, and welcome to the PBF Energy First Quarter 2018 Earnings Conference Call and Webcast. At this time, all participants have been placed in a listen-only mode, and the floor will be opened for your questions following management's prepared remarks. Please note, today's call may be recorded. It is now my pleasure to turn the conference over to Colin Murray of Investor Relations. Sir, you may begin.

Thank you, Erica. 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 financial and operating information with throughput guidance is available on our website. Before getting started, I'd like to direct your attention to the Safe Harbor statement contained in today's press release. In summary, it outlines that statements contained in the press release and on this call, which express the company's or management's expectations or predictions of the future, are forward-looking statements intended to be covered by the Safe Harbor provisions under federal securities laws. There are many factors that could cause actual results to differ from our expectations, including those we described in our filings with the SEC. Consistent with our prior quarters, we will discuss our quarterly results excluding a non-cash lower-of-cost-or-market or LCM after-tax gain of approximately $64.5 million. As noted in our press release, we will be using certain non-GAAP measures while describing PBF's operating performance and financial results. For reconciliations of non-GAAP measures to the appropriate GAAP figure, please refer to the supplemental tables provided in today's press release. I will now turn the call over to Tom Nimbley.

Thank you, Colin. Good morning, everyone, and thank you for joining our call today. With the first quarter we reported adjusted EBITDA of approximately $100 million which is broadly in line with our expectations given the market conditions early in the quarter and our extensive turnaround activity. We completed turnarounds in three of our four operating regions with the bulk of the downtime occurring in the latter half of the quarter. I would like to congratulate all of our employees on the execution of our turnarounds. Another item I would like to highlight was driven by a decision taken by our board and supported by management to reward all of our employees, both represented and non-represented, with an increase in their incentive compensation. This increase was in large part made possible by the benefits of the Tax Cuts and Jobs Act of 2017, which lowered our corporate tax rate and allowed us to pay us on this benefit to our employees. As a result, our G&A expense was higher in the first quarter than our original guidance. Looking ahead, we see a number of items that are lining up very nicely for the refining sector. While there have been no permanent solutions, discussions on waste to fix the RFS and small refinery waivers granted by the EPA have had the effect of lower RINs prices and thereby reducing a significant headwind for our business. Market fundamentals appear to be very favorable as we head into the summer driving season. Product inventories, especially distillates, are trending down with inventory days to cover the distillates near five-year lows. On the crude side, the market continues to be well supplied and we are seeing the Brent TI and light-heavy differentials move favorably. Looking further ahead, we believe our refining system is well prepared for the upcoming marine diesel fuel standard shift with IMO 2020. As we said on our last call, PBF has more coking capacity than all but one independent refiner, and we are exploring additional projects across our refining system that could potentially increase this advantage. Our strategy in this environment as always is to put our assets in a position to succeed and capitalize on strong market fundamentals. We do this by running our assets safely and reliably and by making selective organic investments in high return projects that incrementally improve our crude source and optionality and our yield of high value products. If we execute this strategy, our assets will be profitable and our employees and shareholders will benefit. I will now turn the call over to Matt to run through our operational highlights.

Thanks, Tom. And as Tom mentioned just a moment ago, the story of the first quarter revolves around the heavy turnaround work that was completed across the company. During the quarter, we completed approximately 70% of the planned major unit downtime for the year. Chalmette, Toledo and Del City, each completed major turnarounds all on budget. Clearly, our results were impacted by the heavy workload but we're more than pleased that we now have a clear runway for the second and third quarters with the only turnaround work remaining for the year scheduled for Q4 with our East Coast assets. Total throughput for our refining system during the first quarter was approximately 800,000 barrels per day, which was in line with the low end of our guidance, and was driven by weaker market conditions in the first half of the quarter and the heavy workload during the second half of the quarter. In Chalmette, we completed an extensive turnaround on the refineries, FCC and alkylation plants. With the $100 million, 42-day turnaround was completed a couple of days early and slightly under budget. We continue to see the benefits of the newly constructed tank at Chalmette. It allowed us to export on average 45,000 barrels a day of clean products and reduce our demerge costs. Our exports were higher in January and February but lower in March as a result of the maintenance activity. Chalmette's first quarter results were clearly impacted by the major FCC turnaround as well as somewhat extraordinary weather that hit Louisiana in January. Chalmette has yet to fully capitalize on the reformer project put in place last year. With some maintenance work coming to an end now, the benefits of this project still lie in front of us. The underlying commercial fundamentals of the project are…

Thanks, Matt. As a reminder, our comments on the first quarter results will exclude the aforementioned non-cash LCM item. For the first quarter, PBF reported income from operations of approximately $8 million and adjusted fully converted net loss of $33.4 million or $0.29 per share on a fully exchanged fully diluted basis. Our EBITDA comparable to consensus estimates was approximately $94.3 million, which includes approximately $5 million of non-cash stock-based compensation expense. For the quarter, G&A expenses were $62.8 million, depreciation and amortization expense was $86 million, and interest expense was approximately $43.2 million. PBF's effective tax rate for the quarter was approximately 27% which is reflective of our new lower corporate tax structure. Our RIN expense for the first quarter totaled $43.9 million. This is a favorable decline compared to the last quarter and is a direct result of lower RINs prices combined with lower volume obligations due to our heavy turnaround activity. While still a burden at the current rate, we could see full year RIN expenses in the $200 million range or $100 million less than our 2017 RIN expense. Total consolidated CapEx for the quarter was approximately $93.3 million, which includes $89.3 million for refining and corporate CapEx and approximately $4 million incurred by PBF Logistics. With respect to our balance sheet, we ended the quarter with liquidity of approximately $1.4 billion, and our consolidated net debt to cap was 39%. As mentioned in our press release this morning, we closed on our new revolving credit facility yesterday. This is an important component of our capital structure, and the amended terms provide incremental flexibility and extend the maturity of the facility to 2023. Final commitments were strong and resulted in an upsizing of the facility to $3.4 billion. We'd like to thank the 28 participating institutions for their support and commitment to PBF. Lastly, we are pleased to announce that our board has approved a quarterly dividend of $0.30 per share. Also of note today, PBF Logistics announced its 14th consecutive quarterly distribution increase. Operator, we've completed our opening remarks and we'd be pleased to take any questions.

Thank you. In a moment, we will open the call for questions. We'll go first to Roger Read from Wells Fargo. Please go ahead.

Yeah. Thank you. Good morning.

Good morning.

Could we talk about – you mentioned on the opening there the cost reductions in California. But generally speaking, we've been seeing cost reductions fairly consistently across the ops. Can you kind of walk us through how you've been doing that, the sustainability of it, and then what you would expect from here maybe risks that increase back up for things we – maybe you can foresee, and you've had benefits from, or whether this is a continuous process and we should think about trimming as we go out in the next couple of years?

Roger, this is Tom. I'm going to just speak to Torrance and then turn it over to Matt who will kind of give you his views for not only Torrance but the rest of the system. The particular progress in Torrance – we're all very extremely proud of the people of Torrance because they took the bit in their mouth, we said we had much work to do, that to a certain extent, the problem was us. We obviously spent a lot of money and invested in that turnaround, and of course, that has allowed us to have the equipment in good shape. But the folks have really embraced the human investment and the procedural investment, and the systems investment that we put into that plant, and that has resulted in these improvements and reductions. And I do believe there is yet to come on that. Matt, what would you add?

Just, Roger, that consistent throughput helps OpEx dramatically and we intend to maintain that. If you isolate the refinery, we're well below $6 a barrel and if you want to think about how we compare to other competitors in the West Coast, as you know – I think you have to look at simply the fence line, which is just a bit over $6 a barrel. But to answer your question directly, no, we do not see that escalating or moving up. We've gone to where we think we can get. Hopefully, maybe we can prove it better. But no, we are where we are and we intend to stay there.

Okay. Thanks. And then I guess the next question since we had a pretty big announcement beginning of this week. How does the asset acquisition market look? I mean we've been in or I'll say I've at least been anticipating something else from the West Coast as opposed the world's your oyster on that front. But how do things look on bid ask prices? Are there assets that are actively on the market and do you think you can still do things that are reasonable return here?

Let me first say I was going to say – I'm not sure what you're referring to about the announcement earlier this week, but let me first say congratulations and, in fact, I did e-mail both Gary Heminger and Greg Goff. I think that's a very good deal for the shareholders of both companies, clearly a very good deal immediately for the shareholders of Andeavor, and it is in many ways. Potentially a transformative merger in the industry and probably, well, as usually happens results and other opportunities shown themselves up. On the individual asset basis, so you've heard me say before, I think IMO has probably put a little bit of a complication in terms of the analytical process on the bid ask. You get to tend in these situations that people who have refineries look at this as an opportunity, perhaps the evaluation will go up because of IMO. And so they may want a bigger price, then the buyer has to look at is IMO a three-year transitory thing or do you think it's longer than that and if it's the former, then you're not going to elevate your price ridiculously to get it. That being said, I absolutely believe this is a cyclical thing. Refineries will come back on the market, it may take a bit because of IMO. And candidly, what Marathon and Andeavor did has got to have a lot of people in corporate board room sitting around saying okay, including us, what do we have to do to, the game is changing a little bit, and so we're going to be spending a fair amount of time doing that.

Okay, great. Thank you.

Thank you. We'll go next to the line of Blake Fernandez from Scotia Howard Weil. Please go ahead. Blake Fernandez - Scotia Capital (USA), Inc.: Hey, guys. Good morning. I guess, Tom, just on that last point, do you think that the larger competitor that you now have, does that necessarily change the landscape? I mean, when you talked about boards having to kind of reassess things, I mean, that to me doesn't necessarily change the competitive landscape at year-end, but maybe I'm wrong on that.

No, I don't think it does. And I will say that was a very big deal, okay. The reality is those two companies are probably certainly off the board for a while, buying a lot of things perhaps. But there's no real change in my view on the opportunities that exist in the industry. I do believe they're going to be there, they're going to be material. And I do say this, and I say it all the time, one of the corollary impacts of IMO is it's going to force some companies who perhaps are not in as good position to deal with the issue early and perhaps do it in a way that is going to spawn some activity, M&A activity. I don't have anything specific right now, but if you have a system that has the potential to have a stranded stream, a high sulfur resid that can't go into 3.5% fuel oil, you have some choices to make. And do you try to handle that with acquisition? Do you try to handle that with commercial deals? So I actually think you're going to see more activity in the commercial/M&A area perhaps, not necessarily on the scale of what we saw earlier this week, but some of that will happen as well. Blake Fernandez - Scotia Capital (USA), Inc.: Okay. Thanks. And then, second question is, Matt made the comments on exports, 45,000 barrels a day. I was just hoping you guys could maybe elaborate a little bit as far as do you have any breakdown of what gasoline distillate was, where it's going and then remind us of what the actual capacity potential is there? Thanks.

Yeah, Blake, I don't know that we can get into specific commercial responses in terms of breaking down gasoline versus distillate, but I would tell you we continue to invest in export capability and we see our capabilities increasing. We just did a deal in Toledo where we expect another 5,000 barrels a day or 10,000 barrels a day of exports. It's early in our life cycle on the export gain, but we're investing where we can and we look to grow from where we are. Blake Fernandez - Scotia Capital (USA), Inc.: Okay. Thank you, Matt.

Our next question comes from Phil Gresh from JPMorgan. Please go ahead.

Yes. Hi, good morning. A couple of questions here. One is just on the capital spending. Given the comment that the turnarounds are about 70% of the years' worth of turnarounds, looks like the CapEx in 1Q is actually reasonably low. I think relative to your full year guidance, Erik, I didn't hear you give any new guidance for the full year. Just any thoughts on that comment on just your overall spending outlook. And if I could tie in anything related to IMO 2020 potentially that you'd be thinking about given your prepared remarks.

Sure, Phil. From a financial statement standpoint, I think we're still comfortable with our, call it, circa $550 million in total CapEx for the year. We did have just shy of $100 million of consolidated CapEx in Q1. But ultimately this is accounting. So you're going to have a certain portion that shows up as CapEx and we've probably got another $130 million worth of accruals on the balance sheet that will swing back through during the course of the second quarter, convert into CapEx and ultimately cash.

Yeah, I would just make one comment. My comment regard to the 70%. That's not going to the accounting finance keeping. It's going to the disruption to our refinery on major unit downtimes. So all that work is complete and so there will be other capital spending, pre-spending at Torrance towards the end of the year, but that won't impact our operations. So my 70% is really going to, if you want to call it, operational disruptions to our system.

Let me talk about IMO, a potential addition investment. And I put this in the category. It's kind of three buckets that we're looking at. One is we have a coker in Chalmette that the previous ownership, the joint venture shutdown that coker as you're well aware, along with a number of other units, some of which we've restarted. We believe that will be likely a very good economic project given even if it's a short-term, three-year, IMO quote impact. The clean-dirty spreads that are being projected for 2020 $50 a barrel by some analysts, that project would pay out very quickly. So we are spending money right now to get a better estimate on what it would take. The unit has been down. It's been mothballed it's been projected. The second one is in Delaware we're looking at potentially revising the hydrogen plant project, but that would be done basically with a third party building the hydrogen plant we would lease it and then we would have notionally $30 million of offsite impact. And then we have some logistics things that we're going to spend some money on, because logistics will be an issue in IMO. How do you move things in and out? The feedstock is likely going to change. That being said, what we're doing here is pressing the advantage that we have today. We can literally have IMO go into place tomorrow and we don't have to do a thing. So what I've just talked about is increment to that. And I think we're just pressing our bet on it if we do these projects.

Sure. Okay. And do you have any ballpark on what it might cost to do the coker? Or is it just too early?

It's too early, but I will tell you we've earmarked about $25 million this year to study all of the options, recall the options that we've got. It's a simple little project in Torrance that we're doing to try to get – I think it would debottleneck a pump or something out. They're on the hydrocracker. That will give us a little bit of incremental capacity on the hydrocracker. So those are more well-defined, but about $25 million and three months from now we should have a quite bit better handle on what it might be the cost of the coker.

Okay. Second question is just be on the topic of Torrance, and I know there is this committee meeting out there this weekend around hydrofluoric acid and there's a lot of back and forth. I think your Refinery Manager was there presenting and he made a comment that moving to sulfuric acid, I think he said, will put entire company at risk, which I presume he meant financially. But just curious would this be an accurate representation of your view of the situation? And secondarily, it did sound like from the press release afterwards that the conclusion of the meeting was to try and work towards a Tier 3 solution. Just your curious your latest thoughts on all of this.

Well, I think we go back to the beginning. Over half of the alkylation units in the United States use HF or MHF. The safety record for that particular technology has been very good. The only alternative technology is sulfuric acid, which has some risk of its own and has to be mitigated. We believe the Torrance HF/MHF unit is a state-of-the-art and an extremely safe unit. And we absolutely believe a change in the investment is not warranted. That being said, we are going to continue to work with all of the stakeholders in California on this issue and look for ways. We are going to add some Tier 1, Tier 2, as you're aware, Phil, that the – definitely you're going to go and look for other mitigation steps that we can potentially put in place that would further buttress the safety of the facility. But we are very optimistic and we were pleased with the outcome of the meeting. And we are optimistic that we will get a solution here.

Okay. Last question just on California. The gasoline inventories are still looking a bit on the high side in the weekly data that comes out. I'm curious for your view on the fundamentals in the California gasoline market as we go into the summer and any turnarounds or anything like that do you think will help or not? And how demand looks?

Overall demand on gasoline, it's basically flat or so year-to-year. Of course, there are some headwinds. I filled up my car on the way into work this morning and it was at $3.55 a gallon here in the state of New Jersey for Supreme for 93. But we're seeing still good demand. California demand is – the inventory is a little high, but not really out of the ordinary. Californians love to drive. So we think we're going to be fine. I think really the story is if you look globally you're going to have a threshold point here in probably the third quarter where global demand for products is going to cross 100 million barrels a day. So we're structurally bullish on product side and we're structurally bullish on the crude side. Hopefully that doesn't mean that we're missing something.

Okay. Thank you.

Our next question comes from Brad Heffern from RBC Capital Markets. Please go ahead.

Hey, good morning, everyone.

Good morning.

Question on new PBF projects that you've announced. You quote that $18 million EBITDA number. Presumably that's fees coming from PBF. I'm curious if you have any sort of scale of what the benefit to PBF is from those projects?

Yeah, in regards to the $18 million, part of it is fees from PBF, new contracts, part of it is new third-party business. We acquired a new terminal with third party customers in Tennessee. But importantly, it is not a value exchange between PBF and PBFX. PBF's business and PBF's profitability are increased as a result of the projects. It's relatively tame. So I don't know if it's worth breaking out specific numbers on the project. But this is not a move of a cost center to a profit center. This is new business that PBF Energy is doing and PBFX is the logistics arm to provide the services, but it is definitively a win-win for both companies.

Okay. Thanks for that color. And then, I guess on the RIN's front, it seems like the EPA is taking the tact of sort of managing things through these smaller finding exemptions. I guess any thoughts on a broader regulatory solution. It seems like a lot of the refineries are sort of getting behind this higher octane nation-wide gasoline sort of solution in the long-term. Any thoughts around that?

I'm going to take the discussions around higher octane, and then Matt who has been fighting the fight on the forefront in will deal with the overall status. Obviously octane is the centerpiece here. The main driver is the automobile companies need to get a solution for CAFÉ standards even though the EPA is indicating they're going to pull it back a bit. The reality is Detroit and other automobile makers around the world are trying to figure out how to meet those standards. They've done a lot of things, but what they really want to see is increased use of high compression engines to use high compression engines and you might get a couple of miles a gallon out of that. You've got to have higher octane gasoline. So it looks like there could be a solution there where you go to some type of a new fuel replacing 87 octane unleaded regular with a 95 octane. It's early in the game though. There's a lot of analysis that has to be done as to what the corollary impacts are of putting that fuel in place, but that could well be and it will be discussed as part of a longer term legislative solution. John Cornyn's bill and the bills that are being pushed out of Congress and the House are certainly entertaining some type of an octane standard, whether or not it materializes or not, we won't know for sure, but I'll repeat. There's a lot of things that have to be worked through to make sure that you understand what happens with all of the components that are in today's gasoline and what would happen if we went to a 95 fuel. Matt?

Yeah, and just off of Tom's comments, the way we look at longer term solution is, yeah, there's probably a month's worth of Sundays that a lot of oxygen can go in that. We're certainly more concerned with the here and now. I think it's becoming more and more common knowledge that the RIN's game and the RFS program is nothing but winners and losers. There was a rally as recently as last week in Washington with Senator Cruz. Senator Cruz deserves a lot of credit for raising the game, raising the temperature and raising the awareness around this broken program. If you look at what's happened over the last couple of months, there's four things that I think – really the reason that RINs are now at $0.30 to $0.35, they all are directionally helpful. First, obviously, is PES filed bankruptcy on the back of the RFS program, and the government came in and essentially agreed with them. And recognized upfront that the RFS program was one of the key drivers in putting the company into bankruptcy and actually forgave them for some historical RINs. The forgiveness, obviously, helps with the supply and demand, but I think much more important is the fact that the government is cognizantly saying we're part of the problem. So that's like number one. Obviously, the waiver program that's been sort of uncovered is helpful. It's incredibly helpful if you're getting a waiver. Unfortunately, PBF doesn't have any refineries below 75,000 barrels a day, but it's absolutely helpful to the entire program, because when you talk about 30-some small refiners, it's not an insignificant portion of the RVO. And so you're reducing the scarcity of this false commodity called a RIN, which is directionally helpful to prices. The third piece is Pruitt and EPA…

Okay. Appreciate the detailed answer. Thanks everyone.

Thank you. Our next question comes from Manav Gupta with Credit Suisse. Please go ahead. Manav Gupta - Credit Suisse Securities (USA) LLC: Hi, guys. Following up a little bit on Phil Gresh's question from a different PADD. PADD 1 distillate inventory is down 40% year-over-year and PADD 1 distillate inventory is down 22% on a five-year average. I'm just trying to understand what's going on in the supply demand dynamics over there, if you could shed some light.

Well, I think basically overall distillate demand is high. The fact is, yeah, PADD 1 inventories are disproportionately lower than the other PADDs. We certainly can say that while we've seen normal drivers push distillate demand i.e. high GDP around the world in the United States increased drilling, in the Northeast, you do get an impact on distillate from weather. And for those of you who live in the Northeast, we had spring for two days. So we kept seeing continued cooler temperatures and my guess, we saw a little bit of the demand push there as well. But overall even though PADD 1 looks disproportionately low, the story here is that distillate inventories across the board actually remain in very good shape and as long as the economies of the world continue to do what they're doing that portends well for this program. Manav Gupta - Credit Suisse Securities (USA) LLC: And the second question is more on the secondary product cracks, which tend to get a squeeze little bit in rising crude price environment. I'm just trying to understand what kind of headwind was that for you in 1Q or even 4Q, last two quarters?

Well, we certainly see and you're spot on. Although, it's a tale of two stories, you can actually get – when you look and say, for example, products like naphtha to the extent that you long naphtha and you can't reform it and you have to sell them into the marketplace, that could become an opportunity for somebody who buys naphtha and then turns it into octane. But on the typical low-value products of coke, sulfur, which – inelastic where price of crude goes up $10, the price of coke stays the same. If it goes down, then obviously you're going to see those type of impacts. And you have to look at it refinery by refinery to see how much – Toledo, for example, is well insulated from that because they have such a high percentage of light product yield, whereas you have coking refineries like Delaware, particularly and Chalmette and Torrance that produce more coke, more sulfur. They will be disproportionately impacted. But it's just part of the business cycle and it'll go up and go down. Manav Gupta - Credit Suisse Securities (USA) LLC: Thank you so much, guys.

Our next question comes from Paul Cheng with Barclays. Please go ahead.

Hey, guys. Good morning.

Hey, Paul.

Tom, I suspect and I think that you guys don't have any pipeline commitment to ship from Canada down to the Gulf or from the Permian down to the Gulf for your Chalmette refinery. So in order to get any of the WCS and the Permian crude, the only option if possible would be the well. In the East Coast, you already have the terminal. So what is the today's well cost you want to do from Canada and also from Permian going into the East Coast? And whether that is actually the capacities available for you to ship?

Yeah, in regards to the capacities, in the first quarter we railed somewhere between 50,000 barrels a day, 55,000 barrels a day of crude into the East Coast and that was predominantly Canadian heavy, just under 50,000 barrels a day of Canadian heavy and I expect that will increase going forward into the second and third quarter and beyond. I think the market is structurally set up, but there's some seasonal aspects to the Canadian crude business where it strengthens on a differential basis in the summer months and gets weaker in the winter months. And we will sit there with a catcher's mitt. We have a preeminent unloading capacity and we're going to look to exploit to the best of our ability.

Yeah.

Well, I would add just it's early in the game, but obviously with the – on the Permian side, we were just starting to look to see whether or not there's an opportunity for us given distressed nature of those crudes. So right now we don't have any definitive plans or anything late in concrete, but it is something given the spreads that we're seeing that we want to take a look at.

And just on the cost side, nothing has changed. I mean, the PBF has differentiated itself from maybe some other players and that we were early in the rail business and we stayed there. We've got lot of partners along the – counterparties during the supply chain. So our costs haven't changed in material way from what we've historically talked about.

So are we still talking about, say, $17 to $18 from Alberta to the East Coast?

Yeah.

And if you do ship from Permian to the East Coast, any idea that how much it may cost?

It's way too early in the game, Paul. Literally we just started this as an initiative in the last week and a half. So we've got a lot of work to do.

Actually, do they have terminal availability in Permian because I heard that a lot of those used up for the sand shipment even though you have some capacity but may not be available for shipping oil?

It's fair to say, while we're having this conversation, there's some hard-working people in West Texas increasing capacity, but there's different railroads involved, coming from that and obviously coming from the hinterlands of Canada. But we're in the market in a big way, and to the extent we can exploit crudes there to our other refineries, we'll certainly look to do it.

And just curious that if you gentlemen have heard in terms of the IMO 2020, we have heard there's a private company is proposing, there's an option or there's a way they believe they could directly convert the high sulfur (41:22) with a very efficient capital cost. And don't know if you guys have looked at that option and what you think about the technology.

I've heard the same things and I've seen actually some publications on it that are trying to raise money, but I wouldn't go – I would say it's not beyond that at least to my knowledge. We're not pursuing that as we said earlier. We don't need to worry about converting anything. We've got the cokers to deal with the problem. So we don't produce any high sulfur material today of any real magnitude. Technology is a great thing. People are going to pursue these things, but the ones that I've seen and ones I've looked at, I haven't seen anything that's anywhere near to being commercially viable.

And I would also just make a comment. As you track those opportunities, the clock is ticking also. So, nothing can be done at a snap of a finger, and I'm sure the markets will attract different opportunities, but 2020 is going to be on us in a pretty short period of time.

Can I just sneak in one final question?

Go ahead.

Do you guys have an estimate about what is the opportunity cost loss in the first quarter by region? And also, that with the Chalmette coker that you're talking about on that may start how big is that? Thank you.

The coker that Tom referred to is about 10,000 to 12,000 barrels a day coker and now, we're not publishing a back cast of what our system would have done had we not have the turnaround.

Thank you.

Sorry. Okay. Go ahead.

Thank you. We'll go next to Neil Mehta from Goldman Sachs. Neil Mehta - Goldman Sachs & Co. LLC: Hey. Good morning, guys.

Good morning, Neil.

Good morning. Neil Mehta - Goldman Sachs & Co. LLC: Tom, you'd outlined a picture of 2018 with a relatively strong distillate picture more so than gasoline. Can you just talk about the ability of the system to switch to distillate and run max? How much incremental headroom do you have as a fleet?

Typically, you can just look at this in broad terms. It moves around a little bit by refinery and dependent upon what units. But you can shift about 10% to 12% of the volume between gasoline and distillate across the board. And so, if indeed we see continued strength in distillate, right now, I would guess that across the system. If you say we're 800,000 barrels a day or 880,000 a day and we've got somewhere between 85% and 90% clean product yield, if you do those numbers, and so you're sitting here at 750,000 barrels, take some jet out, the rest of it is gasoline and diesel. And so maybe there's 60,000 barrels, 70,000 barrels a day that can go into diesel or go into gasoline. And that will all be dependent upon the economics of those two streams. There's still some stuff that we can do to push more barrels into diesel. I can't tell you right now where we are in that spectrum of 0 to 80 if you will. Neil Mehta - Goldman Sachs & Co. LLC: Yeah. I appreciate that. The other question is more of a big picture capital allocation question which is you have adopted a different strategy than some of your peers, right? So, peers have taken a keep capital low, not do a ton in acquisitions, return capital to shareholder strategy. PBF has taken more of a growth orientation in finding assets, turning them around and building the business that way. Do you see yourself or is it a priority for the company to evolve into a capital return story at some point in the future where dividend growth and share buybacks are prioritized? So, I don't know if you agree with that characterization, it's not a value judgment, it's a different orientation than some peers. I just want to understand how you guys are thinking about that?

Yeah. I think it's a good point, it's a good question. I'll answer it. Look when we were a small company and you're just starting out, if you're going to be in this business, you obviously have to have a growth plan and an acquisition plan. And we were well disciplined in our growth plan and acquisition plan. We had opportunities to buy assets that, we believe, were unloved by their previous owner that had not been invested in or had some upside in investment and an upside to us as a company that we could acquire at a reasonable price. And if we can do that, we'll do that all day long. But we've bought five refineries, and it isn't clear to me that there's five more refineries or even three refineries out there that you can get under that same model right now. The bid ask has widened out quite a bit as I mentioned earlier. But we still will be very interested in that. But I will also say, Neil, that we believe, and I believe once you acquire your refineries and you do the things necessary to fix them up, capital is not necessarily the friend of the refiner. And you talk about it because of return on capital employed and how you use your cash flow and the benefits to giving it back to the shareholder. So we're not interested in big organic projects inside the fence line. We could build a hydrocracker for $1 billion or we could buy two refineries for $1 billion, that's what we did. So we're going to be pretty prudent on capital. And as cash flow comes out, and I am, and I think Erik is as well, very hopeful that we're going to have a runway here for a couple of years that will allow us to produce significant amounts of cash. Then we will look at buybacks. We already have bought shares back in our history, but then when we're getting into the acquisitive mode, we shut that down and we go buy something. We will look at both dividends. Our share appreciation has gotten us back to where – we were paying $1.20 a share when we were a very low priced stock. It's a little bit different now. So, we'll look at that, but it'll be after the money flows.

...Matt touched on this Neil, but ultimately, it's been less than a year since we've had the major projects out in Torrance. We still have not had a continued, call it, multiple quarter period of time where we've had all five operating assets really completely lined out and running the way that they should. Q2 and Q3 are really shaping up to kind of put us in a position where as long as the market cooperates, we should be in a pretty good position to start spitting out some cash flow here. Neil Mehta - Goldman Sachs & Co. LLC: That's great, guys. Thanks for the time.

Our next question will come from Prashant Rao from Citigroup. Please go ahead.

Good morning. Thanks for taking my questions. First question I wanted to ask, you've just come out of a heavy turnaround 1Q and you've kept costs low – you came in under budget, which is impressive. I wanted to talk about the operational side of the turnarounds. As you're going through these, what are some of the learnings in terms of operations during turnarounds? Are there things that you can take as lessons going forward, particularly in the back half of this year or even in future years. This is sort of a broader kind of question. But as you sort of fine-tune the machine here, is there things that we should be thinking about in terms of operating those refineries through turnarounds?

Yeah. I think it's very simple. They had a refinery in Herman Seedorf. These establish what we call the best practices network, speak for itself what that is. But when you have five refineries and basically all five of those refineries have different cultures and you go through things like turnarounds, they all tend to do it a little bit different way and some of them do certain things better than others and some of them do things not as good. So now, as we've been going through the major activities, major projects, and major turnarounds at the sites, we absolutely ship people from one site – the other sites in there to assist either in planning those projects or obviously in the execution of them and then taking learnings from that back to the best practices group that oversees turnarounds. So there you can get into the weeds on this, but just in terms of how quickly you can clear a unit and get it ready to be turned over to mechanical there are opportunities that we see. So it is a broad question. It really applies to a lot of operational aspects of the business, but that's something that we're working pretty diligently on.

In regards to California and Chalmette, the two nearest refineries that we've acquired, obviously massive investment in California, but the investment, generally in turnarounds you don't get returns, but some of those turnarounds has going on longer than we would have otherwise done it. And we actually got benefits from the turnarounds where our new base case was better than whether refinery was operating prior to the turnaround. Obviously, Del City, Toledo and Paulsboro has been in our system for a better part of eight years. And so we've been through full turnaround cycles there. But on every turnaround you learn something new, and we've got experienced group at every one of our refineries. And like I said what we've demonstrated I think in the first quarter, it wasn't – not we, the teams at each of those refineries demonstrated was absolute expertise and a great job well done.

Good. Thanks. That's helpful. I wanted to ask a broader picture PADD 1 market question, the bi-directional service on the Laurel pipeline and the sort of impact on the East Coast market, I know you've talked about this before, but just sort of wanted to get an update there given that we had some – we had that judgment, the denial earlier in the quarter, and sort of Buckeye proceeding on the bidirectional there, I wanted to see sort of if you have any updated thoughts on PADD 1 and how this plays out.

Yes. I think it's a distinction without merit in regards to they lost on the one directional, so now they are now going bidirectional, our view hasn't changed. It's a bad deal for Pittsburgh, and it's sort of counter logical in that PADD 2 is product short. And so we see it, we'll continue to watch it, we don't have a vested interest being in Pennsylvania and it's clearly a Pennsylvania issue. But we'll continue to monitor it, but we don't view bi-directional as a great answer certainly for the people of Pennsylvania.

Okay. Great. Thanks. And then just one very quick follow up and I'll turn it over. From a credit facility raise you mentioned some working capital needs. Just wanted to get any detail there in terms of putting back towards turnarounds through the back half of this year or anything specific we should we be thinking about when we're remodelling there in terms of the uses of that raised credit facility?

No. I think really $3.4 billion is really the result of having very strong commitments. we were oversubscribed on the facility. Our average use is going to continue where it is, so about $350 million of outstanding pre payable debt. We probably use an incremental $500 million of LCEs under that facility. So it's definitely oversized for the current flat price environment that we see today. For us it's simply extending the maturity. It was going to be coming due, and ultimately it was time to extend another five years. So for us it gives us the flexibility to grow as a result of the business growing potentially, and more importantly, to ensure against any kind of spike in hydrocarbon prices.

Got it. Okay. Thank you so much for the time. I appreciate it.

Thank you. And our next question will come from Doug Leggate from Bank of America.

Hi, guys. This is Kalei Akamine on for Doug. Thanks for taking my questions. First one, just on RINs prices, so these have obviously come in during the quarter as a result of the series of headlines from the EPA this year. Are you starting to see this translate into the crack? And can you give an updated estimate of what full year cost could be?

Yeah. The same is in the crack. And quite honestly, the analysis gets so basic that it's ludicrous. The whole program's broken. And the idea that anything is static in the market is ludicrous. RINs are transitory in the way they appear. And sometimes it affects the crack and sometime it hasn't. We've had $0.30 RINs for that part of the month and cracks have moved dramatically in certain areas. So look, getting into what percentage in the crack I think is a fool's errand. A significant portion is either not in the crack all the time or some of the time. So we benefit from lower RIN prices, and we'll continue to push forward for it.

And I think, Kalei, for the full year, based on at least what we see in terms of current pricing and knowing what we think we're going to make from now through the end of December, so we know directionally where our volume obligation will lie, we could be in the $200 million range for the year, which again is $100 million less than we experienced in 2017.

Great. Thanks for that. My second question is on Canadian heavy differentials. So Delaware obviously has some ability to run heavy Canadian and by rail. What's the update there? How much are you running? And do you think that this will have an impact on the caps your hearing in Q2?

Yeah. As I said earlier, we ran just under 50,000 barrels, delivered just under 50,000 barrels in the first quarter, and we see that number going up in the second and third quarter. I would expect us to be north of 65,000 barrels a day of rail crude into the East Coast. And like I said, we are beholding to know crude. And so we'll continue to access the most economic crudes to our system.

Great. Thanks for the answers, guys.

And we'll go next to Matthew Blair from Tudor, Pickering, Holt. Matthew Blair - Tudor, Pickering, Holt & Co. Securities, Inc.: Hey. Good morning, guys. Thanks for taking my questions here. Just on IMO 2020, so last year PBF ran a crude slate, it was about 34% heavy and 29% medium. I know it's early, but so when IMO kicks in do you foresee that the PBF crude slate changing? Because I could see an argument on both sides, maybe you run a little heavier to capture what would likely be larger discounts on the heavy sour, so maybe you run a little lighter to improve your overall light product yield. Any thoughts on that?

I think it will be a function of what the absolute spreads are at the time. The good news here for us is we have the capability to do both of that. But our base view is, sulfur is going to be a problem. What this is, is a problem with sulfur. You're going from 3 or 2.9 whatever the pull is today, 2.5. So crudes with high sulfur, not necessarily just heavy, but crudes with high sulfur are going to have to widen out. And so we believe that we're going to have continued opportunities on the heavy side. That being said, if there is a situation as I said, we can make the new fuel by running a little bit more lower sulfur crude we have that capability. In other words make a blend of 0.5. The other point I would make on this. It isn't clear to me that crude is going to be – in fact it's absolutely clear to me that crude is not going to be the only alternative. You're going to see a lot of things happen. People who don't have cokers but have streams that use to go into heavy fuel oil, you might wind up actually have an economics that say buy coker feeding, don't run as much crude. It all depends on, if it ever gets down to the alternative dispositions of some of these streams as to the power industry, and you get these type of clean dirty spreads that have been bantered about, it may well be that you're going to wind up buying a stream coker feed as opposed to running crude. But the good news here is, that's what we've focused on when we bought these assets all with Toledo, Toledo is obviously a 100% light, because we have a fair amount of optionality that we can go any one of those directions. Matthew Blair - Tudor, Pickering, Holt & Co. Securities, Inc.: Great. Very helpful. And then just real quick, directionally would you expect 2019 turnaround activity to be less than 2018?

No. Actually I wouldn't say it's – I think it's actually likely going to be the equal or a little bit more. We will have some turnaround activity in Torrance that will add to it. I don't think it's enormously higher, anything like we had, but Matthew do you have anything?

No. I would just say directionally it will be a similar number. We always manage. As Tom talked about earlier, we manage our capital very tightly. We'll manage our system appropriately, but my guess it's too early to give you a specific guidance, but it'll directionally be similar to 2018. Matthew Blair - Tudor, Pickering, Holt & Co. Securities, Inc.: Great. Thank you.

We've follow up from Phil Gresh at JPMorgan.

Yes. Sorry. Thanks for taking two quick follow-ups here. One is, Erik, were there any hedging effects in the first quarter around WCS?

We had an overall consolidated net loss of $13 million, and I'd say roughly half of that related to the $70 million that we highlighted for folks at the end of Q4. So an incremental call it $6.5 million, $7 million loss during the quarter, which again would be offset by the actual price of crude coming into the refinery on that 48,000 barrels a day that Matt mentioned.

Right. Okay. And another follow up for you Erik, just in terms of, you mentioned that the moves you made on the debt side. But I was just curious if there's a specific absolute leverage target gross debt, or net debt that you're thinking about. Obviously, the EBITDA can bounce around quite a bit, and your leverage is looking in better shape as the EBITDA goes up. But just in general, is there a certain threshold that you want to get to that make you more comfortable particularly if something were to come along from an M&A perspective at some stage?

I think we always want to have as competitive the leverage target as possible. What we've told the rating agencies and other fixed income investors is that our long-term target is to always kind of stay within that 40% net debt to cap, pro forma for doing certain transactions. We may pick above that, but the goal is going to always be continue to tick down below. One important point to note though is we do consolidate PBF Logistics on the PBF Energy, Inc. balance sheet. And so we're going to finance the MLP slightly different from a cap structure standpoint than you would the parent company. So I think for the parent company you probably don't want to really tick above 1.5 times to 2 times total debt to EBITDA coverage. But the MLP, we've highlighted for folks who want to stay within kind of the 3 times to 4 times net debt to EBITDA target, and ultimately as that MLP gets bigger you may start to see things shift a bit, but I think where we are today sub-40% is still the target long-term. And I think based on where we see the market going, and to your point about EBITDA picking up, the EBITDA will then translate into incremental cap. So that should really benefit us going forward.

Okay. Thank you.

Thank you. And I would like to turn it back over to our speakers for closing remarks.

This is Tom Nimbley. Thank you very much for joining us on the call. We look forward to talking to you again at the end of the second quarter. Everybody have a good day.

We'd like to thank everybody for their participation on today's conference call. Please feel free to disconnect your line at anytime.