PBF Energy Inc (PBF) 2016 Q2 法說會逐字稿

Good day, everyone, and welcome to the PBF Energy second-quarter 2016 earnings conference call and webcast.

(Operator Instructions)

Please note today's call may be recorded and I will be standing by if you should need any assistance. It is now my pleasure to turn the floor over to Mr. Colin Murray, Investor Relations. Sir, you may begin.

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

Before getting started out 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 described in our filings with the SEC.

As also 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 but they are non-GAAP measures and should be taken as such. For reconciliations of non-GAAP measures to the appropriate GAAP figure, please refer to the supplemental tables provided in today's press release.

It is important to note that we will discuss fully-converted earnings information and results excluding special items. Our GAAP net income or GAAP EPS figures reflect the percentage interest in PBF Energy Company LLC owned by PBF Energy Inc. We think adjusted fully-converted net income and EPS are meaningful metrics to you because they present 100% of the operations on an after-tax basis.

For the second-quarter 2016, PBF Energy reported a net income of $120.6 million and net income attributable to PBF Energy Inc of approximately $103.5 million and earnings per share of $1.06. As a result of rising hydrocarbon prices during the second quarter of 2016, we generated a non-cash lower of cost or market, or LCM, after-tax benefit of approximately $95 million. And our comments today will exclude this special item from the discussion of our results.

I will now turn the call over to Tom Nimbley.

Thank you, Colin. Good morning, everyone, and thank you for joining us on today's call. I would like to make a few general comments on the second quarter and then comment briefly on our specific regions.

Our refineries ran better than last quarter, generating positive results, but as you all know we face significant -- several significant -- headwinds. The flat price of crude increased an average of $12 or approximately 35% versus the first quarter and other inputs such as gasohol, became very expensive in the quarter.

Differentials from medium and heavy sour crudes contracted in large part due to the supply disruptions caused by the Canadian wildfires. The wildfires also caused price spikes in the synthetic crude market as supply was shut in and regional refineries sought alternative barrels. The result is that our refining system saw increased input costs across the board, while at the same time being negatively impacted by event-driven contracting differentials.

On the product side, as a result of the rising flat price, realized margins on low-value products across our system declined versus last quarter. This had a more pronounced regional effect on our coastal refineries with their heavier input slates.

Additionally, persistent above-average gasoline and distillate inventory levels continued to pressure product margins. Margins on chemicals and jet fuel were also particularly weak in the second quarter.

Before Eric provides our financial highlights, I'd like to briefly comment on our regions. Despite some initial stumbling coming out of the first quarter, the East Coast delivered positive results. The Gulf coast and Toledo overcame wildfires and minor operational (technical difficulty) collaborate relatively well.

Toledo was able to maintain throughput, in part as a result of the installation of a new crude tank that we put into Toledo in 2014. This incremental storage capacity and the installation of additional desalting capability allowed Toledo to reduce its intake of synthetic crudes and process of blender crudes that had not been previously possible.

With that, I will turn the call over to Eric to run through some financial highlights before I close out our prepared remarks.

Thanks, Tom. Today we reported second-quarter operating income, excluding special items, of approximately $77 million and adjusted fully-converted net income of $14 million, or $0.14 per share on a fully-exchanged fully-diluted basis. Including in our results were net after-tax charges totaling approximately $6 million, or $0.06 per share related to acquisition expenses and accelerated equity-based compensation expense. As Collin mentioned a moment ago, these figures exclude the non-cash LCM benefit and the GAAP reconciliations can be found in the tables accompanying today's press release.

For the second quarter, G&A expenses were $43 million, depreciation and amortization expense was $51 million and interest expense was approximately $36 million. PBF's reported effective tax rate for the quarter was approximately 38.8%. For modeling purposes, you should continue to assume a normalized rate of 40%.

Our RINs expense for the second quarter was $93 million, bringing our year-to-date expense to $160 million. Refining and corporate CapEx was $95 million.

We are pleased to announce our Board has approved a quarterly dividend of $0.30 per share. Also of note, today PBF Logistics announced a distribution increase to $0.43 per common unit.

With the addition of Torrance, several components of our previously issued guidance have changed. We now expect CapEx for 2016 to be approximately $500 million to $525 million. General and administrative are expected to be between $145 million and $165 million. And interest expenses is also expected to be approximately $145 million to $165 million.

Full-year depreciation is expected to be approximately $220 million to $240 million and refining operating expenses should be in the $5 to $5.25 per barrel range. Feedstock in production percentages at our refineries should remain broadly in line with their historical averages, with some departures for turnaround activity.

Expected throughput rates are included in today's press release and reflect our current expectations for the remainder of the year, including the impact of the SEC turnaround in Paulsboro. The turnaround should commence late in the third quarter and is expected to last approximately 35 to 45 days.

Shifting gears, Torrance is designed to process a slate of heavy high-sulfur, high-TAN crude oil and yield a high percentage of gasoline. Specifically, we expect to a run a slate that is approximately 80% heavy, 8% medium and 12% of other inputs. Primarily, the slate will be comprised of California heavy and medium crudes delivered directly to the refinery via pipelines and supplemented with imported heavy and medium varieties delivered through the Ports of Los Angeles and Long Beach.

This is slate should result in a yield of a approximately 70% gasoline, 20% distillates, 95% of which is comprised of jet fuel and marine diesel and approximately 13% other products which includes LPGs, fuel oil and other low-value products. As a reminder, Torrance's high-complexity processing capacity generates a 3% volume gain.

The effect of pre-funding the Torrance acquisition with a working capital-related draw on our resolving credit facility resulted in quarter-end liquidity of approximately $1.9 billion. Similar to the Chalmette transaction, we intend to delever during this quarter through positive working capital.

With that, I'll now turn the call back over to Tom for his closing remarks.

Thank you, Erik. Going into the third quarter, our refineries are running well and we are focused on the parts of the business we can control. Through a combination of our East Coast and Gulf Coast operations, we have been successful in expanding into additional product markets and increasing our netback pricing to the refineries.

On the East Coast, we are positioning ourselves to become an importer and distributor of ethanol in the region which over time should reduce our own ethanol funding costs. On the Gulf Coast, we continue to move into the export market as opportunities arise.

Consistent with our approach of investing in low-cost, high-return projects, we are moving forward with the construction of a new crude tank which will improve crude logistics, improve product export capability and reduced demurrage cost. Additionally, we are progressing with the project to restart the idle naphtha hydrotreater, reformer and light ends recovery plant. This project will allow us to produce high octane, ultra low sulfur reformate blend stock and chemicals from unfinished naphtha. We expect that both of these projects should be completed by mid to late 2017.

Moving on to our newest region, after some initial hiccups the Torrance refinery has run reasonably well, averaging above historic throughput rates for the last four weeks, or the four weeks under our ownership. We are making significant headway in increasing our RAP business and this should help us achieve higher clean product netbacks for the refinery and also reduce our RIN exposure through increased blending.

With regard to RINs I should also point out that Torrance, as Erik mentioned, produces a significant percentage of gasoline which is being blended as I mentioned. And Torrance's distillate production is primarily jet and marine diesel which is not subject to a renewable obligation.

RINs continue to be a headwind for the refining industry and I would like to echo the sentiment of many of our refining peers, the RSS system is absolutely broken. The EPA has the point of obligation in the wrong place and the goals of the program are not being met. While a complete overhaul of the statute is needed, we feel that as a minimum, the EPA should move the point of obligation to where the RIN is generated as is done in California with AB 32.

These other things we can control. Many of the market-related challenges from the second quarter appear to be carrying over to the third quarter. While demand continues to be reasonably strong, and there appears to be ample supply of medium and heavy sour crude oils, high utilization rates have resulted in persistent overhangs of both gasoline and distillate stock, which in turn puts pressure on refining margins.

As we discussed in our press release, we have lowered our throughput guidance for the third quarter. Refinery utilization rates have been bolstering inventory levels despite the best efforts of the driving public in to travel more miles by road than ever.

With market supply outpacing demand, production is going into tanks and not being sold. It is very difficult to realize margin on a product that is not being sold. We do expect that the market will rebalance from this state of oversupply.

Operator, we completed our opening remarks and we'll be pleased to take questions.

(Operator Instructions)

Jeff Dietert, Simmons.

Good morning. The question is on Torrance. Thanks for the discussion of feedstock and yields in your opening remarks. I realize it's early but I was wondering if you could share your impressions of the first 29 days of ownership, anything that has surprised you relative to when you committed to purchase the facility late last year.

I think the fact that we've been able to move up the product disposition over the rack by some of the planning that our commercial folks has done has not necessarily been a surprise but it's certainly something that we believe is going to be beneficial. As we've said before, the Torrance refinery, at least it is my belief, that this is all about running this plant reliably. And that is something that we are singularly focused.

This is one, if not the most powerful refinery in California, certainly in the top two or three. With its complexity and its ability to run relatively distressed a 16-degreee API crude slate, perhaps the heaviest crude slate in the country. So we see the potential.

If anything, we are more enthused about some of the things that we can do. The product yield, as Erik said, 85%, 86% clean product yield on a 16-degree API crude slate with a 3% to 4% volume gain. This is a toy kit that is very, very powerful.

So we are comfortable, we are optimistic. We believe that the $360 million number that we gave you when we get a full-year run rate on this thing is achievable. And frankly, there's other things inside the fence line that our management team that we put in place, is now starting to identify which could have further upside. Basically, self-help opportunities.

Thanks. And with regard to Chalmette, you highlighted the construction of the new crude tank and the restart of idled naphtha hydrotreater reformer and light-end recovery plants as top priorities.

Could you talk about the potential capital investment on these two projects? And perhaps a ballpark on expected returns? And perhaps talk about your decision to proceed on these projects first, relative to some of the other idle units at the facility.

Sure, good question. Take them in sequence. The crude tank, which is a 450,000 barrel crude tank, is going to cost about $29 million, notionally $30 million of capital. And we have $24 million of EBITDA against that on an annualized basis.

The EBITDA contribution really comes from multiple factors. First of all, one of the upsides that we are pushing very hard in Chalmette, I think we've added six or seven crudes to the operating envelope since we have taken that were not run, previously approved to be run. There is benefits in crude optionality that have yet to be achieved, but frankly we are constrained on logistics in Chalmette.

So the crude tank will give us, as we've mentioned in Toledo, another arrow in the quiver to attack that. The second thing, I said we're constrained on logistics. The docks in Chalmette have a very high dock occupancy which leads to increased demurrage.

We've got significant demurrage savings. We've got significant demurrage costs and there will be significant demurrage savings associated with this project. And very, very importantly, we want to get into the export market.

We see the benefits of getting to that channel of trade, both from a RINs perspective and an overall netback standpoint. To do that, we have to de-bottleneck the docks. And by getting more haulage to be able to pump off crude ships faster, that'll unload the docks and effectively look at it as simplistically putting a clean product ship at the dock to be able to export.

So those three things we think is a very resilient project. One of the reasons we took that one first is, you can really count demurrage, right? It's not mystery management.

There's some big demurrage bills there so they're very hard credits. But we remain very comfortable with that project.

The second project which is basically starting up, an idled naphtha hydrotreater to take sulfur out of reformer feed. An idled reformer to turn that material, as I said, into high-octane low-sulfur reformate.

And a gas plant -- I don't want to get into the weeds in refining -- but Chalmette has only one gas plant operating now which means you have to put your gases from the cat cracker in with the gases from the hydrocracker. And you are mixing things that really cause you to lose margin. By starting up this gas plant we'll be able to separate that out and increase the amount of refinery grade propylene we make.

So all of those benefits are there. This is a pretty simple project as well in terms of looking at the economics. Right now we're forecasting that it'll cost about $70 million to bring the units back online, and there's about $70 million a year of run rate EBITDA.

Thanks for your comments, Tom.

Phil Gresh, JPMorgan.

Hi, good morning. First question is, you gave the CapEx guidance for the year.

Could you help us think through how the normalized run rate would look in 2017 with a full year of Torrance? And then break that down between the sustaining number that you see to run the assets? And then you are talking about some investment capital at Chalmette, for example, so break it down between sustaining and growth moving forward.

I think what we would say, Phil, is consistent with the $475 million to $500 million that we previously guided to, that was comprised really of three buckets. So call it $200 million of more or less sustaining or maintenance CapEx, $200 million of turnaround and then roughly $100 million of discretionary. Included in that sustaining and maintenance, we did have roughly $75 million to $100 million of environmental compliance related to tier 3 gasoline.

With the inclusion of Torrance, we're assuming between $25 million and $50 million of incremental CapEx for the back half of the year. That also includes CapEx that we are going to spend related to essentially integrating both Chalmette and Torrance into the PBF system. So it's essentially corporate CapEx.

Going forward you should probably think that somewhere in that range is going to be consistent with what we're going to see. It is unclear as to what type of environmental regulations will come down the pipe over the next few years. But conceptually we've really been trying to help people understand that on a run-rate basis, we're probably circa $500 million, all-in.

Some years there will be larger turnaround buckets. In other corresponding years there could be much lower turnaround buckets and you have higher regulatory CapEx.

But across the board for our system, think about the legacy assets over a multi-year period having between $80 million and $90 million, including turnarounds. Chalmette is probably in the $90 million to $100 million a year and Torrance we expect between $100 million and $150 million.

Okay, that's helpful. And then could you give us your latest thoughts on what RINs would be on a run-rate basis, including Torrance?

I think as we sit here today, if we take the current price which your guess, I hate to say, is as good as ours in terms of what that RIN cost is going to be through the end of the year, we're forecasting based off of what we've already spent which was roughly $150 million, $160 million. Probably a total bucket for the year, including Torrance, of between $400 million and $425 million.

Got it, okay. And then the final question is around Torrance, how do you think about the potential EBITDA today? You had given a number a while back but just refresh us on that, factoring in the latest thinking around RINs there and what you see from an operating potential.

We put out a number of $360 million EBITDA on an annualized basis, we're certainly comfortable with that. As I mentioned in my remarks, I think we are seeing some opportunities that could have some upside on that. It's too early to declare victory, frankly, we've only owned it for four weeks.

It's lined out a little bit right now but you all know the history that plant has. So as I said, it's absolutely going to be a function of our ability to run the plant in a safe, reliable and environmentally responsible manner. That is priority-one for the Company, to be honest there, maybe after protecting the balance sheet.

But we are comfortable with the $360 million and we think there's upside from there.

Okay, thank you. I will turn it over.

Blake Fernandez, Howard Weil.

Yes, good morning. Tom, I was hoping you could maybe help me out with a little bit of a macro question here. It looks like as of late we've seen some increased imports into the East Coast, gasoline imports in particular, into the East Coast. I'm curious if you think that's a structural phenomenon or something that is going to prove to be a little bit more transitory?

I don't believe it's structural. I do think there's some benefits are some benefits -- some impacts associated with relatively cheap freight rates that have lowered the costs of transport. But I really don't think that's a structural change.

We remain in a position where the import market, the people who are sourcing those barrels have some competitive disadvantage. They narrowed at some, natural gas pricing between Europe and the US, et cetera. But I don't believe that is a structural.

Frankly, it's an interesting market, you all see it. The Gulf Coast [ARB] to the East Coast is shut to the Midwest. Hopefully we're going to see some rebalancing.

I expect to see that but I don't think that's a structural and I think it is transitory.

Okay, thanks. And then the second question, a little bit more specific to PBF, I guess this is more 3Q-related but you mentioned the flat price being a headwind at 2Q. Now we're starting to see prices roll over. So can you confirm that should turn into a tailwind into 3Q?

And in conjunction with 3Q, you mentioned the guidance coming down. Does that contemplate some of the economic run cuts that you guys could potentially be seeing?

Yes, first of all, yes, you're absolutely right. What goes up, comes down. We've had a rather significant retrenchment here, obviously, in flat price.

To the extent that remains the case, much as it did last year, that takes a headwind to a tailwind. We do produce, as you all know, particularly in our coking refineries, which four to five are coking refineries, a significant amount of petroleum, coke, sulfur and carbon dioxide, et cetera, that just doesn't move at all with flat price. So as the flat price comes down, it's a margin benefit for us.

The throughput guidance has been reduced. Basically, some of you have heard me opine on this before, incremental economics is the bane of the refiner's existence and in fact may become the bane of the producer's existence. When we have situations where people are looking at making some money on an incremental barrel and the barrel's going into a tank, and you're not being sold.

You can pretty much guess that will have a negative benefit on the forward market in terms of cracks. We have actually cut maybe, what, 6%, 7% of our crude runs already. And that guidance has been put into what we put out in the third quarter.

Thank you, appreciate it.

Evan Calio, Morgan Stanley.

Good morning, guys. Thanks for the update on the new assets, that was helpful. My question is a follow-up on your RIN commentary.

In 2013 I know you guys were part of the solution. And I refer to that first real RIN scare via political pressure. It's an election year which is different.

Any progress or do you guys see a way out or a receptive audience? Or really a path for some solution here, whether it be via RFS or even an alteration of the enforcement point?

My own opinion is the probability -- let me say that there is a renewed initiative. My high school classmate and good friend, Jack Lipinski, said it very well yesterday. The status of RINs and RFS -- and there is a renewed initiative between the AFPM, particularly on moving the point of obligation.

The reality is we're three months away from a presidential election and I don't think there's going to be anything that is done in that interim period. I hope I'm wrong. But beyond that I think there will be something done.

It was rather interesting, the individual who is actually running this part of this program for the White House in conjunction with the EPA -- I can't remember her last name, Heather something -- she came out recently and said this program -- she's no longer in the job -- but this program has to be fixed. The first point, I think that we'd love to see the whole thing be redone or made over. Probability of that, with the dysfunction that exists in Washington DC and likely will continue to exist, is remote.

What we really need to focus on is getting it to be a more equitable and fair program. And as Jack said, and others have said, we've just set up a commodity here. And people can take positions and drive the price that had nothing to do with blending gasoline.

So there's a really concerted effort, Valero and CVR and ourselves and others, Halley Frontier, all looking to say hey, let's make this to be fairer by getting the point of obligation at the rack, at the terminal. As it is with AB 32, very transparent program where you would actually see the cost of the RIN in an invoice that goes to the dealer tank truck or dealer tank wagon, and frankly, remove a lot of the volatility and lack of transparency that exists.

That has some potential. There's been some indications by Janet McCabe and Gina McCarthy that they, after initially saying they didn't think they wanted to do that, perhaps that is something that they would entertain.

Okay, that's good. My second question, on the last call you mentioned about a 50,000 barrel a day swing capacity in your four refineries system -- that was before Torrance -- between diesel and gasoline. How are you running today, given price signals?

Are you still full tilt gasoline? And how quickly can you change that? How quickly can that change, given the right price signals?

As we said before, the 50,000 is before Torrance. Torrance has some capability to swing between, but not as much, it's a gasoline machine. We can make those moves very quickly, it's simply a matter of changing the cut points on various towers.

There's a certain amount of material that comes out of cat crackers, hydro crackers or crude units that can go into either product, to a limit, obviously, based on product constraints. And that's simply a function of cutting the temperatures or increasing the temperatures. It's almost instantaneous.

The rest of it surrounds putting distillate into gasoline. We did that in the first quarter and I think the whole industry did because we obviously had this large overhang of distillate coming out of the warm winter. And candidly, we created -- we took a distillate problem and turned it into a gasoline problem.

So at the end of the day, we can make those switches. But the bottom line is there's too much clean product. And the only way you can solve that problem is by reducing the amount of clean product that you make.

Maybe that's a good follow-up. One last for me, if I could.

How do you think about economic run cuts? Do you expect we' see them industry-wide in 2H in your regions? And how do you assess whether you cut within your system?

We have already assessed that we're going to cut within the system. I said I believe the incremental economics is the bane of a refiner's existence. Frankly, it's probably the bane of a commodity business existence.

So we have done that. I'll leave it to others to really answer the question. There has been some announced, or at least indications by other people in pad one that they are taking some economic run cuts.

But the bottom line is we know we've got too much product and that's having pressure points on the margins. And we need to figure out, or at least -- PBF has taken steps to reduce its production as we speak and into the third quarter.

Appreciate it, thank you.

Paul Sankey, Wolfe Research.

Hi, Tom. It was enjoyable and this is a painful way to read Jack's comments yesterday. Tom, one interesting thing about you guys taking over Torrance is that we get a little bit of insight into what is normally something we don't get a lot of insight into, which is ExxonMobil.

Was that refinery a good running refinery? I know it ended badly for Exxon in terms of the explosions and stuff. But has it had a good track record of reliability that became anonymous or was it actually a refinery that struggled to run over time? Thanks.

I will tell you that I don't want to necessarily comment on how Exxon ran the refinery but it's self-evident that they did have some issues. I will take you back to -- I worked for Exxon for 20 years and through those years I spent working inside the Benicia refinery outside of San Francisco and the East Bay. I'm dating myself, that was in the 1980s.

The Torrance refinery, which was a Mobil refinery at the time, as you know, was widely reviewed as one of the best, if not the best refinery in California. And it ran well and it made a lot of money. It's had some problems, that's behind Exxon, it is now our facility.

And as I said, it is absolutely all dependent upon our ability to run it in a safe reliable environmentally responsible manner. We have resourced up to do that; we have put extra talent in there. And we are optimistic we're going to be able to do it, but you should obviously hold us accountable to that and see if we perform over time.

Understood. The 16-degree crude you talk about, that's Middle Eastern stuff, is it?

No, actually much of it is domestic crude, in fact, a high percentage of it. A lot of it comes from the San Joaquin Valley down by (multiple speakers) -- SJB heavy is what, 13? SJB heavy is a very interesting crude in that it's 13 degrees API but low sulfur, but high den.

Most of the crude that we're running is domestic crude and obviously we get the working capital benefits from that. And as I said, that is a very heavy crude slate and that's why you get a volume expansion. Basically the way you get a volume expansion in refining, because we sell things on gallons, is you take really heavy stuff and you break it up into lighter stuff and you get an expansion.

Got it. And I don't want to annoy you, but on the East Coast, is the whole rail thing done now?

I don't think so. We are still bringing in, I would say -- let me tell you where we are on rail today. Right now we're bringing in 40,000 barrels a day of Bakken by rail.

And that actually, because of the carrying power on -- Delaware's another machine. It runs a very heavy crude slate, not 16-degree API by any stretch. But some of the Venezuelan crudes we're running, South American crudes, very heavy.

And in order to make the place run with those heavy crudes, you need some light crudes to balance it. So we are bringing in 40,000 barrels a day of Bakken. We have not been bringing any heavy Canadian crudes in recently.

We've had better economics on these other crudes that I've referenced, South American crudes, et cetera, and Middle Eastern, certainly, into Paulsboro. As we go forward, I think other than the fact that we have the economics that carry Bakken with the heavy crudes, you're not going to see us run likely 70,000 barrels a day of light sweet crude, Bakken crude. Those economics are closed on a grassroots basis.

I don't think anybody else at pad one is doing it. And with the Dakota access pipeline and other arteries being built, you certainly could make an argument that it'd be difficult to get a major recovery of crude by rail on the light sweet side.

I do think it's possible and maybe even probable, that if the forecasts are true on heavy Canadian growth, that because of, again, limitations on distribution in Canada, that will come back and perhaps this time next year there's a chance that we'll be running 35,000, 40,000 barrels a day of WCS. That's an option we want to keep.

Final one for me. Venezuela is a bit of a head scratcher. What's your perspective on the sustainability of supply there and any issues regarding the political situation and oil? Thanks.

We've had some minor, I guess, problems and delays but nothing so to speak. They are allegedly refinancing their debt and trying to get some stability. We have not been impacted.

We have some contingency plans in place to the extent that there is a problem. But obviously, on a macro basis, that place is a mess, so it's got to be watched very carefully. But no impact as of this time.

Thank you, Tom.

(Operator Instructions)

Ed Westlake, Credit Suisse.

Just a question on financial matters. The PBFX still trading at a 7.8% yield. Obviously you've got stuff recently purchased at Chalmette and Torrance.

Just talk a little bit about drop-down strategy. The yield there is still a little wide.

Ed, we see the same yields that you see on the screen. However we did go out and raise some equity earlier this year when the yield was higher than where it is today. That is one potential lever that collectively the PBF family thinks that we still have to be able to pull as we go forward.

We now have $280 million of EBITDA that sits at the parent Company that is logistics-related that could be dropped down. We've got some great assets out on the West Coast that are brand new into the system. We have some stuff that we acquired in conjunction with Chalmette, as well.

So the map still points to, while the yield may not be circa 4% where it was at its peak, ultimately you still have arbitrage between where PBF trades and where PBF Logistics trades. So ultimately, Logistics is trading north of 10 times trailing EBITDA and doing drop-downs still makes financial sense as we go forward.

And then obviously doing the right thing by keeping runs under control and hopefully the industry will follow. But the refining EBITDA itself is underperforming for the group. So is there some kind of limit in terms of how much you want to drop into PBFX, perhaps given uncertainty over the refining outlook, but then counterbalanced by the cash that you have on the balance sheet ex Torrance?

I think we have to continue to weigh that we go forward. We've got between $90 million and $100 million of legacy, what historically would of been included in refining EBITDA, that is now part of our Logistics business. We think it's a great platform as we go forward.

We've guided to a long-term growth rate at Logistics. That's over a two- to five-year period. So a lot can change in that two to five years.

And ultimately our view is we're going to continue to grow Logistics through dropdowns and third-party acquisitions. But fortunately it's a relatively small business today, so any incremental growth is going to come probably in $20 million to $40 million EBITDA chunks near term.

And I had another one on the same theme. Any logistical constraints in terms of getting the EBITDA that's within Chalmette or Torrance ready for drop-down in terms of paperwork, et cetera?

What we would say is there is always an ongoing process related to getting essentially cost centers converted into profit centers and getting the associated financial statements done. We've tackled it multiple times in the past two years and don't see any big obstacles as we go forward.

Thanks.

Roger Read, Wells Fargo.

Good morning. Most of it's been pretty well hit.

Maybe there's a way to think about the run cuts that you've indicated by guidance and then your flexibility to either trim more or if crack spreads move the other way to ramp back up. Should we think of that as a 1-day, 3-day, 10-day, 30-day kind of event? Whichever direction you have to go.

It's certainly not a 30-day event. These are steps that can be taken short order, short period of time, assuming you're prepared for them, if you've taken the step to bring in gas oil. If you wanted to run up, obviously we have to procure that.

But a week, we can make that switch either way. I do think, and I want to go back on it. It's interesting, John Rockefeller had the integrated oil strategy and there was a reason he had that.

We have -- I sit and I look at this thing a little stump speech time -- I tell a story that I pulled into my local retail store in my hometown in New Jersey and I asked the attendant that fill my car up with crude. And he said, well, I'm sorry, sir, we don't sell that, we only sell gasoline and diesel. And I think there's a point there.

The integrated model can make sense. But it really when it comes to why are we entertaining runs cuts? We don't work for a producer, we work for the shareholder.

And it's in the best interest of the shareholder for us to take steps to try to get the inventory overhang more in balance, and we're doing that. If indeed the market changes, the refiners will react. I said incremental economics is the bane of existence problem but it can be done in short order.

Okay, thanks. And my follow-up, Erik, just falling on Ed's question there. Is there a pace of deleveraging that you would like to pursue at this point? I know the Company overall would like to still grow through acquisition, but presumably debt levels are getting to a point, at least on debt-to-cap where maybe you don't want to add a whole lot more. So I'm curious, is there a target by year-end 2016 or 2017 and the use of those drop-down proceeds to do so?

Sure. So we, just conceptually, in following the press release and the associated tear sheets, ultimately what we did is we pre-funded the Torrance transaction. So you will see essentially the funds from drawing down $550 million on our ABL that show up in the form of cash on the tear sheets.

Ultimately we used the cash from the financing work that we did at the end of 2015 in conjunction with that drawdown to essentially spend just shy of $1 billion for the assets and associated working capital. As we go forward, we are still very comfortable with circa $250 million of net working capital associated with Torrance. So we expect to see -- and this is near-term, this quarter and into the beginning of Q4 -- we should see positive working capital generate anywhere from $150 million to $250 million coming back to the PBF balance sheet, exclusive of any financing work in and around drop-downs.

So ultimately, our view is the $550 million on our ABL is 100% dedicated to working capital. That's pre-payable debt; the rest of our debt is eventually termed up with pretty hefty make-wholes. As we go forward, though, the goal is to try to use any excess cash to pay down that $550 million, whether it is from positive working capital, drop-downs or any other levers that we have to pull.

Okay. And then if you did, where do you think total debt could go to or debt-to-cap if you were to pursue another acquisition at this point? Trying to understand what the flexibility of the Company's balance sheet is at this point.

Yes, we're pro forma for our transaction. We had our reported number at [630] on a net debt-to-cap basis adjusted for the LCM charge was 23%, pro forma for the transaction it's circa 40%.

So consistent with what we've done in the past, we still firmly believe that to finance hard assets that we're going to acquire at the refining Company, you need a fairly modest mix, or conservative mix, of debt and equity. To keep it very simple, assume it something circa 50-50 debt to equity. And then we would use, just as we've done with Chalmette, borrowing under the ABL to finance working capital and paying that down as we go.

What we've done with Torrance, we assume if it's a single asset, that is exactly how we would plan on financing something as we go forward. However, we have acquired two facilities in less than a year now and we're in the process of digesting all of this.

So from our perspective, we're in good financial position today. But ultimately, there's a big focus on making sure that the balance sheet is safe as we potentially head into any type of headwind.

Great, thank you.

Brad Heffern, RBC Capital Markets.

Morning, everyone. I was hoping we could dig into the performance at Chalmette a little bit. Obviously you've had the EBITDA target out there and the macro environment in general is not going to let you hit that, I would think.

But I was curious if you could talk about the performance to date, maybe on a crack-neutral basis. If we'd had the cracks that you expected, would you be on pace to hit the EBITDA target? Or how comfortable are you with that EBITDA target in 2017?

Yes, we remain comfortable -- I think your point is well taken. We're not going to hit from a November to October period unless there is a market change in the market environment that rate. But we remain comfortable with the $260 million number that we threw out.

It's all about, from our vantage point, looking at competitive disadvantages and competitive advantages versus our peer group. I mentioned it's very important to us with this crude tank project to go ahead and de-bottleneck the logistics. A big piece of improving, getting higher -- getting to that $260 million is going to be further penetrate the export market.

The netbacks are better, the RINs, of course, are lower. That's in the plan. It's going to be 2017 before we get that tank in but we are already taking smaller steps to try to increase exports.

The people of Chalmette are doing things that we want them to do inside the fence line in terms of -- it's a heavy crude machine as well. It was run as part of the Exxon system, the Gulf Coast system; it's a merchant refinery now. We are starting to see expansion of the crude envelope, as I said. There's five, six, seven more crudes that we are running.

And that's the way we run the business. It really does look at, hey, what is the most economic crude. So I think we're still very comfortable with $260 million.

We are obviously seeing the headwinds. We saw the headwinds in the second quarter when the crude differentials compressed because of Mars and LLS getting bid up as a result of the wildfires and the crude impact supply disruption associated with that. But in a normal basis, normal cracks and normal kind of differentials, we are comfortable.

Okay. That's great color, thanks. And then on the RINs front, Tom, in your prepared comments you mentioned becoming an importer and distributor of ethanol on the East Coast.

I was curious if you could dig into that a little more. What are the steps that are required for that? Are we going to see you acquiring more terminals or something like that?

And what's the potential impact on RIN costs from that initiative?

I wouldn't put in there. I don't really know the total RIN cost impact but let me talk about what we're going to do, is we're going to -- it's got multiple benefits for us in the Delaware City refinery.

Just as an aside, I mentioned that Chalmette has very high dock occupancy, so does Delaware. Delaware has some constraints with limited amount of draft capability. So we're going to be bringing in ethanol by rail, which has a benefit for us, which will reduce dock occupancy on the input side.

And then we're going to be able to ship it out. The intent is ship it out by barge over to maybe Paulsboro, a new facility in Plains, a terminal asset that we bought, Paulsboro and other assets, and effectively become a merchant player. We're actually starting that.

I think we're starting next week to load notionally 50 rail cars with ethanol and get the process started. It's an incremental step; it obviously helps us in the RINs category. But do you have any idea what the total number might be?

It's going to improve our ethanol cost, our gross margin by $3 million to $4 million.

$3 million to $4 million of gross margin improvement.

Okay, thanks for that.

Chi Chow, Tudor Pickering and Holt.

Hey, thanks, good morning. Tom, the most fascinating thing I think you've said this morning that you and Jack Lipinski were high school classmates. Who would have ever thought?

I want to go on the record he is older than me. He was a year ahead.

Two refining CEOs in the same home economics class, that's tremendous.

Just a follow-up on the RIN offset strategies you've got. So to understand, the ethanol situation, so you are buying ethanol on the market, railing it in and then exporting it? Is that the plan here?

No, the plan is to rail it in, as I said, rail into Delaware where we have the rail infrastructure to be able to do that. We are buying some ethanol today, or before that, and we're bringing it into Delaware by barge. Delaware obviously has a demand for ethanol in the rack that we have in Delaware.

So we will be replacing the barge receipts with rail receipts to supply ethanol into the Delaware rack. But at the same time, we have a rack in Paulsboro, and we have Plains facilities to try to improve our lie there in terms of how much we're moving over a rack. And that ethanol will effectively be brought in by rail into Delaware and then the intent is to barge it over the water but it's not exporting ethanol.

And then there's the case we haven't been able to see whether or not how much money there is in this as to whether or not we can become a supplier, a more macro supplier in pad one in this particular area.

It sounds like a couple of your efforts is to increase product exports to offset RINs. And then you have got your blending at Torrance. Is there a target on, I think you said, full-year RIN costs around $400 million, $450 million.

Is there a target to targeted that level to get that RIN cost down with these efforts?

Yes, and I wouldn't write this on the wall and it's the holy grail. But in some of the strategic work that we've been doing here recently and are continuing, recognizing that we are faced with headwinds of $400 million, $450 million, the management team has embraced an objective of reducing RINs cost across the circuit by $50 million a year between now and two years from now.

So if the price stayed where it was, we're going to try to get $100 million out of the system in two years. A lot of that is by export, a lot of that is by increasing the rack sales.

And that may mean that we go ahead and take an opportunity in the logistics side of the business to continue to do that. But that is the goal. But we have to do a little bit more work to put more substance in the exact steps beyond what we've talked about to achieve it.

Okay. What percentage of gasoline produced at Torrance do now blend yourself through the rack effort?

So Torrance makes a little -- what, 105,000 barrels a day of gasoline when it's running well, and we're up right now almost 70,000, 75,000 barrels a day moving through the Vernon rack, all of the racks that we have acquired as part of this facility. So as I said, that's one of the areas that I think having our commercial organization, and frankly, having our whole management team, be out there enjoying the lovely weather in California since November 1, is paying some benefits.

Because they had those plans in place, as opposed to just showing up on July 1 and saying, okay, we own it, now what are we going to do with it? So we're up a very high percentage already, and that's a success story right now.

Yes, that sounds great.

And then one question back on Chalmette. You've outlined a lot of these improvement projects in the works at the plant. Is there anyway you can outline the timing of when all these benefits will begin to flow through?

Yes, I think I said that mid to late 2017 for the two big ones that we've talked about, which is the crude tank and the startup of the reformer block and gas plant. The exact dates, if you want them, that they are showing me, I don't necessarily will lay into.

But it's going to be certainly by the end of 2017 and hopefully a little earlier than that, that we should be having these two projects on. And as I said, that's notionally $100 million in EBITDA improvement associated with that for the $100 million spend.

Okay. What about ramping exports and the demurrage savings? Are those kicking in sooner?

There will be some ability to do that, but recognize it's going to be limited by the base logistical problem that we have. Our team is working pretty heavily, fast and hard, on trying to do some things to unload the dock congestion that we've got and obviously give us an opportunity to bring more clean products ships to the dock. We'll see some marginal improvement, but the step change with take place when we really the de-bottleneck the whole logistics system and that crude tank is a big part of it.

Okay, great. Thanks, Tom, appreciate it.

Paul Cheng, Barclays.

Hey, guys, good morning. For Chalmette, Tom, if we exclude the new initiative that you are doing now which won't come on-stream until later next year, for the next several quarters, should we use the second quarter we saw as a reasonable baseline? Or that there's something unique in the quarter that, as a result, your capture rate will be lower or higher?

Well, I think the big thing is obviously for our system, ex Toledo, there is a relatively high percentage of co-products that obviously don't move with price -- flat price of crude. The second quarter with a 35% run-up in the price of crude, you effectively can say, okay, if you moved up $12 a barrel then the margin on coke, the margin on sulfur, the margin on carbon dioxide, pretty much the margin on LPGs, decrease by $12 a barrel. That certainly was what happened in the second quarter.

As we start of the third quarter, I think as someone asked the question before, that obviously prices are going the other way and so we would actually expect to see an improvement in the impact on the capture rate from the co-products, irrespective or regardless of the [crack].

And Torrance, just curious, is there any data you can share in terms of what is the cash operating cost may look like? And also that when you're looking at the improvements that you're going to do, is it more hardware-related or is it the culture of the people?

That's a great question, Paul. First question is we've basically taken some of the plans that Exxon had and we're honing them as we speak. So we believe we have to get some cash operating costs out of there.

We know how we're going to do that to a certain extent. I don't want to go into it on the line because it's we haven't divulged all of our plans and reviewed them internally even with the people of Torrance. But we recognize that we've got to get a fair amount of money, $50 million or so, out of Torrance on a go-forward basis on the cash side, operating as a merchant refiner.

Second part of your question, this is a culture issue. I said this to the people of Torrance. The hardware is unbelievably good.

Exxon spent a ton of money fixing things that they obviously had problems with. As I look at Torrance, this is a facility that has somewhat been under a black cloud for a period of time because Exxon -- I personally believe -- Exxon probably had made a decision that they were not going to run a single refinery operation in the state of California.

And then if you go fast forward to February of 2015 when this explosion took place, envision these people going to work inside the fence line every day, 12 hours, trying to put that place back together. And then going home and seeing their colleagues on the nightly news getting blasted because of [there] being poor performers.

To a certain extent, they were beating down a group of people, they are better than that, we know they are better than that. It's all about changing the culture to be a merchant refinery, to understand that this is a core asset for PBF. It wasn't a core asset for Exxon.

This is our Bay town in effect. And get them to really engage. So far we been enthused about it.

The talent level is there, it's just a question of changing the culture. So you are spot on.

And can you tell us that is there talk, what you need cash quarters we should assume for the next couple quarters in Torrance?

For the refining cash OpEx, we're estimating it to be circa $8 a barrel. I think our long-term target is consistent with what we laid out on the acquisition call, in the $6.50 to $6.75 that is an aspirational target. But we like to set our goals high.

As we go forward here through the second quarter, or second half of the year since we just acquired the facility, assume what's built into the guidance that we provided. It's roughly $8 a barrel at Torrance.

Very good, thank you.

Faisel Khan, Citigroup.

Hi, thanks. Erik, just a question on liquidity. The $200 million to $250 million in working capital you expect -- or cash that you expect to generate from working capital, is that excluding the working capital that you allocate towards Torrance?

That would come back from Torrance. So if we think about we had $1.9 billion of liquidity at quarter end but while we pre-funded through the ABL, you don't see any of the PP&E or any of the inventory on our balance sheet.

So assume we used -- of the $1.9 billion -- we used roughly $1 billion of it to buy $527 million, $537 million of hard assets and another roughly $450 million of working capital, we think we'll get back roughly $200 million of that working capital. So pro forma for the deal, roughly $900 million liquidity at quarter end.

Okay. And then pro forma for the deal, how much cash did you have on the books?

Roughly $415 million.

Okay. With that sort of liquidity in place you should be able to have, take down the ABL to a low enough level. But do you envision -- do you see the need to issue common equity at PBF?

I think at this point we're confident that's what the ABL is there for in terms of financing working capital as we continue to buy assets. And we feel pretty confident with what we have today. We're looking at the same forward cracks that everyone else sees.

But ultimately it's a focus on CapEx, OpEx and delevering the balance sheet.

Okay, got it. Thanks.

At this time we have no further questions and I'd like to turn the call back to Mr. Tom Nimbley for closing remarks.

Thank you very much for your attendance and attention during the call. We look forward to seeing you, hopefully with better results at the end of the third quarter. Everybody have a good day.

Thank you.

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