PBF Energy Inc (PBF) 2018 Q4 法說會逐字稿

Good day, everyone, and welcome to the PBF Energy Fourth Quarter and Full Year 2018 Earnings Conference Call and Webcast. (Operator Instructions)

Please note that today's call may be recorded. It is now my pleasure to turn the floor over to Colin Murray of Investor Relations. Sir, you may begin.

Thank you, David. Good morning, and welcome to today's call. With me today are Tom Nimbley, our CEO; Matt Lucey, our President; Erik Young, our CFO; and several other members of our management team. A copy of today's earnings release, including supplemental information, is available on our website.

Before getting started, I'd like to direct your attention to the safe harbor statement contained in today's press release. In summary, it outlines that statements contained in the press release and on this call, which express the company's or management's expectations or predictions of the future are forward-looking statements intended to be covered by 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 and annual results excluding certain after-tax, special item charges of approximately $483 million and $256 million, respectively, which are primarily comprised of a noncash lower of cost or market, or LCM, adjustment.

As noted in the press release, we'll begin -- we will be using certain non-GAAP measures while describing PBF's operating performance and financial results. For reconciliations of non-GAAP measures to appropriate GAAP figures, please refer to the supplemental tables provided in today's press release. I will now turn the call over to Tom Nimbley.

Thanks, Colin. Good morning, everyone, and thank you for joining our call today. This morning we reported the results of another good quarter where we ran our assets well and delivered a solid financial performance. Adjusted earnings for the fourth quarter were $126 million or $1.03 per diluted share.

Our strong fourth quarter results highlight the benefit of having a geographically diverse, high complexity multi-asset refining system. During the quarter, our Mid-continent and East Coast refineries were able to benefit from lower cost Canadian crudes. The wider Canadian differentials were largely driven by high inventory levels, takeaway capacity constraints and high-PADD 2 maintenance activities.

The differentials had since narrowed in large part due to the mandated production cuts by the Alberta Government but are expected to widen back out as the underlying takeaway capacity issues have yet to be solved.

Globally, refineries ran at very high utilization during the fourth quarter, taking advantage of a well-supplied crude market and strong distillate margins to maximize outputs. High utilization through the quarter set the table for above normal seasonal builds in gasoline.

On top of this, currently the market is experiencing extraordinarily narrow differential between light and heavy crude oil. This is due to a well-supplied market for light crude oil and a significant number of heavy crude supply constraints starting with OPEC, Non-OPEC, supply cuts, the Alberta curtailment and Iranian and Venezuelan sanctions. Any one of these issues is digestible by the market but the confluence of the constraints has led us to where we are today.

I have been around this business for a long time, and I will say that both gasoline margins and crude differentials this narrow are not sustainable. We have a weak margin environment that is primarily driven by narrow feedstock differentials. Demand remains good and, as history has demonstrated, the supply constraints will get solved.

We are entering maintenance season with planned maintenance globally projected to peak in March. In a challenging crack environment, high levels of maintenance, combined with a series of weather-related disruptions across the industry should translate into lower utilization. We believe this will improve the market for refining margins and particularly gasoline going forward.

Fundamentals are strong with global demand continuing to support product markets. Distillate inventories are down globally as days of cover is tracking well below the 5-year average, and that is with the global refining system in a max distillate mode.

Gasoline economics on the other hand are effectively at breakeven levels at the moment. While it may seem unusual, a large part of this movement is seasonal. We seem to frequently have conversations in the beginning of the year about the weakness in gasoline markets. We believe this situation, as in the past, will correct itself.

Lower gasoline prices should also have a positive impact on demand. On the supply side as we enter spring, we will see increased maintenance activity, which should further decrease the amount of gasoline being supplied. The switch to summer-grade gasoline will also help in this regard as the amount of butane blending decreases. We will continue to watch both the crude oil and product markets going forward and adjust our operations accordingly.

Looking forward toward the latter half of the year and beyond, as Matt will discuss in a moment, we are making some changes to our plans for 2019 in order to put our high complexity refining system in the best possible position for the upcoming marine diesel fuel standard shift with IMO 2020. We believe that there will be an increased demand pull on the distillate markets as the move towards cleaner fuels continues and that higher sulfur feedstocks will see differentials as a result of IMO.

In closing, the economy is still growing, and we are encouraged by the environment we see for 2019 and beyond. Our strategy in this environment, as always, is to put our assets in a position to succeed by running them well and being a safe, reliable and environmentally responsible operator. By executing this strategy, our assets will be profitable, and our employees and shareholders will benefit. I'll now turn the call over to Erik, to go over our financial results for the quarter.

Thanks, Tom. As previously mentioned, PBF reported fourth quarter earnings of $1.03 and $3.26 per share for the full year. Fourth quarter EBITDA comparable to consensus estimates was approximately $311 million and $1.1 billion for the year. PBF's effective tax rate for the quarter was approximately 27.5%, which was impacted by state tax rates and certain discrete items. For modeling purposes, please continue to use an effective tax rate of 27%.

Included in our fourth quarter results, was $27 million of rent expense, which resulted in a full year total of approximately $144 million. At the current price, we expect full year 2019 rent expenses in the $175 million to $200 million range. Consolidated CapEx for the quarter was approximately $265 million, which includes $177 million for refining and corporate CapEx and $89 million incurred by PBF Logistics, including the acquisition of the East Coast terminals. Our quarter-ending liquidity was more than $1.9 billion with approximately $1.6 billion at PBF Energy and $360 million at PBF Logistics.

The year-end consolidated cash balance was approximately $600 million, and our net debt-to-cap was 27%. Importantly, we repaid 100% or $350 million of the outstanding balance on our ABL credit facility. We are pleased to announce that our board has approved a quarterly dividend of $0.30 per share.

Finally, we are pleased to announce that PBF Logistics and PBF Energy reached an agreement to eliminate the IDRs currently held by PBF Energy in exchange for 10 million PBFX common units. This is an important transaction for the companies because it strengthens the alignment between the GP and the LP, simplifies the structure and improves the cost of capital at PBF Logistics.

This transaction demonstrates our commitment to the partnership, while positioning both companies for growth. I encourage you to listen to the PBFX earnings call later this morning. Now I'll turn the call over to Matt.

Thank you, Erik. Despite a declining market over the quarter, our assets ran well with total throughput averaging over 840,000 barrels per day. As Tom mentioned, we will adjust our system in response to the market.

Our East Coast and Mid-con systems benefited from advantaged barrels and delivered very strong results. In other areas, we adjusted operations to account for weaker product margins and other variables outside of our control. We remain intently focused on the aspects of our business that we can control.

We are committed to our efforts to reducing operating costs across the system. There were some seasonal spikes in energy cost during the quarter, particularly in natural gas in Torrance, but overall, expenses were in line with our annual guidance.

In our press release this morning, we lowered throughput guidance for the first quarter. The reduced run rates are reflective of both the current market as well as ongoing maintenance and turnaround activities.

Additionally, in order to strategically position the company for the later part of 2019, we have elected to accelerate the previously announced 2019 turnarounds at Delaware City and Paulsboro. The Delaware City coker turnaround will now occur in the March to April time frame and the Paulsboro crude unit turnaround, originally planned for the third quarter of 2019, will now occur in the second quarter. By moving the turnarounds forward, we will complete approximately 65% of our turnaround work by the end of Q1 and 90% by the end of Q2.

In addition to the turnaround work, we are also conducting repairs on piping and instrumentation associated with a pre-flash tower located at Del City. The equipment was damaged during an incident last week. It is important to note that the refinery's crew unit was not damaged and has been returned to service.

As previously disclosed, PBF Energy is continuing to invest in its assets to improve the strategic flexibility of our system going forward. We are progressing with the restart of the idled 12,000 barrel a day coker at Chalmette refinery and the installation of a new hydrogen plant at Del City.

Both projects are on schedule. We expect that coker will be in service in the late fourth quarter, and the new hydrogen plant, which is being built and will be owned and operated by Linde will be in service during the first quarter of next year.

We plan to continue to put our refineries in position to benefit from the tailwinds that we see driving the refining sector and PBF.

Operator, that concludes our remarks, so we'll be happy to take questions.

(Operator Instructions) And your first question comes from Roger Read with Wells Fargo.

I guess, Tom, let's dig in a little deeper on the guidance and on gasoline. I mean seasonally, I think everybody agrees with you, things should get better, as you could expect, market's a little bit nervous that it won't.

I was just wondering if you could maybe give us an idea of some of the other things you are seeing either on the demand side or some of the supply changes that always occur and maybe put some numbers on that in terms of thinking about your system alone, just how much easier it is to make gasoline, say, in February than it is in May?

Well, yes, a great question, and I commented on this in the prepared remarks, but let me really dive a little deeper. If you looked at the -- 1 week does not make a trend, but if you looked at the EIA data yesterday, DOE data, utilization dropped almost 5% week-over-week, 85.8% refining utilization. That is a combination of a number of things. And make no mistake about it, it's a combination of number of things.

As economic run cuts -- PBF actually took some economic run cuts because of the forward gas crack in the quarter of potentially running our cat units -- not running our cat units full. But in addition, there were unplanned outages as I alluded to because of the polar vortex and the significant extreme weather conditions that we had in the Midwest, and there are still some refineries struggling as a result of that in the Midwest and even in the Northeast and frankly, the incident that we had at Delaware City, which we were fortunate did not have severe damage was a weather-related event.

When you add to those things and talk about the accelerated turnarounds, and we are not the only ones doing that. That just makes common sense. You don't really -- you don't have good coking economics right now, so why not move your turnarounds up and that's what we're doing, as Matt mentioned in the Delaware coker, and we're also moving up the crude unit, the bigger crude unit, the lube crude unit in Paulsboro, but that we're also doing because we're going to fix a problem that is impacting our ability to produce lubes, so it's margin play for us as well.

We're entering this heavy turnaround season. We have a continued incentive to crack distillate, and if you believe the projections for IMO, that will -- trend will continue throughout the year. And it will be interesting to see what happens with the product yield shift if indeed, that is the case.

Butanes are coming out of gasoline, they've already come out of gasoline. We've made the transition, are in process of making the transition in California. The rest of the country will sequentially come behind it. And frankly, you can buy gasoline in Morristown, New Jersey for $2.10 a gallon and then a large portion of the country for below $2 a gallon. I actually think that we're going to see a bounce in demand as a result of that elasticity. Of course, when the prices come back, there may be a pushback.

And the final comment I'd make about the data yesterday. It was interesting to me that gasoline built [to 100,000] but PADD 1, PADD 2 and PADD 5 drew gasoline. The main build was in the Gulf Coast of the United States, and some of that was impacted by fog-related difficulties in shipping material out. Time will tell, but I believe, we are in a process of turning the corner.

Great. And I can confirm we've had a lot of fog down here on the Gulf Coast. Changing direction a little bit here. Erik, the cash flows in Q4 had a big CapEx number come through. Can you give us an idea of maybe the change by accelerating the turnarounds, how you think about managing cash flow, I guess, first half of the year versus maybe full year?

I -- quite honestly, I think, it's probably going to be very similar to the trajectory we saw in 2018, where a lot of our work was going to be front-end loaded during the first half of the year. So cash management, as we've already said, is one of our top priorities here.

And ultimately, between the turnarounds, some maintenance as well as the strategic projects where the coker and the hydrogen plant at Chalmette and Delaware City, ultimately, we should see probably close to 3/4 of our CapEx spent during the first half of this year.

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

Tom, I'll also ask you to dig in a little more on your opening remarks just around the mediums and heavies being so tight. Can you just talk about how crude sourcing looks sort of in the short-term and the medium-term? Is there difficulty just finding barrels? Where are you getting them from and so on?

We've been able -- well let's deal with Venezuela, since that's obviously a living, breathing, moving target right now. We continue to be able to get some cargoes through third parties, but basically we're not worried about Venezuelan ability. We can source other crudes and have been successful in doing that.

So it's not -- the problem is not getting the crudes. Of course, the problem is that those crudes have tightened up and the spreads are narrow. So as others, we have the ability to basically swing probably 50% of our system to lights. We'll do some of that, but we don't believe that this is going to be a sustained event.

I do think it was exacerbated significantly by an ill-advised move by the Alberta Government to go ahead and force mandated cuts, as the law of unintended consequences has played out perfectly here. There was a time, as you all well know, not only could you no longer economically rail crude to either the East Coast, West Coast or the Gulf Coast, you couldn't have pipeline economics in the money when WCS moved to below $10 versus WTI.

We see indications now, some of that's with some other things going on. Obviously, we're net now about $20 onto Brent, and it appears as though that is starting to unwind and move in the right direction and at least there's chatter that perhaps those cuts will be undone quicker.

The last comment I'd make, and it's going to be a question of time. The Saudis, the Russians, all the people who are cutting back right now and are cutting back medium and heavier crudes, which is exacerbating this problem, production E&P companies get paid to produce oil. And again, I just don't think that they're going to be able to sustain this.

And you can actually make an argument, and I've made this argument, that a lot of what we're seeing right now is simply due to the fact that there's too much crude out there. And that's shale crude from North America and the United States as well as we've had some companies in from Canada here recently have told us their growth project -- projections for the next 3 or 4 years. There's a lot of reserves, there's a lot of crude, and there's going to be a lot of crude on the marketplace.

At the end of the day, if you're a refining company, and there's a surplus of crude, that's a good thing, but I do think we're going to have some time here that we're going to have to work through the Iranian sanctions, the Venezuelan situation. And even there, ultimately, and it may take a year, may take 18 months, I have no idea, but there's perhaps promise for the Venezuelan people. And there's visibility to then rebuild that industry. It's going to take some time.

So longer term, certainly I'm bullish. And with IMO coming at the second half of the year, and I do believe it's going to come, we're going to see, again, a 3.5 million barrel stream that disappears, and there's going to be some stranded feedstocks associated with that. So next couple of months your bet is a little bit as good as mine, but it could be -- well be like it was last year, a tale of 2 halves.

Okay. I guess maybe for Matt. On the ACE pipeline that PBFX is participating in, can you talk about the potential benefits for Chalmette?

Yes. We -- for the benefit of everyone else, we announced an open season with our partners at Phillips 66 and Harvest. It is an interesting project not only on its own, but you, obviously, have captive refineries at -- are part of the sponsors of the project. So it opens up St. James.

We believe it is economic, and there's not too much I can say about it other than Chalmette will be a shipper on the pipeline, and we think it'll bring more advantaged crudes to Chalmette. And we think the project is a good project for PBFX and is in line with what PBFX announced a year ago in developing organic projects. This is one of many projects that they'd be working on.

Our next question comes from Manav Gupta with Crédit Suisse.

Erik, can you comment on this line item early return of railcars, which was expensed? Are you actually cutting back on your crude by rail runs from Canada?

Ultimately, that if you go back to Q3, we experienced probably close to $40 million hit in terms of expense associated with early return of railcars. It's simply rationalizing the fleet to make sure that we're using all the latest and greatest cars and that ultimately, we had some idled cars that didn't make sense to use anymore.

I think ultimately, what we've seen is absolutely we'll see a decline in some crude by rail through part of the first quarter, just simply driven by economics as we shift back to more waterborne economics that are better for the refinery on the East Coast but longer term, I think I'd probably echo what Tom mentioned in response to a previous question that ultimately, we think that crude by rail is a long-term viable strategy for heavy crude out of Canada.

And a quick follow-up. What was the working capital headwind in the fourth quarter?

We probably, overall, used about $125 million nominally of working capital during the fourth quarter.

Our next question comes from Blake Fernandez with Simmons Energy.

Erik, just going back on CapEx, I know you said about 3/4 or so, maybe 2/3 will be spent in the first half. I think on the previous call, you had gone through some kind of general ranges, which if we did our math right, would kind of land for full year spending around $600 million to $750 million. I didn't know if you could maybe help narrow that or just kind of confirm that that's a good number for this year?

Those are -- absolutely, Blake. Those are still good numbers. Just high level what we would say, is order of magnitude turnarounds are about $300 million for the year, I think Matt commented on when we're going to have maintenance downtime and ultimately, that we're going to be through the bulk of that during the first half of the year.

Then we've got another, call it, between $200 million and $250 million of maintenance-related expense. That's going to be a combination of regulatory spend, environmental spend and just general maintenance. And then we obviously have about $150 million of, call it, strategic projects, discretionary CapEx related to the coker and ultimately, the hydrogen plant. That's probably got a longer runway in terms of overall CapEx outlay through the course of the year.

The coker is expected to be up and running by the fourth quarter of 2019 and the hydrogen plant during the first quarter of 2020. So that CapEx outlay is going to be spread over, call it, through the remainder of the remaining 3.5 quarters of the year. But ultimately, the bulk of the turnaround and maintenance, that 75% is probably going to be, call it, between $500 million and $600 million during the first half.

The goal -- I think the key message here is that ultimately, we understand the decisions made to accelerate a few of these turnarounds and bring maintenance forward. Ultimately, yes. There will be a use of cash, but ultimately, we will have a very clean runway as we look towards the back half of the year.

Understood. If you could, maybe just spend a quick minute on the IDR simplification. I think this should be viewed as a positive step but just does this change anything? Is there anything imminent, maybe drop-down potential, self-funding, just any kind of general comments you might offer?

I think ultimately, our view for both PBF Energy and PBF Logistics is this is a transaction that worked for both parties. We've shown pretty significant sponsor-related partnership and growth here associated with support that, ultimately, comes through in the form of -- we still have the drop-downs that are out there, but our real focus is on organic projects and third-party acquisitions at PBF Logistics.

This was clearly something that the investment community was pushing for. We are all for and very supportive of a lower cost of equity at PBF Logistics. We've always said that logistics and energy should work in tandem and that ultimately the plan would be the streamlining of the structure should ultimately help both companies continue to grow.

We have not provided guidance in terms of what's coming next in terms of drops or anything else. There's clearly been significant strain and stress in the MLP equity market. Although, we are starting to see pretty significant movements there. There obviously is a new fund that was raised earlier this year. We have been successful in essentially self-funding over the past couple of years. We brought in a strategic equity partner in Tortoise during the middle part of 2018.

So our long-term view is, this is a viable strategy. It's a way for these -- both of these companies to grow, and we still firmly believe that for discrete projects, accretive transactions, there will, ultimately, be access to capital. It may just come in a form that's slightly different than what we've seen in terms of the old, regular way MLP equity fundraising from the 2014, 2015 time line.

We'll take our next question from Neil Mehta with Goldman Sachs.

So I guess first -- my questions are a little bit more tactical in nature. I guess the first one is at the forward curve, do you see PBF generating cash flow from operations that exceed the capital spending levels and the dividend?

And the reason I ask that is if there is a funding gap, we're just trying to figure out, is there a risk of incremental debt issuance? Do you work down cash balances? Or how do you think about the need for incremental equity? You guys really effectively timed the last equity issuance, so I just wanted to see if any thoughts on whether you'd be willing to tap the equity market again if there's a funding gap?

As we sit here today, Neil, quite honestly, I don't think we have any comments around potential equity raises. We feel very confident with -- we just repaid $350 million on the ABL. That is exactly what that ABL credit facility is there for.

In terms of -- if we're going to be building some inventory during the course of turnarounds to then run it as we're coming out of turnarounds or if we have some strategic opportunities related to crude, and we want to store crude for a period of time and then as we're coming out, ramp up runs, I think we'll do that.

As we sit here with the forward curve, Tom provided a lot of color on the distress in the gasoline market. And while we think that ultimately things will rebound, near-term, and I think this is consistent with what we heard from our peers over the past couple weeks, ultimately, this is unsustainable, but it's not very much fun at the current point in time.

And so ultimately, yes, we'll probably burn some cash throughout the first quarter and potentially into the second quarter. But we feel very good with the liquidity position that we have today. So don't anticipate any type of equity fundraising related to needing to fund anything at PBF.

Okay, that's helpful. And then the follow-up on PBFX. You guys have taken a different approach than some of your peers with MLPs in the sense that you're leaning into the business this morning, and it feels like if anything you're saying it's a very core part of your strategy.

When we look at the MLP-eligible EBITDA that sits at the PBF level, what is the best way to monetize that, given the challenges in the drop-down markets right now, from a capital markets perspective? How do you best get credit for the midstream and logistics assets that sit up at the parent?

I think it all depends on what the prevailing market is. When you say we are leaning into the MLP, we work very, very hard internally here to strike the right balance. Clearly, IDRs were going by the way of the buggy whip or other things that have left and so there's clearly a trend and something that we talked quite a bit about.

If the MLP works, it is a sort of a perfect sidecar for our refining business because there is certainly the crossover between midstream assets within the assets that we own and then you have a cost of capital differential that you can provide investors with different investment classes that work for both. But it's all function of the MLP market working and being open. And one thing that PBF is not interested in is simply dropping down assets if the markets aren't open and taking back equity.

So to the extent the markets are open we firmly believe we can grow the business and are quite comfortable with the growth projections we've put out there. That's not only from drop-down assets to which we have a large inventory of drop-down assets but all the different projects that we're working on. And as you saw in the fourth quarter, we also bought a terminal from Lindsay Goldberg. So our growth strategy is there and ready, willing and able. It's going to require the markets to be open, and only time will tell on that.

We'll take our next question from Paul Sankey with Mizuho.

On the accident, the initial headlines read pretty bad, it seems like it wasn't that bad. Can you just talk a little bit more about what happened with the understanding that there was an injury?

I'd just make a couple of comments, Paul. We still have an investigation underway and as always the case in these things, one of the things I've learned from my career is don't believe the first 10 things you hear when you have an incident like this.

But we can say, I absolutely have to give a tremendous thanks to emergency responders, firefighters inside and the mutual laypeople who responded because we had a pretty good fire there. We are honing in now exactly of what happened, but we're not quite done.

But because they were able to get water and foam onto the area that the fire was burning and because there wasn't that much equipment in that area, it was really just a fair amount of instrumentation damage that occurred. And as we mentioned, we were effectively able to get that unit back up 7 days after the fire occurred. But again, I think it was testimony to how well our emergency responders handled that situation.

It's tough as you mentioned; the current environment looks like it'll eventually recover, given the shortage essentially of heavy crudes. From a planning point of view, how are you thinking about timing and how to respond?

Insofar as it's extremely difficult to know, I guess, we can say that the Canadian crudes will come back in due course logically, but it seems that Saudi may have stepped down to a structurally lower level of production with a view to $70 oil. And it seems like Venezuela isn't going to recover anytime soon. Are you sort of planning on an outlook of rates hike over what time frame? Because your comments suggested you expect a rewidening in due course.

Certainly, do expect a rewidening and of course, in due course. We do believe that Canada will lead the pack. And that there is a -- this curtailment simply did not work, I mean, it worked in terms of narrowing the spread, but you may have seen that, one very large company, who was railing in north of 100,000 barrels a day of crude has indicated they will be railing 0. So when you're transportation-limited, that perhaps becomes more of a problem.

So we believe that we're already starting to see the Canadian differentials widen up. But I then think you hit the wildcard is -- and to me some of this is circular, we've seen this movie before. The price gets too low, Permian growth is high, OPEC, Non-OPEC says we've got to come in and balance the market, they cut back their crudes, effectively -- then gets faced with -- the price might go up but their market share may be getting diminished.

At the end of the day, I go back to what I said, I actually think there's plenty of crude out there, plenty of heavy crude, medium crude and light crude, and that will ultimately play out in our favor. But it certainly is going to take a little bit more time to get the Venezuelan situation and the Iranian situation behind us, and then it is going to be a function of what the Saudis and, frankly, the Iraqis -- there's a lot of crude in Iraq that could solve this problem if they would open it up.

Paul, also just low prices affects oil prices and so as the U.S. complex refining system pushes back heavies and sours and starts running lights with crude, that will have an impact unto itself.

And just Tom, it seems like you are pretty much expecting Iranian sanctions?

Well, I wouldn't rule it out. Certainly, this administration is very aggressive. So I'm not in Washington, D.C., and I try not to be in Washington, D.C., but the fact is there's a high probability that he's going to continue to do some of these things.

I just want to amplify what Matt said. And just simply, you all know this, when you have the type of heavy, medium crude differentials that we have, that tight differential. When you have 6 oil, 3% 6 oil in New York harbor trading at a higher price than gasoline, notionally, call it, breakeven with Brent, and you've got a $15 to $16 diesel crack, you don't have good coking economics. Clean/dirty spread is not wide enough so then what happens people will start pushing back those crudes and try to lighten up to the extent you can, and this will fix itself over time.

We'll take our next question from Doug Leggate with Bank of America Merrill Lynch.

Tom, I wonder if I could just get your updated thoughts on IMO, and it's really more high level given the timing of everything that's going on with heavy oil. Because it seems if this does roll through, let's say, next year or so. That would kind of coincide with the timing of when one was anticipating otherwise weakness on sour crude. So any updated perspective, please? And I have got a question on gasoline.

Yes, I think, our view is a lot of the concerns about IMO was predictably on the supply side for the compliant fuel. We've come down or I've come down to state that is not going to be an issue. And the reason I say that is, everybody assumed that it was going to be ultra-low sulfur diesel and it may be ultra-low sulfur diesel on a margin that meets that new demand for this 3.5 million bbl/d or 3 million bbl/d, pick your number, of a 0.5 fuel. But a lot of that can be supplied by just frankly hydro treated gas oil in a refinery.

And if you had a situation, and you're going to talk about gasoline next, where gasoline remained under pressure, frankly, you can just take gasoline out of the cat cracker that's always compliant fuel, it is below 0.5 in many of our refineries because we take sulfur out before it goes into the cat unit.

So I think the ability to supply the fuel is going to be there for the industry. The industry is ready to do that. Obviously, you might be on the margin doing that with higher, light sweet crudes or whatever and that will impact price structure.

Personally, what I am more interested in or I'm waiting to see how it plays out is, there's a significant amount of distillation capacity, crude capacity in this industry mostly in other parts of the world that run medium and medium sour crudes and where they go with it is into the international bunker fuel market. And that markets going away.

So that becomes 3 million barrels of stuff that if you continue to run the crudes, you've got to figure out where they're going to go, where's the home? If you try to put it into asphalt, there's not enough coking and conversion capability so then does it go on a margin into the power generation system? Can you lighten up, sweeten up?

I will tell you the United States is probably darned close to being able to process all -- as much light crude as it can until you get some of these investments that are being talked about. So our view is IMO is going to come, and in fact, that it's going to be good for companies like PBF, who basically run a kit that is very high complexity and that's why we bought the refineries in the first place.

I appreciate the long answer. I'm afraid my second one is also kind of a macro issue given how much time you spend talking about gasoline weakness. It's really just to get your perspective on some structural changes or whether you agree with this or not, I'm just trying to get our head around what happens next.

I remember the good old days of seasonal strength in gasoline, and we're trying to figure out if, with all the windfalls behind us, we're just going to get back to a very simplistic view of the world. And what I'm referring to is the fact that the U.S. is running the highest API slate in its history currently.

And obviously, storms aside, when you don't have a storm, it seems that we end up with very weak gasoline in the winter. Do see that as a structural repeating cycle now or do you think there is a little bit more to it than that?

No, I think it's a little bit more than that. I will agree with you that certainly worldwide, the gravity of the crude inputs worldwide has increased. And it certainly has increased in the U.S. and I suspect -- I did say that I think absent additional capacity coming on, you're going to get pretty close to being able to absorb all of the -- as much of the shale that is being produced in the U.S. before you start running into production cuts or operational problems.

I think that you will see seasonality will continue, you'll also have some knock-on effects. One of the things about some of the shale oil crude is it's got a higher cut of straight-run naphtha, therefore, there's more gasoline yield, at the same time the octane component of that stream is lower than normal, and frankly you have pretty good octane spreads in the harbor that will probably benefit as we move forward into summer.

We'll take our next question from Prashant Rao with Citigroup.

I wanted to ask, specifically, on some IMO 2020 preparations and certainly the opportunity pipeline, now that we are getting closer towards the implementation. There's some recent news about your contract with Maersk on the East Coast for providing the Marine fuels for -- compliant IMO 2020 Marine fuels for, think it was 10% of their fuel needs coming out of the East Coast.

I'm wondering if we could get a little comment on that. And then certain -- it's a greater opportunity set in storage and providing those fuels. What does that pipeline feel like in the next few months? Should we expect to see more of these deals, what's the size of those? And then what does it say about how close we are to, in terms of progress, putting a standardization of a new [lithoil] for fuel oil blend?

So on the Maersk announcement that, that came out this morning, of course, that is a PBFX announcement. PBFX bought the old Crown Point terminals, I think we refer to them as the East Coast storage assets. And we bought the assets with this transaction sort of being worked as we did. It is a toll processing deal for the MLP. It is a direct result of IMO and it's good business, for sure, for PBFX.

But a big reason why we are going to be able to create synergies with those East Coast assets and our PBF refining assets is, you have millions of barrels of heated dirty storage. And so we believe the opportunities are going to be many.

We've been reached out to with -- by counterparties that don't have the complexity or the coking capacity that we do, and I think there are a number of companies that are running a more simple kit that, quite frankly, are making money today because of some of the perverse differentials that are in the marketplace, but are staring down the barrel of what could be a very challenging time.

So I think we are well positioned for it. The deal with Maersk is -- it just enhances our returns on the Crown Point acquisition. And so we think it certainly makes a lot of sense, and we're excited about the transaction and working with them over the next number of years.

I'll just add very quickly that tankage that Matt referred to, obviously we have a large coking operation in our East Coast facilities. We do believe there's going to be opportunities for people not to run crude, heavy crude, but people who are saying we have this stranded -- potentially stranded stream called high sulfur resid and that 3 million barrels of tankage can allow us to bring that in and move it either to Delaware or to Paulsboro.

I guess stepping back, the next question I had was on the broader macro. Tom, we've seen numbers out there, I think the IEA OMR that was out yesterday with them repeating the 2.6 million bbl/d of incremental capacity adds 2019, and think there's some skepticism around that number, it's back-half loaded for some of those projects. It remains to be seen what the progress is.

I'm wondering if I could get your big picture thoughts on what seems more likely if we were to haircut that. And what are some of the risks that -- to the downside that might help us to maybe come to a more balanced market versus incremental product demand, maybe sort of a sanity check on that would be great.

Yes. I think '19, I wouldn't expect to see a number that high, maybe 0.5 million less than that, at least that's what I have read. I'm just reading the same -- some of the information that's put out there, [Pyre] and others who say that that's probably overstated.

When you look at a 3-year look-ahead, frankly, many people say you're going to have -- assuming there is no recession and with 1.3% -- $1.3 [billion]-a-day growth numbers in demand or north of that, almost a balanced situation.

Now, longer term, when you see things like ExxonM capacity in the U.S. because of the integrated model that they're going to have with the Permian, that's going to be something that the whole industry is going to be looking at and factoring in. I'll leave it at that.

And just one very quick sort of detailed question if I would (sic - "could") before I turn it over. We've gotten a few questions, given that sort of cyclical industrials are kind of slowing a little bit in transportation, not necessarily hitting contraction but just maturation in the industrial cycle, some questions on demand, which I feel like cracks have been great for the last couple of years.

With IMO coming up, it's asked about a little bit less but seems like there'll definitely be some support for wider jet cracks. On balance though you could see a little bit of slacking in demand or maybe slowing down of demand growth.

Wondering how you're thinking about the knock on effect to jet fuel, specifically from IMO 2020, as we get closer and you're thinking about how you're going to run your kit and configuration options once we start to get closer to Jan 1? And will that be sort of a dislocation that's similar to other middle distillates, more pronounced or less pronounced? Any thoughts there would be great.

Yes. That's really a great question because when I said our views or my views have morphed a the little bit on what might happen with -- on the product side, it is really everybody assumed that it was going to be a $3 million-barrel pull on ultra-low sulfur diesel or a very high component of that.

I think it's 3 million, 3.5 million bbl/d of light products. And that either could be you un-make gasoline by taking gasoil out of the cat cracker, as I mentioned earlier, deconvert the jet -- take jet fuel and put jet fuel, it's a compliant fuel.

So I think the reality is, IMO, on the product side will give some underpinning and support to all light products. Jet, gasoline and diesel. And so we'll see; there may be a drag certainly economically, where we are mature in the cycle. But IMO should be a nice boost.

We'll take our next question from Benny Wong with Morgan Stanley.

Just wondering if you can give us your outlook of product exports for you and as well as the industry. Just wondering what's happening in Mexico, how much is that going to affect it?

And the second part of that question, as it relates to IMO is, as it approaches and refineries start changing behavior slightly, do you have any early thoughts on how product flows or even crude flows will change or evolve?

Just on exports, we made some investments down in Chalmette over a year ago, and our exports out of that facility have been fairly consistent. Actually in the fourth quarter, there were some opportunities to make some exports out of the East Coast, which we did and it just speaks to our optionality of being able to deliver products out of different refineries on the coast.

And then we're developing a project that is about to take hold in Toledo where we're going to be exporting finished products into Canada, starting almost as we speak over the next couple of weeks. So there's -- we have, as a company, a base level of exports that are not dependent on Mexico per se.

But it's -- it is a big driver in the U.S. refining bull case in that the U.S. refiners are providing fuels to the rest of the world because we have the most complex kits, we have access to attractive crude, we have cheap natural gas, and we have the best workers in the world. So it's a good combination, and it certainly makes our market more buoyant because the U.S. is then competing with products with the rest of the world.

On the feedstocks side, if you will, and what might happen with flows and trade patterns et cetera, I'm going to be fascinated by how this all plays out. As I said, there's over 4 million barrels a day of distillation capacity that doesn't have any -- has low complexity and there's significantly more than that that doesn't have coking capacity.

So on paper, if you lose the outlet for your high sulfur fuel oil bunker market and that stream is still there. Personally I think you're going to see an opportunity or a shift, a wave perhaps from filling your cokers on the margin from crude. And filling your cokers on the margin from somebody else's stranded feed stream.

So we'll have to see how it all plays out but certainly we're positioning ourselves as a company with the tankage in the East Coast that we've got to be ready to be able to have the catcher's mitt to take somebody's stranded oil and not necessarily just fill the cokers with crude.

We'll take our next question from Phil Gresh with JPMorgan.

This is John Royall sitting in for Phil. So I know you've spoken about wanting to get bigger on the Gulf Coast and the West Coast, but would you ever consider expanding your refining footprint into Eastern Canada? And how do you think about that market from a competitive advantage perspective?

Let me answer it this way. We'll consider anything, but our priority is going to be trying to get an asset obviously at a reasonable price and fits the model in PADD 3 and PADD 5. If there was a great opportunity, we'd look at it in Canada, but one of the things we are very conscious of is going into a foreign company to become an operator has a little bit of a bandwidth issue with it in terms of management's attention span.

So it would have to be a very good opportunity, otherwise we're going to keep the strategy, which obviously we've got it as a strategy, but it all is dependent upon the bid/ask to try to grow. We intend to grow and to do it by having an additional asset in those 2 PADDs.

Okay. And then it looks like one of your peers is -- in California is shutting an FCC. What impact do you think this is going to have on the West Coast product market?

Yes, it's already shut and that was done -- that was Tesoro, now it's MPC obviously with the takeover endeavor, but when Tesoro was -- had acquired the 2 plants in Southern California, Carson and Wilmington, they undertook a project to try to hook those plants up and make them more synergistic between the 2 plants. And they did ultimately, get a permit to allow them to do that. But a condition of the permit was to shut down -- what's that cat, 40,000? 42,000 bbl/d FCC.

Los Angeles is short gasoline -- by and large. Even when the -- California's balanced, there's a net movement from the Bay Area or Pacific Northwest down to L.A. to supply that market. So there's going to have to be more supply that gets down there because that's coming -- that is now shut down, that unit.

We'll take our next question from Paul Cheng with Barclays.

Just curious that Tom and Erik, when you're looking at PBFX, does it really have a cost advantage on capital cost or any other funding cost related to PBF? And so from a strategic standpoint, how important it is for you to have that as a subsidiary, which while -- and also that from a valuation standpoint, quite frankly, I'm not sure that it really add to really that much value to the C Corp, anyway. It's pretty small.

Yes, I think, Paul, we've obviously had a fairly strategic announcement this morning related to the IDR conversion into common units. We are believers in the MLP strategy as we go forward, but obviously we need to see how things unfold here over the next few years in the equity market. Because clearly for the MLPs to grow, we need that equity market to rebound in some way, shape or form.

For us, we've run the math a couple different ways, and obviously, with the IDRs coming out, lower cost of equity should be a real benefit for PBF Logistics. We still have a couple of different things in market where there is enough arbitrage between where refining companies tend to trade and where MLPs trade that we think the math works.

But ultimately, today's announcement is extremely strategic for us, and we're going to need how the market responds to what we think is overall a very positive message. And we feel like PBF and PBFX came to a very reasonable agreement between the 2 parties that ultimately, Matt mentioned that as a sidecar vehicle, these 2 companies should be working in tandem to continue to help grow both the refining business as well as the logistics business.

PBF by itself would not be able to have acquired the East Coast storage assets, going back to Plains assets. But those are very good deals for PBFX and they bring with it synergies with the parent.

So markets go up, markets go down and they certainly have been sideways in the MLP space. And we've tried to position as well as we can and to the degree that's well received and the markets opened, we think it makes a lot of sense.

Torrance, the fourth quarter margin realization seems to be a bit stronger than we would expect, comparing to the market indicator. Any particular reason that -- why that may be the case?

I think ultimately, Paul, it's just a combination of things over the past 2 years. We've clearly spent a lot of time, a decent amount of capital and the team has continued to develop. The combination of all those things we think will continue to lead to performance coming out of Torrance that's consistent with what we laid out on the front-end.

When you run well, it saves a lot of discussion and the refinery has run well and they continue to make improvements and optimizations around the assets. And I think the core's performance [is as we said].

I'd add that operation and the refinery has improved. There's still work to be done there, OpEx has gone down, but the commercial activity in Torrance has been impressive. What I mean by that, getting into new markets, I mean, getting into asphalt market, running the marketing system at very high [RAC] numbers. So I think the business unit, and I mean the business unit, commercial, logistics and refining itself is continuing to make improvements in strides.

Tom, can you share how much is the marketing contribution in Torrance in the fourth quarter? Is it a big number?

You know what we really don't break that out, Paul, it's just -- what I can tell you we are moving a lot of barrels.

A final question, whether you guys will be willing to share what is the benefit in the fourth quarter from the different crude defenses? I mean that Exxon have said year-over-year from 4Q '17 to 4Q '18 the better crude defense so have captured about $1.2 billion after-tax. So is Exxon willing to share, okay with that, what you guys be willing to share?

I'm sorry. What was the question?

How much is the crude benefit -- crude oil price defensive benefit that you received in the fourth quarter. I'm saying that as to everyone's present supply, Exxon actually gave out a number saying that from the fourth quarter '17 to the fourth quarter '18, the much wider crew defense or what they capture in the downstream is $1.2 billion after-tax. So i was just talking, saying that if Exxon that the most ultimate that don't want to share information will be willing to share, I hope that you guys will be willing to share also.

I commend Exxon for their willingness to share but that's not something we're splitting out today.

We'll take our next question from Matthew Blair with Tudor, Pickering, and Holt.

I'm not sure if I missed this, but could you share your WCS crude by rail volumes in Q4 '18 as well as your outlook for Q1 '19? And do you feel -- are you receiving the full economic benefit of these barrels in Q4? Or are there any like fixed-price contracts or hedging that might have limited the upside?

Basically, we ran north of 70,000 bbl/d, I think, through the fourth quarter by rail. And we've captured by and large all of the benefits from the distortions in the marketplace in the fourth quarter. That wasn't true throughout necessarily the whole year, but in the fourth quarter. As we move into the first quarter, I think for the month of January, we probably would've continued to move somewhere around 60,000 bbl/d by rail, but that is coming off. As Erik said and others have said, right now, we think that we are probably going to bottom out somewhere around 30,000 bbl/d in the March, April time frame and then based on what we are seeing in the -- remember, there's a big lag in the system. Based on what we're seeing now with the spreads widening out, there is roughly $20 now versus Brent. We would expect to be ramping up in the second quarter.

Yes, we absolutely believe, as Tom said, that, that market is bottomed out and we did, we did and we will be able to evidence that we responded with the differentials shifting from being the cheapest crude of the world to being the most expensive on an economic value, and so we responded and that all goes to the market sort of fixing itself and then we'll decidedly ramp up as the crudes become more attractive.

Sounds good. And then turning to your RIN guidance, so looks like guidance is up approximately 30% year-over-year for 2019. If I look at year-to-date ethanol RINs about $0.21 in 2018, ethanol RINs averaged about $0.30, however biodiesel RINs are up year-to-date. So could you talk about what's really driving the year-over-year increase in your RIN expense? Does it have to do with the biodiesel side?

There is an element of the biodiesel side and quite frankly there's probably an element of conservatism in there just based on what we've seen in the market, thus far, where things have traded over the past few months. But I think that something that we will continue to kind of update as we go, we'll -- obviously as the year progresses we will have booked a certain amount related to RINs for both ethanol as well as the bio component, but ultimately, there's probably some conservatism built in there.

RINs will be what they will be, although we're entering kabuki theater for, I don't know what number this, the acting Secretary is going to try to get confirmed by the Senate. I think he received the letter from 5 Senators this past week, voicing their concerns over the RIN market and the impact to the manufacturing base of this country. He, no doubt, is hearing from the powerful core lobby and so it's just, again, it's a snapshot of why big government can be -- have a whole bunch of unintended consequences, but we -- I'm actually comfortable certainly with the administration that they recognize high RIN prices not only affects the consumer, but can absolutely damage the manufacturing side and refining side and have done a reasonable job of keeping RIN prices in check, and I expect that will continue.

We'll take our next question from Jason Gabelman with Cowen.

Firstly just on PBFX or organic growth. I know you have that $100 million EBITDA target out there. How much of that was realized last year? And is this Maersk deal that you announced today, it doesn't seem like it was embedded in the East Coast acquisition EBITDA target. Is it part of this organic growth target?

No. And I want to shy away from giving forensic accounting on $100 million, we invested a fair amount of money last year, and we continue to invest money this year on projects. I mentioned that Toledo export facility, that's part of it, I think, by this year will have $10 million of run rate EBITDA as a result of those investments. In regards to Maersk, I would not characterize that as an organic project. It is absolutely incremental to the economics that we shared when we acquired the facility and something that's been in the plans for some time, and so we identified it as upside but this is the first time that the market is learning of the upside and like I said, it is definitively incremental to the business.

And just a quick question IMO 2020. Just want to go back to your comment about potentially blending vacuum gasoil into the Marine fuel pool. There's been some industry chatter that there could be some issues with blending. I'm not sure you guys are running the tests to kind of sanity check that or what your expectations are on the vacuum gasoil blending? And just follow-up from that, I understand you still expect IMO 2020 to be positive for PBF, but is the magnitude of the benefit that you're expecting in 2020 the same magnitude that you were expecting, say 6 or 8 months ago?

Second piece of that. I think it will be. Frankly, certainly, on the feedstock side and stranded side, I don't see anything that's changed that outlook in terms of corporate penetration or people figuring out what they going to do with these streams. And the whole key there is, if indeed, you're [tipping] on the margin that you are going into the power sector, then you're going to wind up with these $30, $40, $50 clean dirty spreads, which will push coking economics to be very attractive. I think on the blending side, make one another comment after that, we're going to leave that to the Exxons, BPs and Shells of the world, they are actively working through -- trying to do formulations and blending with a variety of different-sourced, what would be compliant from a sulfur standpoint fuels. I can assure you every one of those companies has the ability to do a lot of hydrotreating on their gasoils and turn that gasoil. And it's a higher density fuel than diesel, because obviously it's got more BTUs in it. So we're going to wait and see, we are not doing any of our own formulations. Recognize though that we're burning 0.1% sulfur in all of the ECA zones around the world there has not been real issues with that. Now gasoil, we'll find out what they do. I would say, I suspect that this industry, on the product side will figure out how to solve this problem with less of a problem than was originally forecast. And it may be that you will get an initial pop that will be the same as what was thought but I suspect that on the product side and the availability to fuel, that will be solved in a short to midterm and the longer implications might be on the stranded feedstocks and wider for longer heavy crude, sweet sour crude differentials.

I'll now turn the call back to Tom Nimbley for closing remarks.

Thank you, everybody, for joining us today. We look forward to talking to you in our next quarterly call.

This does conclude today's program. Thank you for your participation. And you may disconnect at any time.