PBF Energy Inc (PBF) 2018 Q1 法說會逐字稿

Good day, everyone, and welcome to the PBF Energy First Quarter 2018 Earnings Conference Call and Webcast. (Operator Instructions) Please note, today's call may be recorded. (Operator Instructions) It is now my pleasure to turn the conference over to Colin Murray of Investor Relations. Sir, you may begin.

Thank you, Erika. 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 describe in our filings with the SEC.

Consistent with our prior quarters, we will discuss our quarterly results, excluding a noncash, 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. For 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 3 of our 4 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 nonrepresented, 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 pass 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 ways 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 (technical difficulty) inventory days to cover the distillates near 5-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 sourcing 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'll now turn the call over to Matt to run through our operational highlights.

Thanks, Tom. 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. It 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 refinery's FCC and alkylation plants. The $100 million, 42-day turnaround was completed a couple 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 demurrage 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 as good and potentially better from when the original investment was approved. We're quite confident the units will perform to our expectations going forward.

In Toledo, we completed turnarounds of the crude unit hydrocracker, the large reformer and aromatics production unit. The work extended past our original target date, but importantly remained on budget. The market environment for the quarter was challenging in the mid-con and our capture rate reflects the impact of our maintenance activity, combined with the relatively weak gasoline markets that were partially offset by strong chemical cracks. On the East Coast, we completed a turnaround of Del City's alkylation complex on time and on budget. East Coast operations are running well.

Last, but certainly, not least, Torrance. Torrance ran very well in the quarter, reliability was excellent, throughput was slightly above guidance and operating expenses were in line with our expectations. Of note on operating expenses, which were reported as just over $7. It's important to note the $7 includes not only the refinery, but the pipeline terminal network as well. The $7 represents a $3 decrease from where we started in 2016. This is in line with our stated target of operating expense reductions.

While we made significant investments in the plant last year, these results are only possible through the tremendous efforts of our team at Torrance. 2018 should be a standout year for Torrance. They are off to a good start and have a clear path ahead with no planned turnarounds for the year.

In regards to the remaining 30% of turnaround work to be completed this year, Paulsboro has scheduled work on its coker and smaller crude unit, which is set to begin at the end of September, but the bulk of the work in October. Del City has a turnaround work scheduled on its reformer set for November.

As Tom mentioned, growing global demand is driving strong clean product markets, especially for distillates, and inventory levels are below 5-year averages. With the bulk of our planned turnarounds complete, our refining system is well positioned to be firing on all cylinders, entering what looks like a very constructive spring and summer season.

With that, I'll turn the call over to Erik on financials.

Thanks, Matt. As a reminder, our comments on the first quarter results will exclude the aforementioned noncash LCM item.

For the first quarter, PBF reported income from operations of approximately $8 million and an 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 noncash 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're 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 would be pleased to take any questions.

(Operator Instructions) We'll go first to Roger Read from Wells Fargo.

Tom, can 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'd expect from here? Maybe risk that it creeps back up for things we maybe 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 into the next couple of years?

Roger, it's 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 the -- not only Torrance, but the rest of the system. The particular progress in Torrance, I'm extremely -- 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 equipment in good shape. But the folks have really embraced the human investment, and the procedural investment, 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 improve it better. But no, we are where we are and we intend to stay there.

Okay. And then, I guess, the next question. Since we had a pretty big announcement at the 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 on the West Coast. I suppose the world's your oyster on that front. But how do things look on bid-ask price? Are there assets that are actively on the market? And do you think you can still do things at a 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 will, as usually happens, result in other opportunities showing 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 things situations that people who have refineries look at this as an opportunity that perhaps their valuation will go up because of IMO, and so they may want a bigger price. Then the buyer has to look at, is IMO 3 a 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. The game is changing a little bit, and so we're going to be spending a fair amount of time doing that.

We'll go next to the line of Blake Fernandez from Scotia Howard Weil.

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 talk about boards having to kind of reassess things. I mean, that to me, doesn't necessarily change the competitive landscape that you're in, but maybe I'm wrong on that.

No, I don't think it does. We -- and I will say, that was a very big deal, okay. The reality is that those 2 companies are probably -- certainly go 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 a 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 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.

Okay. And then the second question is on -- 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 break down of what gasoline distillate was? Where it's going? And then remind us of what the actual capacity potential is there.

Yes. Blake, I don't know that we're going to get into specific commercial responses in terms of breaking down gasoline versus distillate. But I will tell you, we continue to invest in export capability, and we see our capability is increasing. We just did a deal in Toledo where we expect another 5,000 or 10,000 barrels a day of exports. So it's -- we're -- it's early in our life cycle on the export game, but we're investing where we can and we look to grow from where we are.

Our next question comes from Phil Gresh from JPMorgan.

A couple of questions here. One is just on the capital spending. Given the comment that the turnarounds are about 70% of the year's worth of turnarounds, it looked 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, and just your overall spending outlook? And if I could tie in anything related to IMO 2020 potentially that you'd be thinking about in 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. 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.

Yes. I would just make one comment. My comment in 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 downtime. So all that work is complete. And so there'll 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, potential additional investment. And I put this in the category -- there's kind of 3 buckets that we're looking at. One is we have a coker in Chalmette that the previous ownership, the joint venture, shut down 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, 3-year IMO "impact." The clean-dirty spreads that are being projected for 2020 are $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's been down. It's been mothballed, it's been projected.

The second one is, we -- in Delaware, we're looking at potentially revising the hydrogen plant project. But that would be done basically with third-party building the hydrogen plant. We would lease it and then we would have some, notionally $30 million of off-site impact. And then we have some logistics things 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's 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. And we've culled the options that we've got. There's a simple little project out in Torrance that we're doing to try to get, I think it's debottlenecking a pump or something out there 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 into [buddy]. Three months from now, we should have quite a bit better handle on what might be, the cost of the coker.

Okay. Second question would just be on the topic of Torrance. And I know there is this committee meeting out there this weekend around hydrochloric acid and there's a lot of back-and-forth. I think their refinery manager was there presenting and he made a comment that moving to sulfuric acid would put -- I think he said, would put the 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. So, just curious for 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 risks of its own that have 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'll -- we're going to continue to work with all of the stakeholders in California on this issue and look for ways. We're going to add some Tier 1 and Tier 2. As you're aware, Phil, that definitely is 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 that -- 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 there are still looking a bit on the high side in the weekly data that comes out. I'm just 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 that you think will help or not? And how demand looks?

Well, we're really -- overall, demand on gasoline is basically flat or so year-to-year. There are -- 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, or 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 the product side, and we're structurally bullish on the crude side, and hopefully that doesn't mean that we're missing something.

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

Question on the 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?

Yes. In regards to the $18 million, part of it is fees from PBF, the 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 going to increase 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. And I guess, on the RINs front. It seems like the EPA is taking the tack 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 refiners are sort of getting behind this higher octane nationwide 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 Washington, will deal with the overall status. Obviously, octane is the central piece here. The main driver is the automobile companies need to get a solution for CAFE standards, even though they -- the EPA is indicating they're going to pull them 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, and 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?

Yes. Just to follow up on Tom's comments. The way we look at longer-term solution is, yes, there's probably a month's worth of Sundays. 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 RINs 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 awareness around this broken program. If you look at what's happened over the last couple of months, there's 4 things that I think really the reason that RINs are now at $0.30 to $0.35. They all are directionally helpful. The first, obviously, is PES filed bankruptcy on the back of the RFS program and the government came in and essentially agreed with them, and then 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 cognitively saying, we're part of the problem. So that's leg 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 the EPA has been pretty direct on removing the speculators from the program. And I would expect some action on this in the not too distant future, where they either limit nonobligated buyers from participating in the trading of RINs, limit hoarding, which no doubt was going on in a dramatic way over the last couple of years. But simply take out some of the bad actors that were exploiting this false commodity and impacting the obligated parties. And then the fourth piece to the sort of here and now, is the work that Cruz is doing with Toomey, negotiating with the White House on real RIN reform, that adjustments can be made to the program to level the playing field. So we're in complete support of that.

We've worked very closely with the White House, with the EPA, with the Hill, and we're hopeful that the President can make a decision soon that is a win-win for all parties. And I think we may be on the precipice of that. So in regards to RINs, it's a crazy roller coaster ride. But obviously, as we get closer to a world with lower RIN prices, PBF is one of the largest beneficiaries of that. It's hard to describe ourselves as beneficiary of it. It's more accurate to describe us as one of the ones -- the bigger losers when high RIN prices prevail. So we're cautiously optimistic and we continue to work the program.

Our next question comes from Manav Gupta with Crédit Suisse.

Following up a little bit on Phil Gresh's question, but on a different PADD. PADD 1 distillate inventory is down 40% year-over-year and PADD 1 distillate inventory is down 22% on a 5-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, yes, PADD 1 inventories are disproportionately lower than the other PADDs. Let's -- we certainly can say that, while we've see 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 2 days. So we kept seeing continued cooler temperatures and my guess is we saw a little bit of a 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 distillate demand.

And the second question is more on the secondary product cracks, which tend to get squeezed a little bit in a rising fuel price environment. I'm just trying to understand what kind of headwind was that for you in 1Q or even 4Q, last 2 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're 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 are inelastic. Where the 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 of -- Toledo, for example, is well insulated from that because they have such a high percentage of light product yield, where 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 will go up and it'll go down.

Our next question comes from Paul Cheng with Barclays.

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 Permian down in the Gulf or your Chalmette refinery. So in order to get any of the WCS and the Permian crude, you're probably the only option, if possible, would be the rail. In the East Coast, you already have the terminal. So what is the -- today's rail cost if you want to do from Canada, and also from Permian going into the East Coast? And that -- whether that is actually the capacity is available for you to ship?

Yes. In regards to the capacities, we -- in the first quarter, we railed somewhere between 50,000, 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. 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 the preeminent unloading capacity, and we're going to look to exploit to the best of our ability.

Yes. Paul, I would add, just -- it's early in the game, but obviously, with the -- on the Permian side, we're just starting to look to see whether or not there is an opportunity for us given the distressed nature of those crudes. So right now, we don't have any definitive plans or anything laid 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, there -- PBF has differentiated itself from maybe some other players in that we were early in the rail business and we stayed there. We've got lots of partners along the counterparties during the supply chain. So our costs haven't changed in a 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?

Yes.

And if you do ship from Permian to the East Coast, any idea then 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 1.5 weeks. 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 is being used up for the sand shipment and all that. So even though you have some capacity, but it 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 you gentlemen have heard in terms of the IMO 2020, we have heard there's -- a partner company is proposing there's as an option or that there's a way they believe they could directly convert their high-sulfur resid fuel into low-sulfur bunker fuel 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 have heard the same thing 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 need to -- 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 the ones I've looked at, I haven't seen anything that's anywhere near to be commercially viable.

And I would also just make a comment, as you track those opportunities, the clock's ticking also. So nothing is -- can be done at the snap type of a finger. And I'm sure the markets will attract different opportunities, but the -- 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 of what is the opportunity cost loss in the first quarter by region? And also that whether it's just your met coke that you're talking about on that may -- will start, how big is that?

The coker that Tom referred to is about 10,000 to 12,000 barrel a day coker. And no, we didn't -- we're not publishing a back cast of what our system would have done had we not had the terminal.

We'll go next to Neil Mehta from Goldman Sachs.

Tom, you 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 our 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 there at 750,000 barrels, take some jet out, the rest of it's gasoline and diesel. And so maybe there's 60,000, 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 2 streams. There's still some stuff we can do to push more barrels into diesel. I wouldn't -- I can't tell you right now where we are in that spectrum of 0 to 80, if you will.

Yes. I appreciate that. And the other question is more of a big picture capital allocation question. Which is you've adopted a different strategy than some of your peers, right? Some of the peers have taken a keep capital low, not do a ton on acquisitions, return capital to shareholder strategy. PBF has taken more of a growth orientation, and finding assets, turning them around and building the business that way. Do you see yourself, or is it is 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 just -- it's a different orientation than some peers. I just want to understand how you guys are thinking about that.

Yes. 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 believed 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 bought 5 refineries and it isn't clear to me that there's 5 more refineries or even 3 refineries out there that you can get under that same model right now. That 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 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'd rather -- we could build a hydrocracker for $1 billion or we could buy 2 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 think Erik is as well, we're 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 get into the acquisitive mode, we shut that down and we go buy something. We'll 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 will be after the money flows.

And Neil, Matt touched on this, Neil, but ultimately, it's been less than a year since we 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 5 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.

Our next question will come from Prashant Rao with Citigroup.

First question I wanted to ask. You've just come out of a heavy turnaround 1Q, and you've kept costs low -- or 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, doing turnarounds. Are there things that you could take as lessons going forward, particularly 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?

Yes. I think it's very simple. The head of refining, Herman Seedorf, he's established what we call a best practices network, it speaks for itself what that is. But when you have 5 refineries and basically, all 5 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 to the other sites in there to assist either in planning those projects or in overseeing the execution of them, and then taking the learnings from that back to the best practices group that oversees turnarounds. So that said, 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 and really applies to a lot of operational aspects of the business, but that's something that we're working pretty diligently on.

And in regards to California and Chalmette, the 2 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 have gone on long -- longer than we would have otherwise done it. And we actually got benefits from the turnarounds where the -- our new base case was better than where the refinery was operating prior to the turnaround. Obviously, Del City, Toledo and Paulsboro has been in our system for the better part of 8 years and so we've been through full turnaround cycles there. But on every turnaround you learn something new and we've got an experienced group at every one of our refineries. And like I said, what we've demonstrated, I think, in the first quarter was -- not we, the teams of each of those refineries -- demonstrated was absolute expertise and a great job well done.

That's helpful. I wanted ask a broader picture, PADD 1 market question. The bidirectional 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. Wanted to see if -- sort of if you have any updated thoughts on PADD 1 and how this plays out?

Yes. It's -- I think it's a distinction without merit in regards to they lost on the one directional, so now they're 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 bidirectional as a great answer, certainly, for the people of Pennsylvania.

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

No. I think the $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 5 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.

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

This is Kalei Akamine on for Doug. 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 costs could be?

Yes. The same as it is in the crack. And quite honestly, the analysis gets so basic that it's ludicrous. Like 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. Sometimes it affects the crack and sometimes it hasn't. We've had $0.30 RINs for there, 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 for reform.

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.

My second question is on Canadian heavy differential. 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 capture here in Q2?

Yes. As I said earlier, we ran just under 50,000 barrels -- or 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're beholden to no crude. And so we'll continue to access the most economic crudes to our system.

And we'll go next to Matthew Blair from Tudor, Pickering, Holt.

Just on IMO 2020, so last year PBF ran a crude slate that was about 34% heavy and 29% medium. I know it's early, but 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 sours or maybe you run a little lighter to improve your overall light product yield. Any thoughts on that?

I think it'll 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. The -- what this is, is a problem with sulfur. You're going from 3 point -- or 2.9, whatever the pool is today, to 0.5. 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 that says, hey, 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 a 0.5.

The other point I would make on this, it isn't clear to me that crude is going to be -- as a fact, it's absolutely clear to me that crude is not going to be the alternative -- only alternative. You're going to see a lot of things happen, people who don't have cokers, but have streams that used to go into heavy fuel oil, you might wind up actually having economics that say buy coker feed and don't run as much crude. It all depends on -- if it ever gets down to the alternative disposition of some of these streams as to the power industry and you get these type of clean-dirty spreads that have been bandied 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, we have -- that's what we focused on when we bought these assets, all but Toledo. Toledo is, obviously, 100% light, which we have a fair amount of optionality that we can go any one of those directions.

Great. 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 going -- I think it's actually likely going to be the equal or little bit more. We will have some turnaround activity in Torrance that will add to it. I don't think it's enormously high or anything like we had. But -- Matt, do you have anything...

No, I would just say, directionally, it'll 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 '18.

We have a follow-up from Phil Gresh at JPMorgan.

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

We had an overall consolidated net loss of about $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 the moves you made on the debt side. But I was just curious if there was a specific absolute leverage target of gross debt or net debt that you're thinking about? Obviously, the EBITDA can bounce around quite a bit, but -- and your leverage is looking in better shape as the EBITDA goes up. But just, in general, is there a certain threshold do you want to get to that'd 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 a 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 tick above that, but the goal is going to always be to 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 you'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 1.5x, 2x total debt to EBITDA coverage. But the MLP, right, we've highlighted for folks we want to stay within kind of a 3x to 4x 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 ticking up, EBITDA will then translate into incremental cap so that should really benefit us going forward.

And I'd 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 any time.