PBF Energy Inc.
Q2 2017 Earnings Call Transcript

Published: 6 Aug 2017

[Operator:]

Good day, everyone, and welcome to the PBF Energy Second Quarter 2017 Earnings Conference Call and Webcast. At this time, all participants have been placed in a listen-only mode. And the floor will be opened for your questions following management’s prepared remarks. [Operator Instructions]. Please note, this call may be recorded [Operator Instructions]. It is now my pleasure to turn the floor over to Colin Murray of Investor Relations. Sir, you may begin.

[Colin Murray:]

Thank you, Erica. Good morning, and welcome to today's call. With me today are Tom Nimbley, our CEO; Erik Young, our CFO; and several other members of our management team. A copy of today's earnings release is available on our website. Before getting started, I'd like to direct your attention to the forward-looking statement disclaimer contained in today's press release. In summary, it outlines that statements contained in the press release and on this call that express the company's or management's expectations or predictions of the future are forward-looking statements intended to be covered by the safe harbor provisions under federal securities laws. There are many factors that could cause actual results to differ from our expectations, including those we described in our filings with the SEC. As noted in our press release, we will be using certain non-GAAP measures while describing PBF's operating performance and financial results, as we believe these metrics are useful. 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 Erik Young.

[Erik Young:]

Thanks, Colin. As a result of changing hydrocarbon prices during the second quarter, we generated a noncash lower-of-cost-or-market, or LCM, after tax adjustment of approximately $92 million, which decreased our reported operating income. The remainder of our comments today will exclude this special item. PBF reported income from operations of approximately $39.9 million and an adjusted fully converted net loss of $6.9 million or $0.06 per share on a fully exchanged, fully diluted basis. This figure includes debt extinguishment charges of $25.5 million and other non-recurring or one-time expenses totaling $7.6 million or $0.04 per share. For the quarter, G&A expenses were $41.1 million, depreciation and amortization expense was $68.7 million and interest expense was approximately $40.7 million. PBF's reported effective tax rate for the quarter was approximately 39%. For modeling purposes, you should continue to assume a normalized rate of 40%. Our RIN expense for the second quarter totaled $74 million. Given the current uncertainties surrounding the RFS and RIN pricing, we continue to expect that our full-year burden will likely be in the $350 million to $375 million range. Total consolidated CapEx for the second quarter was approximately $280 million. Of this, we spent $243 million on refining and corporate CapEx, while $37 million was spent by PBF Logistics. CapEx for the quarter includes expenses for the completed turnarounds at Delaware City and Torrance as well as for the Chalmette reformer restart. For the remainder of the year, we expect to spend approximately $175 million on refining CapEx and $60 million at PBF Logistics. With respect to the balance sheet, we ended the quarter with liquidity of just under $1 billion and consolidated net debt-to-cap of 41%. In May, we successfully refinanced our 8.25% senior secured notes with a new $725 million 8-year bond tranche. The new unsecured notes have a coupon of 7.25%, which will result in an annual cash interest savings of approximately $3 million and extends our weighted average long-term debt maturity to more than seven years. With the majority of our 2017 capital investment program behind us and with five operating refineries, we began to return our working capital to normal operating levels. As we outlined on our first quarter call, we built inventory during the first half of the year to maintain unit rates and fulfill our commitments to our customers throughout the heavy turnaround cycle. We are now focused on reducing the excess inventory which should result in positive working capital across the third and fourth quarters. I'll now turn the call over to Tom.

[Tom Nimbley:]

Thank you, Erik. As Erik pointed out, we have accomplished many things in the first half of this year. And in doing so, we have set ourselves up for a promising second half. We recently completed PBF's first turnarounds at the Torrance refinery, which involved a number of different units, including the crude unit, 1 or 2 cokers, saturated gas plant hydrocracker and the FCC feed hydrotreater. At the peak, we had more than 2,000 people working onsite and completed numerous scope items that will improve reliability, yield and efficiency in the coming years. Torrance is now operating at planned rates. We expect to see improved reliability as well as tangible improvements in unit performance. We have already seen improved performance from our crude units with better cut points. With the turnaround complete, we have initiated a reorganization, which, along with increased reliability, will reduce overall operating expenses. I am also pleased to announce that the City of Torrance has issued us a building permit to allow for the construction of a foundation and enclosure to house a 220,000-volt switching station, which is the next step in a collaborative electrical reliability plan developed jointly with Southern California Edison. While Chalmette refinery continues to run well following its successful turnaround and improved reliability is also driving operating cost reductions. Our reformer restock project is mechanically complete. The associated naphtha pretreater is online and the light ends plant and reformer are in different phases of start-up and will be resteamed in the next two weeks. We expect to see improved margin capture as we are now able to upgrade components of our gasoline pool into higher octane, low sulfur finished projects -- products. The new crude tank at Chalmette is also well underway, and we expect the tank to be in service as planned by late October. As mentioned on prior calls, this project is a gateway to decongesting our dock facilities and increasing our product export capabilities. Looking towards the second half of 2017, the economic environment and market outlook looks promising. OPEC cuts have impacted the available supply of medium and heavy sour grades, resulting in narrow feedstock differentials, which is a challenge to our complex refining system. This has been offset in many ways by robust demand, both domestically and globally, which have supported strong cracks in all regions. Distillate demand, in particular, has improved and continues to reflect strong economic growth domestically and in our export markets. Before closing our prepared remarks, I would like to comment briefly on RINs. RINs have been and continue to be a headwind and a headache. We have been disappointed in the administration's lack of movement on RIN reform to date. However, we are hopeful that with the appellate court decision last week that there is a clear pathway for the EPA to proceed with fixing this deeply flawed system. We look forward to the EPA aligning renewable volumes with consumer demand as well as addressing the point of obligation to align compliance with the location of the blending activity. Today, with strong market conditions, we have positioned ourselves to be successful, and we look forward to demonstrating the potential of our refining systems. Operator, we've completed our opening remarks. We'd be pleased to take any questions.

[Operator:]

Thank you [Operator Instructions]. Your first question comes from Phil Gresh from JPMorgan.

[Philip Gresh:]

Just a couple of quick guidance questions. Erik, starting with the capital spending outlook for the second half of the year. If I take that with the first half, it sounds like it's a raise for the full year to $700 million. I think it was $625 million to $650 million before. If you could clarify that and just provide some color about where the incremental spend is going?

[Erik Young:]

No. I think, Phil, it is actually in line with what we laid out on the last quarterly call. So the logistics, I think what we've done is originally we were coming out in the range that you highlighted, but the refining and corporate CapEx is going to be in the $575 million to $600 million range. And with the organic projects as well as the Toledo Terminal acquisition at PBF Logistics, that will come out for the full year in the $110 million to $120 million range. So I think both of the, both those numbers should be consistent with the Q1 call.

[Philip Gresh:]

Okay, got it. The second question is this, I was looking at the throughput guidance you're giving for 3Q and then for the full year. If I were just to take the midpoints of those, it would actually imply that 4Q runs will be down from 3Q by about 45,000 barrels a day. And so is that just conservatism? I believe you said there's no turnarounds at all baked into the second half of the year. So I was just wondering how to think about that?

[Erik Young:]

I think it's probably in line with what you laid out. I think, at this point, highlighting where we think Q4 is going to be is always a difficult thing from a runs perspective because we don't have a real guide on where cracks will be. But ultimately, I think, our Q3 numbers are really the ones to focus on as we're kind of one-third of the way through that quarter.

[Philip Gresh:]

Okay. Last question would just be, again as we look at the second half of the year with Chalmette and Torrance and with no turnarounds. Tom, is there any reason we shouldn't expect you to be able to achieve your mid-cycle EBITDA expectations on a run rate basis given where we see crack spreads right now and given the expectation that it will be running pretty flat out?

[Tom Nimbley:]

Absolutely not. In fact, we're very pleased with the run, the operation at Chalmette. Since the turnaround, they have, and I'm very superstitious so I'm knocking on this table, but they have run very high utilization. Obviously, been hit somewhat with the compression the light heavy spreads, but have performed very, very well and it is my expectation that after this turnaround, we are instituting a reorganization. There will be some further improvements, but we'll see the same type of thing in Torrance. I personally believe Torrance, if they do our job, will be the most profitable refinery in our system, and I am very confident we'll reach the $260 million at Chalmette and $360 million in Torrance.

[Philip Gresh:]

In the second half of this year, run rate?

[Tom Nimbley:]

Run rate, yes. And as we say, we've got a clear run rate in terms of what -- how we're running and utilization. And right now, even though we have these tight dips, which in fact -- sooner or later will widen back out. The demand pull is such that you can pass those course along into the crack, and we're seeing strong cracks.

[Operator:]

Our next question comes from Paul Sankey with Wolfe Research.

[Paul Sankey:]

Good morning all. We saw just a little bit of PADD 1 chat. It's pretty well publicized that there is some issues at PES. And also I heard, I think it was on the Valero that we were talking about the dynamics of Colonial and the economics of Colonial and Jones Act tankers, which was all quite interesting to me. I just wondered if you could give your perspective on what's going on in PADD 1.

[Tom Nimbley:]

Sure, Paul. I'll deal with the second part of it first. We obviously are very interested in seeing, but not surprised by, the shift in trade flow. And ultimately with the announcement by Colonial, I guess it was in May or June, I can't even recall, that for the first time in a very, very long time, there would be no allocation on both the mainline for gasoline and distillate. The fact is, the orb has not been open more often than not recently from the Gulf Coast to PADD 1. And that is principally driven by the fact that we've talked almost ad nauseam, North American and particularly US refining capacity has an advantage, advantage in complexity, advantage in crude cost to a certain degree, not as much as it was when you had to wide Brent-TI spreads, but still there, an advantage in natural gas. And it is in a position to have taken market share from the rest of the world, particularly in South America and other parts of the world. And that in fact is the case. The netbacks -- our netbacks exported out of Chalmette are better than moving it up the pipe to PADD 1. So ultimately, there's been a shift now that people are going to move their barrels to wherever they can make the most money. And that resulted in Colonial going slack. As PADD 1 recovers, if indeed that's the case and it has a pretty good crack right now, it will ultimately be the netbacks that govern where the barrels move. So not totally a surprise and I would expect to see that continue going forward, not necessarily that the lines will be slack, but that they'll move the barrels to where they can make the most money. We have read a number of things on PES, there have been rumors that -- well certainly the steelworkers have come out and said that because of the cuts that were made to their benefits program that they were contemplating labor action, don't know where that stands. There's also been, obviously recent discussions about how they are attempting to restructure and refinance their debt that is coming due next year. And they have a significant RIN headwind with the amount of gasoline and ULSD, as does Delaware City for that matter. So it'll be interesting to watch, but I am not going to speculate on what their immediate or even long-term future is going to be.

[Paul Sankey:]

And then to follow up, if I could would be just you mentioned a pathway to RIN sanity or whatever we want to call it, being cleared by the recent appeal decision. Can you just outline your best guess on what that pathway is?

[Tom Nimbley:]

I think the two paths are both still viable. I'll make a comment. I said I was, we were disappointed, and I was disappointed because we all told you we thought there was, I certainly did in some conferences, there was a greater than 50% chance and probably a 75% chance that we get some action by May either via point of obligation or a reduction in the RVO. We didn't get the point of obligation. We did get a reduction in the RVO, but it was de minimis and not material. That being said, it was pretty clear to me in visits with the EPA and the current administrator that they were cognizant that the appeals court hearing indicated that the judges were not necessarily convinced that the EPA was within its jurisdiction and doing what they did in using the waiver authority. And I think they probably, appropriately said let's table, put things to the side-line until we get that decision out. The decision came out earlier than most people expected last week, and I am optimistic that they still realize, they being the administration and the EPA, that this is a flawed system and it's creating winners and losers and it's not helpful to the consumers in the United States and that they ultimately will deal with this, but I said that earlier this year, and I was wrong.

[Operator:]

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

[Blake Fernandez:]

Sticking to the East Coast theme, Tom, you mentioned the compression in the heavy spreads and obviously, Maya has come in. I know there's a decent amount of Maya that typically you bring up to the East Coast. I'm just curious what your flexibility is to either shift toward light or access other barrels over there?

[Tom Nimbley:]

Yes. Actually, like we're not running very much Maya, in fact, we haven't run very much Maya in a number of, in about 2 years. We do run Venezuelan crude and we run a lot of Saudi crude and other Latin American, South American heavies. But your point is, let me make a couple of comments in this whole area. Obviously, light heavies have narrowed in. That is a supply-driven phenomenon, right? The OPEC, non-OPEC deal has resulted in mediums and heavies being backed out of the supply system. The conversion capacity growth, coking, if you will, in the former Soviet Union has increased. So we've had some clear supply issues that have helped cause the narrowing of those spreads and people have lightened up, including us, and I'm going to speak to that in a moment, which has produced less heavy fuel oil as well. I would say that if you look at the month of July, number 3 fuel oil, 3% fuel oil in New York Harbor traded at a diff of about $3.20 under Brent. So far this month, it's $4.70 under. So it's widened out. But why did it widen out? Well, for a variety of reasons, one of which is, Delaware City has coking, so does Paulsboro. We are spare in coking, because with the current crude diffs, with the current heavy fuel oil prices, the clean-dirty spread is not sufficient to justify coking economics. So we are actually making heavy fuel oil in Delaware. And when you start to make more heavy fuel oil, you'll pressure the supply side, and I think you will see some widening out of that diff. We've already seen it start, we believe that's transient. But to your point, our systems, and I'll just speak for the whole system so you folks have it. We could run hydraulically about 50% light crude. We've demonstrated that in the past when we had very strong economics. On Bakken, we ran Delaware at over 100,000 barrels a day at Bakken. But if you look at our system, there're only two refineries that we're going to -- in this economic environment, that we're going to look at possibly swinging back and forth. Toledo is a 100% light sweet, Torrance is basically going to run the crude they're running. It's a more isolated market with pulling down a lot of crude from the Valley. So Paulsboro, being in PADD 1, is going to run medium sours. And the reason, even though they've tightened in, Paulsboro has very strong lubes cracks that depends on medium sour crude and asphalt cracks that depend upon medium sour crudes. So it is really just Chalmette and Delaware City. We have increased the light runs in Chalmette by about 40,000 barrels a day over the last two months because LLS is now more attractive than Mars. And we've done the same, not to that volume yet, in Delaware. As I said, the step we took in Delaware was to spare coke and to make some fuel oil, but we are looking at lightening up Delaware as well. We're not going to get that to 50-50 split that we could hydraulically mainly because Paulsboro has got sound economics that continue to say run the medium crudes. That makes sense?

[Paul Sankey:]

Absolutely, that is very helpful. Thanks for the description. The second question, Erik, I don't know if you're able to quantify this, but, I guess, I'm just curious, the cash balance has obviously come down, debt is up, I realize that's a function of the heavy turnaround activity in the first part of the year. So going forward, spending, you've already kind of articulated what that's going to look like and we can make our own assumptions on the crack, but you did mention the working capital unlock. Is there any way to kind of help us frame up what kind of magnitude that may look like?

[Erik Young:]

Sure, so I think during the first quarter, we mentioned that we had built inventory to the tune of between $230 million and $240 million. We probably recouped about a quarter of that during the second quarter and the goal is to get back to essentially net zero on an inventory basis by the end of the year.

[Operator:]

We’ll go next to the line of Brad Heffern from RBC.

[Brad Heffern:]

Good morning everyone. Tom, you mentioned in your prepared comments the restructuring that you're planning at Torrance. Is that consistent with the sort of $50 million operating cost reduction target that you guys had in the past or is this something that's on top of that?

[Tom Nimbley:]

No. I would say it's consistent with the $50 million. Our goal is and has been and is once -- now that we've got this place up, to the get to sub-$7 a barrel OpEx in the refinery. This restructuring, which is not just a headcount reduction, there is a headcount reduction as part of it, but more importantly, it's getting the right people in the right boxes, in the right jobs and really focusing a little bit differently in the approach of being a merchant refiner and on reliability. So we expect to get that $50 million. We expect to get to below $7. And once we do that, we'll look for the next steps, but it's consistent with that.

[Brad Heffern:]

Okay. Thanks for that. And then looking at the Chalmette OpEx, obviously, it spiked at the end of last year. This quarter was a pretty good number. Is that sort of what we should think about as the run rate for Chalmette? Or is there more that could come on the cost-cutting side there as well?

[Tom Nimbley:]

No, it is more. We have said and we are going to be very persistent on the good folks of Chalmette who are very -- have done very well. That Chalmette is not as competitive as the rest of the competition in the Gulf Coast, and we want to get down to the sub quartiles. But you're right. I mean, they have, they've taken it to heed and we're guiding our cost down some but there is more to go.

[Operator:]

We'll go next to the line of Roger Read with Wells Fargo.

[Roger Read:]

Erik, if we could real quick, just come back to Blake's question on the working capital. Just looking at the balance sheet from December 31 to June 30, inventories look stable. And I recognize a lot of things in inventories when it's $1.9 billion. But if you've recovered a quarter and they're kind of flat over the 6 months, exactly what else has been going on in inventories that you can pull something out here post-turnarounds?

[Erik Young:]

I think, ultimately, we just, we've built throughout the course of the first quarter. We started to see a portion of it come back down. It's going to be a combination of price and volume. And so we're really focused, we know we are a few million barrels high in terms of volume and so ultimately getting those barrels back to our long-term targets at the end of the year, that's our goal and we think we're starting to see that roll through even as we're in the third quarter now.

[Tom Nimbley:]

To put this a little bit into a specific is obviously, the crude unit in Torrance was down for a good portion of the second quarter. And there was crude flowing through the pipe coming down to us that we have a contract to take and that was going out and being put on a VLCC and stored in, outside of Los Angeles Harbor. That's being drawn off right now as we speak.

[Erik Young:]

And, Roger, one thing to note to that. This is just for GAAP portrayable, but what you see on the balance sheet too on the inventory side includes the lower cost or market adjustment. So obviously, you're going to see those numbers kind of swing, swing back and forth depending on what hydrocarbon prices do.

[Roger Read:]

So that’s how the cash can be different than the look number there?

[Erik Young:]

Absolutely.

[Roger Read:]

And then, Tom, if you could, you've now done the big turnaround in Torrance, and I know this would be an easier question to answer in 6 months when everything has run for a while. But as you got into the crude unit specifically, given the amount of time between turnarounds there, can you give us maybe an idea of what you saw that was good? What was bad? What was potential for maybe a better performance going forward? And then what is the timing on getting the electrical substation online permit, obviously, that construction and availability?

[Tom Nimbley:]

Sure, I'm going to let Jeff deal, who's here with us in the epicenter of the refining industry, Parsippany, deal with the electrical question. But we got into the crude, it is interesting, the Chalmette crude tower that we get turned around had run even longer than Torrance, and we didn't find significant more scope than we had planned. That was not the case in Torrance and the primary, in Torrance, it was 10 years between runs. We're not going to run 10 years between runs, that’s not the way we want to run the system. But Torrance also runs a high-acid crude. The interesting thing about the SJV crude is it's heavy, but it's sweet, but it's got high naphthenic acid. So we found more damage in, particularly the vacuum tower, where a lot of that acid is concentrated, which caused us to do a little bit more work, but that work is behind. In fact, we basically have got a brand-new tuned up engine, and we already have seen, as I alluded to, some improvements in cut points, particularly between resid, the stuff that goes through coker and pulling gas oil out of that resid and sending it to the hydrotreater. We have seen some other benefits. We are waiting to get -- we wanted to do this reorganization, get that announcement out, we have done that. But we want to have whole plant lined out and then we're going to put it through a speed run and see what we've got, what the capability of it is, but there's clearly upside there and, as you say, we will be very much looking forward to reporting some good news in that regard in the next earning call. And with that, I will ask Jeff to comment on the electrical question.

[Jeffrey Dill:]

Yes, Roger. Look, I think, just from a scheduling perspective, we are spot on with what we've been saying for the last several quarters, project execution, later this year into '18 and probably the new connections coming online in 2019, and then you do the infrastructure within the refinery as you sequence turnarounds going forward. So we're spot on with what we've been saying all along and keeping the pressure on Southern California Edison to continue to move forward with project execution.

[Operator:]

We'll go next to the line of Doug Leggate from Bank of America.

[Doug Leggate:]

Thanks. Good morning everybody. A quick follow-up on the California question, if I may. Does this -- I mean, how far down the road does this get you to solving the reliability problem? I guess, this is kind of like a stage one work. What else needs to happen to get you where you want to be in terms of cogen facilities and so on?

[Tom Nimbley:]

It's a good question, Doug, and we're going to bifurcate it between me and Jeff. I wouldn't say -- this is clearly the most important piece that we're talking about, but it's not the first stage. We've had an enormous effort, brought in some specialty people that have worked for us before on a contract basis in Los Angeles. In fact, in the Los Angeles refinery, that's a P66 refinery, that had similar problems when Tosco acquired it, severe electrical issues, and helped solve it with a Tosco employee. And we have been working very cooperatively with Southern California Edison. Remember the two power failures were self-induced. It wasn't the equipment, it was human error or poor preventive maintenance. So we've attacked that pretty well, but that is not -- that's necessary, but not sufficient. So therefore, we go into the second stage and I'll turn that now over to Jeff to handle that part of it.

[Jeffrey Dill:]

Yes. Look, I think as I've said in prior quarters too, if you look at what we've been able to achieve cooperatively with Edison, a bit of a tribute to our technical team and theirs. There's just much greater cooperation, much better maintenance and attention to their infrastructure feeding the refinery. The new project is going to further enhance that reliability with the direct connection to their 220 system coming directly into the refinery. That project has a lot of support. We went to a meeting with the PUC jointly with Southern California Edison, City of Torrance, the South Coast Air Quality Management District and every agency, every stakeholder involved in this has a great deal of support for the project. So we think it's going to be very helpful. This was, by far, the most efficient and fastest way to improve electrical reliability of the plant. If you look at cogen or other alternatives, you're looking at a much longer lead time, you're looking at a much more complex permitting scheme and putting new emission sources in Southern California. This was by far the best option for the plant.

[Doug Leggate:]

My follow-up, if I may, is obviously there is a lot of uncertainty on RINs for sure, but there is also a lot of uncertainty on what's going on in Venezuela right now. And I'm just curious, when you acquired Chalmette, one of the key kind of thoughts there was how you could exploit different changes in feedstock where Exxon had not. What are your latest, what's your latest thinking there in light of the current situation? I'll leave it there.

[Tom Nimbley:]

Okay, well, there's no change in our view that the optionality is not only Chalmette, but also frankly Delaware, Paulsboro and even, to a degree, Torrance is a strength, and we factor that in when we look at a facility [indiscernible]. The Venezuela situation clearly is very fluid as a country that is in very deep economic situation. We have been able to get our contract supplies from Venezuela. We have not had any issues. That, so we haven't really been impacted in terms of avails. We have been impacted, as others have, in the sweets or the light heavy dip compression. Now going forward, the obvious question is having a referendum go-forward on Sunday, what steps in addition to what has already been done, would the administration take. If indeed they take a step that impacts the imports from Venezuela, there will be a short-term change in flow. The crudes that we are, we in the U.S. are running, and you all know how much we're running, we'll have to go somewhere else and it'll be a longer haul. It will go to Asia and then the crudes that will be backed out of Asia will wind up redirected here. And there will be a period of time where it's a little bit messy, but then it will ultimately equilibrate. And over the long haul, I personally think, I said, I think this is transient, WCS is going to come up more in volume. We're going to see other areas, the recent Mexico discoveries even though they are a year or 2 years or 3 years away, are medium sour and ultimately the sorties will step in behind Venezuela if there is a situation, in my belief, and help rebalance that market.

[Doug Leggate:]

Tom, does it change your view of the sustainable EBITDA out of Chalmette mid-cycle?

[Tom Nimbley:]

No. Not at all, Doug. We made, we had a pretty good quarter and our crude diffs were narrower than they really would be if we had a normal market, if we didn't have the impact of the OPEC, non-OPEC changes that I believe with the project coming online and the way Chalmette has done and the other crudes that we've been able to source in. And again, we have not yet pulled the trigger to anywhere near the level that we expect to on exports. We would love to be exporting more barrels. Logistically, we're challenged in that regard. That is going to be solved with this crude tank coming on at the end of October. And if the market stays where it is right now, and I don't believe there's any chance you're going to see a resurgence in refining production in South America, Latin America anytime soon. We think that's going to be a plus for the Chalmette refinery as well.

[Operator:]

We'll go next to the line of Neil Mehta with Goldman Sachs.

[Neil Mehta:]

Tom and Erik, I wanted you guys to talk a little bit about dividend sustainability as you see it. Obviously, the market is strong right now, but cash generation was an issue for the first half of the year, recognizing there are turnarounds. How do you think about the importance of sustaining the dividend? And then corresponding with that, how do you think about using the equity markets, if you get the right price, to maintain the strength of your balance sheet? So I wanted to talk about those two balance sheet related questions.

[Tom Nimbley:]

Let me handle the dividend one. I'll let Erik chime in on the equity. The whole key here is for us to run, we all understand that. Our fervent belief is this -- the power of this machine will have to be -- it is up to us to demonstrate it in the third quarter and in the fourth quarter as we go forward because the turnaround headwinds are behind us, and we believe, with our own forecast, that we're going to be able to generate sufficient cash to; one, continue to pay the dividend and it is important. Our shareholders want RIN while we're trying to get this share price up, and I hold a lot of shares, and I want the RIN. So -- and we believe, we're not jeopardizing the balance sheet as we go forward with our forecast and continuing to pay the dividend. At the same time, we have to demonstrate that and -- so my belief is, we're not -- we're going to be able to sustain the dividend as long as we do our job. Erik, you want to weigh in on the equity side?

[Erik Young:]

Sure, and I'd just follow up to Neil with, internally, we spent a lot of time focused on operating expenses, CapEx and working capital. And clearly the first half of the year, we saw things go a little bit haywire in terms of inventory because we wanted to make sure that all of our customer contracts were filled. We didn't have the market that we anticipated going into 2017. That being said, as we sit here today in August, second half of the year really looks pretty good. So we've got $350 million of pre-payable debt that's on the balance sheet today. So as we start to generate free cash flow, the goal would be to build the cash reserves back up and ultimately delever the balance sheet as we go. We think ultimately that should be received well by the public equity market. We've done, outside of our initial IPO, we've issued equity twice, and we really issued it once in conjunction with a set of transactions for both Chalmette and Torrance. And the second time, quite frankly, was to make sure that we had a strong enough balance sheet to be able to weather what was coming at us. We think that was the prudent move back in December and ultimately, as we go, there may be other opportunities to acquire different assets. And at that point in time, I think, we will evaluate accessing the capital markets on the equity side. But we feel pretty good about where we are today as we sit here and look forward from a dividend perspective.

[Neil Mehta:]

That brings me to my follow-up. This is probably the longest we've been on a call without having asked you guys about M&A. So just your latest thoughts in terms of whether acquiring assets is still a key objective of the company? I think you've made the comment in the past that you want to have multiple assets in different regions that you operate in and then just how you think about that from a timing perspective knowing that you're still trying to drive the full synergies at both Chalmette and Torrance?

[Tom Nimbley:]

Absolutely, the strategy has not changed and we've spoken to it and you obviously understood it and that remains. I mean we want to be hedged, we want to be hedged from a crude standpoint in terms of our ability, optionality on crude, but we want to be hedged geographically and candidly particularly in PADD 5 and PADD 3. It's good to have effectively an insurance policy, not that we expect our existing refineries not to run. But PADD 3, you could have a hurricane season and some things could happen. So the strategy is exactly as you said, as you recall. We want to grow, we will focus -- we're not going to be able to buy anything in PADD 1, and we're probably not going to want to get into bidding war on PADD 2, given where WCS is as satellite pad. So we're going to focus on PADD 3 and PADD 5. There are some opportunities but they haven't really come to the forefront in terms of any immediacy. And we were fine with that because as you also recognized and said that we had stuff we were working on in the first half. And if our projections are correct, we'll be in a position to take advantage of those opportunities when they get put out on a table, but the strategy remains exactly as you describe it.

[Operator:]

And we'll go next to the line of Paul Cheng from Barclays.

[Paul Cheng:]

Erik, just curious that from a cash spending standpoint, the RIN obligation that you guys, are you up to current or that's a liability sitting on your balance sheet?

[Erik Young:]

No, we're essentially ratable. We've tried to be ratable here as we go. We did, we've noted, I think, during the first quarter call what our normalized number would have been. But for the second quarter, we're ratable, and we're ratable kind of as we sit here today.

[Paul Cheng:]

And referring to the cash, not in terms of expense from the P&L, but on the cash spending, that is ratable, right?

[Erik Young:]

Yes.

[Paul Cheng:]

And then in Chalmette and Torrance, the second quarter, the cash OpEx is $81 million and $118 million. Erik, is there a number that you will be able to share in the second half, the local run rate we should be looking for those two on the cash cost?

[Erik Young:]

I think, ultimately, the goal is to get Torrance to the position where they're probably in the $35 million per month of operating expenses, that's really the goal. The goal as we go, and I think Tom mentioned for Chalmette that $4.65 per barrel number that we saw during the quarter is a good number. It's better than where we've been, but we want to see that kind of tick down lower sub-$4 a barrel.

[Paul Cheng:]

But do you believe that in the second half that you can achieve that? Or that is a more long-term aspiration and objective?

[Erik Young:]

I think the goal is that we will see that number start to tick down obviously on a per barrel basis. It will be determined by the dominator, so depending on how hard we run. But I think in terms of the excess operating expenses that we saw, for example, in Chalmette in Q4 of last year, we do not anticipate those types of events as we go forward. We've got a fairly disciplined strategy on the operating expense side of things and the refinery has taken all of the advice from corporate to make sure that those operating expense numbers get lower.

[Paul Cheng:]

And Torrance, because of the low run rate at, it's a little bit difficult in terms of absolute number. Is this something that you can share in terms of Torrance? What is your unit cost expectation in the second half?

[Erik Young:]

I would tell you that the goal is to get Torrance on a monthly run rate to be in the $35, $35 million per month run rate from an operating expense standpoint.

[Tom Nimbley:]

And on a unit basis, we're going to, we expect to be approaching and perhaps getting below that $7 a barrel number now that we've got high utilization, we've got good cracks. And as long as the cracks are there, we're going to be able to, we should be able to run so we should get there reasonably quickly.

[Paul Cheng:]

Tom, a final one. It seems now in California that they're going through the commenting period about hydrofluoric exit. Just, nothing that will happen, but if in the event that they go crazy and go ahead and ban the HF. What is the option for Torrance and how expensive is it?

[Tom Nimbley:]

First of all, let me say, the prospect of California doing something crazy, I can't conceive of that. But perhaps it might happen. I'm going to turn it over to Jeff in a moment but there are some things -- obviously, this is a political situation, there is a lot of rhetoric going on. But we've made rather significant progress in working with the South Coast as well as the fire department and other agencies. Jeff will talk to this, but actually the alliance that is raising this issue, the community alliance came out yesterday and said they recognize that there are only 2 technologies, some of this new technology that was being fostered as being the answer to all of this stuff is not commercially viable. So now you're down to again sulfuric acid and HF, and as we've said before, more than half of the alkylation units in the world are HF units and their safety record has been very, very good. So we think this is a red herring, but I'll turn this, the second part of your question over to Jeff.

[Jeffrey Dill:]

Yes, Paul, look, I think to follow up Paul's or Tom's comments, the legislature in Sacramento, the City Council in Torrance, a number of bodies that matter have realized that doing something on a hydrofluoric acid phase out is just not the right answer. And so we're left with rule-making at the South Coast Air Quality Management District, which is charged with the air quality in Southern California. And if they go with a phase out, they're basically forcing Valero and Torrance to switch to sulfuric acid, which actually increases the emissions in Southern California and increases truck traffic because of the regeneration that you have to factor into it. So it's really an outcome I don't think anyone believes is in the best interests of anyone in Southern California to pursue this. We've provided data to a firm called Stillwater and Associates as has Valero and I think their number for the two plants to switch from HF to sulfuric is in excess of $1 billion. So it just makes absolutely no sense and that doesn't even capture the lost productivity you're going to have while you're trying to do a conversion. So it's just -- it's really just not a feasible path to follow at this point, Paul.

[Paul Cheng:]

Jeff, you say $1 billion is the two plants combined. So each one is about $0.5 billion. In other words that -- if they go crazy and ban it, it's unlikely that you're going to make that investment or do you think that you may still make that investment?

[Jeffrey Dill:]

We haven't thought through that scenario. It's just -- as you captured it Paul, it's a large number. I don't know that it's exactly 50-50 between the two plants. But it's just a scenario that just doesn't make sense.

[Operator:]

[Operator Instructions]. We'll go next to Chi Chow from Tudor, Pickering and Holt. Please go ahead.

[Chi Chow:]

Hi, thank you. I've got a couple of questions back on the heavy crude market. Tom, you've kind of mentioned this a couple of things in the call today. But how do you see WCS differentials trending going forward here? And what spread do you need to make rail deliveries work again?

[Tom Nimbley:]

Following the forecast, and we believe it may take a little lot longer than some of the folks have been saying. We believe WCS-TI will stop winding back out as some of the new production comes online. Of course Canada will continue to be -- have some limitations on its ability logistically to move the barrels. So we would expect to see some widening back out to $14, $15 a barrel, late 4Q, first quarter. And if you believe some of the forecast, you get back to the $18 number sometime mid-next year. We will not likely be running a lot of CS. We will run into fourth quarter and the first quarter because the economics improve. Of course, you're effectively not making RBOB. You get into the lower, the higher RVPCs and then Canadian crude actually is a debit, has more of a debit in the summer at Delaware than in the winter. So we will be running some of that. But our focus is really on some of these other crudes that are being produced, send it and the heavier crudes to the remote areas of Canada. If we get to $16 or $15 or $14 WCS, WTI with a $2 or $1.50 TI Brent spread and the differential we get for those crudes relative to WCS, they will be economic, and we will be railing them in to Delaware once we get to that level.

[Chi Chow:]

Have you seen railcars come down with kind of slack capacity the last couple of years?

[Tom Nimbley:]

Not really materially. That's going to change.

[Chi Chow:]

And then longer-term on the heavies, what do you think the impact will be on the market with the IMO bunker field spec change upcoming here?

[Tom Nimbley:]

It's always good to serve the best, save the best question for last. I actually believe, I don't think this is going to get delayed by the way. At least out intelligence suggest it isn't and when you look at it with all of the pressures and all of the statements that are being made by some of the European countries, particularly on climate change and the Paris Agreement, it's hard for me to see how they can come in and say, well, that's okay. We can continue to burn a fuel on all of these ships that's 3.5% sulfur. So I don't think it's going to get delayed. And it's going to be significant. It'll be for a period of time. The options are there. And you know what they are. The ship owners could put scrubbers on them. They don't seem to be inclined to be getting a space to allow that to happen. They could go to LNG. I don't think they're going to do that very quickly. So my guess is they're going to get, when we're get into '19, people are going to start being faced and confronting the fact that this is going to happen and you're going to have spreads widened out and LS, low sulfur fuel obviously, is going to be more valuable than current high sulfur fuel oil. You're going to get a pull on diesel, significant pull on diesel to blend down, say a 1% fuel oil that a light sweet crude refinery produces today. But you got to turn it into 0.5% and the way you do that is you throw in effectively a half a barrel of 15 parts per million diesel. So you're going to get the diesel demand going up, you're going to have stranded heavy resid from refineries that don't have coking and that's going to widen out the clean dirty spread, improve coking economics and the lights, in my opinion, the light sweet heavy sour differential will widen back out to a very attractive number. So I think it's a very, very significant thing going forward. And as we've said, we might not be completely dispassionate about this because PBF is in a very, very good position with 4 of our refineries being coking refineries and Toledo, which doesn't have a coker, cracks all of its resid and it's completely insulated from this.

[Chi Chow:]

But theoretically though, wouldn't all the cokers globally just still run full because you all have the ability to upgrade that barrel to other products. So even in that scenario, would the spread still really widen out?

[Tom Nimbley:]

I believe it will, because I don't think you -- you're going to have to build more coking if you really want to take all of this resid and turn it. We will look at, for example, the idle coker, it's not a big coker at Chalmette, it's 12,000 barrels a day. We're going to say -- we didn't think we were going to -- have an incentive to start that up, we'll look at it. What will happen is as soon as this hits, when you realize that you don't have a home, if you don't have a coker and you're making a 3.5% fuel oil with your resid, you don't have a home for that resid. So you're either going to have to sell it to somebody who's got a coker or you're going to try to get into the asphalt market. I do believe the asphalt market will get pretty saturated and you'll probably see some compression on margins there. But there's not enough coking capacity to deal with the sheer volume of resid. And unless they go to LNG or scrubbers, you're going to have a period of time where those light heavy spreads are going to widen out. That's clear to me. And then, you'll have economic incentives to put scrubbers on and do other things and maybe in five years, things will equilibrate back down. But in the short term, I think it's a significant legislative step.

[Chi Chow:]

I had actually one more question back on RINs. Can you talk about maybe some of the commercial or other strategies you're undertaking to reduce that exposure? And do you have a specific target? I know it fluctuates with RIN prices. But any specific target on reducing your RIN expense?

[Tom Nimbley:]

Let me take the first one first and I don't know that -- we just want to -- we've got a number of methods that we're targeting to get the RIN cost down and hopefully, the number will show what it is. And that's non-legislatively or administratively outside of the efforts that we're trying to influence strongly and a lot of effort in Washington D.C. But obviously, one first thing that we're doing is trying to get up to the level of exports that we think we can achieve. We talked about this crude tank coming on in October. I will tell you that our commercial organization is already in discussions with customers that we will have lined up in advance so that we can -- the day that the oil goes into -- that crude oil goes into that tank and the dock space becomes available, that we will have customers lined up and ready to go to start opening the gate, as we said, to get Chalmette exports up. We're exporting out of Toledo, believe it or not, by rail into Canada. We'll be doing some exporting out of Torrance. And if the ARB is there, we'll do it on the East Coast. The second big step is collectively now we're approaching 300,000 barrels a day of gasoline and distillate movements into the wholesale value chain, the wholesale market. And we're capturing some RINs benefits by doing that blending itself. So those are the two primary things that we're doing internally. But in addition, obviously, we have a massive effort underway in Washington DC and with our local politicians, Senators in our states, to try to get this thing pushed over the finish line, preferably either point of obligation or the passage of what is called the Flores bill which recognizes as the blender.

[Chi Chow:]

And what's the export volume that you're expecting out of Chalmette out of the gate?

[Tom Nimbley:]

30,000. Like I said, we did about 15,000. Once we get there, we're going to get to 30,000 and then we'll see where we can go from there.

[Operator:]

And we'll take our final question from Faisel Khan from Citigroup.

[Faisel Khan:]

Just two questions. One is, are you planning or what's your philosophy right now on the drop downs into the MLP?

[Erik Young:]

I think, Faisel, we've been fairly vocal that we don't give any guidance in terms of timing around drop downs. We've clearly had 2 big organic projects underway that are going to start coming online here during the second half of the year that will start to generate free cash flow for PBF Logistics. So that in conjunction with the Toledo Truck Terminal that we acquired during the second quarter, those are incremental EBITDA i.e. incremental distributable cash flow that will start to really flow through the system. So we feel good about where the distribution is today. And ultimately from a drop-down perspective, I think, we've also provided some guidance around what is the, what are the easiest suite of assets to drop down. And so we did the first half of the Torrance Valley pipeline during the second half of 2016. Things that have very high basis from a parent company perspective to avoid any types of tax consequences would appear to be probably the most logical things to be dropped in the near future.

[Faisel Khan:]

Okay and then just last one on Chalmette. Because and in the first quarter you guys mentioned that once you got reformer units sort of up and running that the yield improvements would give you about $70 million uplift in margin and then some of the things you were doing around the storage in the dock could give you about $20 million of sort of uplift, a reduction and sort of demurrage sort of cost. I mean, are you guys there yet? You were also talking about getting down to $4 per barrel on operating cost. I just want to make sure, I know exactly what we saw in the quarter but are we, how far are we to getting to those numbers?

[Tom Nimbley:]

Well, for the 2 projects, as I said, we call it the PRL project. But basically, it's the ability to take naphtha, which we're selling sour naphtha, which we are selling in to the marketplace today because we don't have adequate clean treatment or reforming. And by the way, I'll just add, that's the problem for the U.S. You can lighten up your crude slate and run more and more light crude, and you might be able to get it into a splitter that you put on or into a crude tower. But the reforming capacity in the United States is pretty much full. So as you, the incremental naphtha coming off of those runs tend to go into the market. And we, in fact, are selling it into the market today. We will now be able to not only not stop, we'll stop selling the naphtha we are selling and we'll treat it, get the sulfur out and then we'll put it in a reformer, turn it into high-octane gasoline and there is a corollary benefit with the light ends plant that comes along that gives us a better split between propane and propylene that has some margin contribution. But to your question on that one, the $70 million is there, it's real, and we haven't gotten any of it yet. Because that unit, the one unit is online, so, with taking the sulfur out of the naphtha. But in the next 2 weeks, the entire complex will be up. So the burn rate, if you will, starts in about 2 weeks that we should be contributing $70 million more a year. The crude tank is an October event. And again, you've got it right, it's about $24 million of incremental EBITDA, which is a combination of reduced demurrage, export flexibility and more crude optionality but that is all in front of us. None of that's in the second quarter for either of the 2 projects.

[Operator:]

At this time, I would like to turn the call back over to Mr. Tom Nimbley for closing remarks.

[Tom Nimbley:]

All right. Thank you for your time and attention. And we hope to have very good results for you when we talk again after this quarter. Thank you. Have a great day.

[Operator:]

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