PBF Energy Inc (PBF) 2015 Q2 法說會逐字稿

Good day, everyone, and welcome to the PBF Energy Second Quarter 2015 Earnings Conference Call and Webcast. At this time all participants have been placed in a listen-only mode and the floor will be open for your questions following management's prepared remarks. If you would like to ask a question at that time, please press star and one on your touchtone phone. (Operator Instructions).

It is now my pleasure to turn the floor over to Colin Murray, Investor Relations. Sir, you may begin.

Thank you, Devon. Good morning and welcome to our second quarter earnings call. With me today are Tom O'Malley, our Executive Chairman; 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, pbfenergy.com. Additionally, today we distributed a slide presentation related to the Chalmette acquisition which we referred to on today's call and a copy of that is also 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 the statements contained in the press release and on this call that express the Company's or management's expectations or predictions of the future of 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 also noted in our press release, we will be using several 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. It is important to note that we will emphasize adjusted fully converted earnings information and results excluding special items. Our GAAP net income or GAAP EPS figures reflect a percentage interest in PBF Energy Company LLC by PBF Energy Inc., which averaged approximately 94% during the second quarter. We think adjusted fully converted net income and EPS are more meaningful metrics to use because they present 100% of the operations on an after-tax basis.

Before Erik discusses our results I'd like to take a moment to review the non-cash lower-of-cost-or-market, or LCM, inventory adjustment that we recognized in the quarter. As mentioned on our previous calls, we assess our inventory for the potential of LCM adjustment on a quarterly basis and future movements up or down of hydrocarbon prices could have a non-cash positive or negative impact to our reported earnings. During the second quarter of 2015 average hydrocarbon prices increased slightly and for PBF this generated a $63.4 million after-tax non-cash inventory benefit. For the purpose of today's call the comments we make in regard to our results will exclude the impact of the non-cash LCM inventory adjustment.

I will now turn the call over to Erik.

Thanks, Colin. Today we reported second quarter operating income of $167.8 million and adjusted fully-converted net income for the second quarter of $80.5 million or $0.88 per share on a fully-exchanged, fully-diluted basis. This compares to operating income of $87.9 million and adjusted fully-converted net income of $34.2 million or $0.35 per share for the second quarter of 2014.

Adjusted EBITDA for the quarter was $218.8 million as compared to adjusted EBITDA of $124 million for the year-ago quarter. For the seventh consecutive quarter our East Coast operations generated significant profitability. For the quarter the East Coast generated almost 60% of the refining contribution.

In both of our operating regions product cracks were strong while input costs increased versus prior quarters and differentials for crude oils narrowed across the board. Higher flat prices for feedstocks versus the previous quarter meant that the relative value of our low value products decreased and became the headwind to earnings.

As we discussed on the first quarter call, rail economics for both light and heavy crude oils continued to be unfavorable the second quarter. The narrow differentials were primarily driven by producer maintenance and wildfires in Canada that impacted supply and subsequently increased demand for alternative Midcontinent barrels such as Bakken. As a result, we reduced our rail delivered supply and used our sourcing flexibility to pursue more economic water born barrels.

We incurred approximately $36.1 million of RINs expense in the second quarter. We were pleased to see some progress from the EPA in the resolution of the RINs issues, which plagued 2014 and 2015 but we believe the EPA did not provide sufficient clarity on 2016 and may have set the stage for the recurrence of past problems regarding the blend wall.

For the second quarter G&A expenses were $39.2 million as compared to $33 million a year ago. Depreciation and amortization expense was $48.6 million versus $34.7 million in 2014.

Second quarter interest expense was $26.8 million compared to $26.2 million last year. PBF's effective tax rate for the quarter was approximately 40%. Going forward for modeling purposes you should continue to assume the normalized effective tax rate of approximately 40%.

PBF ended the quarter with liquidity of just over $1.1 billion. Our consolidated cash balance was approximately $858.1 million including marketable securities and our net debt to cap ratio was 22%. For the quarter refining in corporate CapEx was approximately $56 million, which excludes railcar purchases and sales.

Looking forward to the third quarter for modeling purposes refinery throughput volumes for the Midcontinent should average between 150,000 barrels and 160,000 barrels per day. The East Coast should average between 310,000 barrels and 330,000 barrels per day. For the full-year we expect refinery throughput volumes should fall within the following ranges. The East Coast should average between 310,000 barrels and 330,000 barrels per day and the Midcontinent should average between 145,000 barrels and 155,000 barrels per day.

Early in the fourth quarter we are currently scheduled to have a three-week turnaround at Delaware City and the impact of this is already factored into our full-year throughput guidance. We continue to expect our operating costs for the year to range between $4.50 and $4.75 per barrel. G&A expenses should be in the $130 million to $140 million range. The change reflects expenses expected to be incurred during the Chalmette acquisition and an expected increase to employee compensation expense as a result of positive results for the Company and a good outlook for the remainder of the year.

Depreciation and amortization should be in the $190 million to $200 million range and interest expense should be approximately $105 million to $115 million for the year, which is increased as a result of the senior notes issuance at PBFX in May.

For 2015 we continue to expect CapEx, including maintenance and turnarounds but net of railcar purchases, to be approximately $175 million to $200 million.

Regarding our share repurchase program as a result of the pending announcement of the Chalmette transaction, our activity in the second quarter was limited. During the quarter we acquired 124,589 shares for approximately $3.6 million, which brings the total repurchase since inception to approximately 6.1 million shares at an average price of approximately $24.92 per share, which includes purchases made subsequent to quarter end. We have roughly half or approximately $149 million of the current repurchase authorization remaining. The program remains in place and going forward we will continue to evaluate repurchases with other strategic opportunities.

Our Board has approved a quarterly dividend of $0.30 per share payable on August 25th to the shareholders of record as of August 10th, 2015.

Before turning the call over to Tom Nimbley I'd like to comment on a couple of other notable items. Firstly, regarding the Chalmette transaction there is a tremendous amount of work to do before that transaction can close and we have a dedicated team working with the sellers towards that goal. Tom will go into greater detail on Chalmette in a moment but I wanted to comment briefly on the potential financing of the pending transaction.

As stated in our June announcement, we will likely use a combination of cash and debt to finance the transaction and do not anticipate having to issue any equity. We continue to explore opportunities to finance a portion of the working capital with intermediaries. Additionally, a portion of the transaction could be financed with proceeds from potential dropdown transactions with PBF Logistics. I should point out that we have not approached PBF Logistics with any such proposals and any transaction would have to be approved by the PBF Logistics Independent Conflicts Committee.

Also important to note is that any such dropdown transaction does not have to include assets that are currently held by Chalmette Refinancing LLC but can come from the existing inventory of dropdown assets at PBF Energy.

In addition to June's Chalmette transaction announcement, in May PBF Energy concluded the dropdown of the Delaware City products pipeline and truck rack to PBF Logistics, which generated an additional $143 million in proceeds to PBF of which $112 million was in cash. Including the most recent transaction PBF has received more than $700 million in net cash proceeds through transactions with PBF Logistics including the IPO.

Also of note, today PBF Logistics announced a distribution increase to $0.37 per unit. As a reminder PBF Energy owns 53.8% of the units of PBF Logistics and 100% of the general partner and incentive distribution rights and we are now benefiting from participation in the first level of the IDR splits. Additionally, PBF Logistics successfully raised $350 million of senior notes in May. The establishment of a long-term capital structure further positions the partnership for growth through third-party acquisitions and incremental dropdowns.

I am now going to turn the call over to Tom Nimbley for his comments.

Thank you, Erik, and good morning, everybody. Before speaking about the results of the quarter I would like to update you on the unplanned downtime at Toledo that we experienced in June. Due to a motor failure we had to shut down the wet gas compressor and the FCC for a total of about 16 days. There was no damage to the FCC and with a good amount of effort we were able to completely overhaul the motor and bring the unit back into service within a relatively short time frame. Unfortunately the downtime coincided with a period when the markets were at their best. Estimated total lost profit opportunity for this equipment failure including margin loss and operating expense increases was approximately $40 million to $50 million.

On the positive side both the East Coast and Toledo combined to deliver another positive quarter for the Company. We also successfully dropped the Delaware City Logistics assets which brought in $143 million in proceeds to PBF Energy and very importantly we announced the acquisition of the Chalmette Refinery and associated Logistics assets. I will speak more about Chalmette after covering our second quarter results.

Turning to the second quarter operations, the market continued to deliver and take away in almost equal measures. Cracks on East Coast and Toledo were strong throughout the quarter while a flat price of crude increased and crude differentials narrowed. As Erik mentioned, the higher flat price environment versus the first quarter increased the margin loss on our low value products as a result of their declining relative value versus crude.

WTI averaged approximately $58 a barrel in the second quarter versus $48 in the first quarter. [RINs] averaged $62 during the quarter versus $54 in the first quarter. During the quarter total throughput for our overall system was about 491,000 barrels a day with the Midcontinent averaging approximately 142,000 barrels a day and the East Coast system about 349,000 barrels a day.

For the quarter operating costs on a system wide basis averaged $4.30 a barrel, $4.03 on the East Coast and $4.97 in Toledo. Toledo operating expenses were higher than planned as a result of the lower throughput and increased expenses associated with the outage.

As I stated, results at our Toledo refinery were negatively impacted by the FCC downtime. This not only impacted the overall throughput but also the yield of the refinery. Without the FCC our conversion percentages dropped and we made less clean products and more intermediates and low value products. We were able to partially mitigate these impacts by using our rail capacity and the flexibility of our system to take low value atmospheric bottoms that could not be processed at Toledo to the East Coast and capture some additional benefit from the high East Coast cracks. The Midcontinent 431 crack spread averaged $20.57 per barrel, an increase to the first quarter average of $15.45.

Our margin at Toledo was $12.02 per barrel for the second quarter versus $14.36 in the first quarter. Despite the strong quarterly average margin environment, the downtime and high input costs combined to offset the benefit of the high cracks. We are continuing to finalize the work on a previously announced chemical expansion project at Toledo and we expect that to be complete in the coming weeks. After completion of this project we expect to see an increase in chemical yields, specifically benzene, toluene and xylene, which should improve margins by approximately $15 million to $20 million on an annualized basis.

On the East Coast the Brent 211 crack averaged $19.83 per barrel, up from the first quarter average of $15.76 and seasonally strong on strong gasoline margins.

The refining margin for our East Coast system was $8.26 per barrel versus a margin of $8.92 in the first quarter. While our margin on the East Coast benefited from the $4 increase in the crack spread, the higher flat price to crude oil and decrease in [differentials], both domestic and international crude oils provided a significant headwind.

Rail differentials were uneconomic during the quarter with a Bakken rent differential averaging $6.30 versus $10.93 in the first quarter. Similarly the WCS Brent differential averaged $12.45 versus the fourth -- first quarter average of $17.60. Factoring in transportation costs, it is plainly evident that these barrels cannot find an economic home on the East Coast or a lot of other places at these differentials experienced in the second quarter.

Consequently we shifted our focus to sourcing more water born barrels. The differentials for these barrels also narrowed in the quarter with the asking Brent differential contracting from $5.58 in the first quarter to $2.66 in the second quarter. It is during these times that we rely on the flexibility of our crude sourcing capabilities to bring the most economic barrels into our system. The rail infrastructure at PBF provides us with access to North American crude oil and our marine facilities provide us with access to the international waterborne market. It is very important for PBF to have this flexibility.

We are happy to report that we have received a permit from [Denrex] through Delaware Environmental Agency for the hydrogen plant project that we have discussed previously at our Delaware City Refinery and we continue to progress to the detailed planning on this project. The process is moving ahead as expected and we expect the new hydrogen plant could be in service by the second half of 2017. The additional hydrogen will allow the refinery to increase its yield of low Sulphur high value products, which when complete will add approximately $70 million to $90 million of incremental margin to the East Coast system. We expect to complete the project without spending significant capital by relying on a third party to build and operate the unit or through alternative financing.

Overall we are pleased with the earnings contribution of our East Coast assets this quarter and disappointed with the lost opportunity at Toledo. I would like to point out again that the East Coast continues to pull its share of the weight by contributing over 60% of the refining EBITDA for the quarter. The performance of the East Coast shows, at least over the past several quarters, that the improvements we have made to the system are working and can deliver positive results in turbulent marketing conditions.

It's been about six weeks since we made our announcement regarding the pending acquisition of the Chalmette Refinery and its attendant logistical assets. We are working closely with the sellers to complete the transaction and we still expect it to close before year-end. Since the time of the announcement we have continued to verify our assumptions and evaluate optimization plans for the asset. We still have a lot of ground to cover before closing in terms of working to integrate the assets into our Company, developing a detailed plan to put in place to margin enhancement items we've identified.

We recognize that Chalmette has underperformed its Gulf Coast peers in recent times but we believe that there are a number of opportunities that PBF can take advantage of in order to enhance the earnings of the refinery and make it a meaningful contributor to specific companies. To be clear, the sellers ran and maintained the facility well but we believe there are significant optimization opportunities for PBF versus the operations under the JV structure.

Similar to our East Coast system, Chalmette is a complex asset and because of their complexity they benefit from the lower flat price of crude oil that we currently experience. We can debate how long the oversupply of crude oil in the global market is going to last but at current prices, i.e. today's prices, we estimate that Chalmette is benefiting from the margin uplift of approximately $50 million higher than our base case assumption due to the drop in the flat price of crude. This is obviously a market driven benefit and can certainly move against us in the future but given the current supply situation the base case assumption of approximately $75 a barrel LLS that we had used, does not seem unreasonable. And in that environment Chalmette and our East Coast assets will benefit from their coking operations.

Moving on to an area that is a sizable opportunity that we'll be able to influence, we will be focusing on optimizing the crude's weight of the refinery. Under its existing ownership structure with two parents that had their own independent refining system and equity crudes we believe that Chalmette has never truly been a point of focus for optimizing its input slate. This is a tremendous opportunity for PBF. Chalmette has traditionally run a medium to heavy sour crude slate comprising about 80% of the total inputs. Similar to what we have done on the East Coast, we will use the flexibility of Chalmette's duel crude operations to balance the mixture of heavy and light crudes being run at the refinery and use that flexibility to process the most economic crude slate.

A part of this will be done with the crude we will procure under a new arrangement with [Pet of Asia]. While we will not disclose [volumes] at this point, I can say that the agreement is market based and we believe that Venezuelan crude will play an important role in enhancing the profitability of Chalmette and to a certain extent the East Coast. Under the agreement we will be able to direct the crude to any of our coastal refineries depending upon profitability. Optimizing the crude slate is something that can begin immediately upon transition to our ownership and more importantly requires no additional investment.

Similarly we believe that the product slate at Chalmette can also be optimized to produce a more high value slate. Our efforts in this area will focus on producing a higher volume of distillates, additional grades of gasoline and specialty chemicals. These are high value products that Chalmette is capable of making in greater quantities by making a few changes in the operations that again require very little to no capital investment. Additionally, we believe that there are opportunities to penetrate further into some of the regional product markets which will result in higher netbacks to the refinery and increase overall margin capture.

In total we believe that our crude and product optimization efforts should result in approximately $55 million to $70 million of incremental EBITDA from our base case assumptions.

Additionally for the past few weeks our engineers and planners have been working with the sellers to review Chalmette's capital requirements and investment opportunities the current owners have identified and scoped out a number of margin improvement projects that will increase the yield of high value products and improve unit operations. These projects were left undone under the current owners and are truly low hanging fruit for PBF and include projects such as replacing catalysts with the new more efficient generation at the CCR and projects aimed at reducing coke to cycle times and slurry oil yields.

We believe the initial optimization efforts will result in an initial $30 million to $45 million of EBITDA and this includes the spending associated with tier three compliance.

In total we expect that Chalmette will contribute in the range of $245 million to $275 million of EBITDA to PBF's earnings after we have implemented our initial optimization plan and $85 million to $115 million EBITDA improvement over our base case assumptions.

In addition, as part of our overall review, we are evaluating the potential of restarting the hydrocracker that we shut down in 2010 and a reformer that is currently idle which could help in raising sustained levels in our gasoline pool. We believe there is additional margin upside for Chalmette when these units are restarted. Again, we are in the beginning stages our analysis regarding the potential of restarting these units and we will not know their condition and what it might take to restart them until we have an opportunity to get inside the units.

Lastly, I wanted to comment on the capital spending plan for the refinery as there seems to be a little confusion about this. Before doing so I want to reiterate that we have a dedicated team reviewing all aspects of the capital plan and future projects to ensure that we are spending money at the right level in the right places. This will be an evolving plan that should become more defined as we progress through our review. Based on information we have today, we expect that the refinery will require approximately $90 million to $100 million per year over the next three years for maintenance and turnaround capital expenditures. In the initial years we expect the turnaround and maintenance capital run rate to be lower than this and in 2018 when the next major scheduled turnaround is to be undertaken we expect to run above this level.

We are very much looking forward to adding Chalmette to the PBF portfolio. As we progress through the work and approach the close of the transaction, you can expect further updates with additional details. This transaction is very meaningful to the Company in many ways. We will be adding an asset with untapped potential to our portfolio thereby enhancing the scale and geographic diversity of our business. By increasing the scale and diversity of our business we are strengthening the Company and making PBF more resilient than it is today. It took some time to get to this point and as we have said in the past, PBF does not control the timing of acquisitions but we will put ourselves in a position to capture opportunities as they arrive. Even with the close of the Chalmette acquisition still ahead of us, we are looking for our next opportunity.

I would now like to turn the call over to our Executive Chairman, Tom O'Malley. Apparently we have lost Tom, at least for the moment.

Tom, I'm on. Okay thank you, Tom. I apologize for that. My role at PBF is to be both a cheerleader and a motivator for improving results. We should have and could have earned over a dollar a share if we didn't have the upset in Toledo, which was something frankly we should have avoided and certainly we've taken steps to avoid in the future.

Regarding Chalmette, I am pleased that this refinery can and will be a strong contributor to cash flow and to the profitability of the Company and I am happy that we can buy this facility without issuing shares given the Company's cash position. While we talked in the past about being conservative from a balance sheet perspective when acquiring assets, we have to continue to focus on an ever improving financial standing. PBF's balance sheet meets most of the tests of an investment grade Company and our bonds on a yield to call basis appear to be trading as investment grade.

The Board of Directors of PBF has a very clear goal and that is to go from the appearance to the fact, i.e. to become an investment grade Company. We intend to grow beyond the Chalmette acquisition but only if we can acquire assets that our creative and cash flow positive, thus helping us on the road to an investment grade credit rating and continuing on the road to increasing earnings per share. I'll save any comments on the current turbulent oil market for the question and answer period.

On that note, operator, we would be pleased to take any questions the listeners have.

In a moment we will open the call to questions. The Company requests that all callers limit each turn to one question and one follow-up. You may rejoin the queue with additional questions. (Operator Instructions).

Your first question comes from Doug Leggate with Bank of America.

Tom, thanks for the quantity and the detail on what looks like a fairly substantial uplift in the EBITDA at Chalmette but if I could just pursue the capital question because I think you're right. There is a lot of confusion over the CapEx associated with this. I think when you did the deal you talked about $60 million of maintenance capital and then it was adjusted to $100 million to $110 million of go forward total capital excluding tier one so now you're saying $90 million to $100 million but an uplift in the actual year of a turnaround. Can you give us some idea as to how we should break that down? So in other words the maintenance I assume is still $60 million. What is the -- how is the turnaround capital in the turned around year on top of what's going on in the interim years and what is the tier thee capital? And I've got a follow-up please.

Tom, take that.

I will indeed. We're saying $90 million to $100 million for sustaining and turnaround inclusive of tier three. If you look at it, we think that the sustaining capital is going to be in the $55 million to $60 million range over that period of time, maybe a little bit lower but that's the number we're using. We have no significant turnaround so really money is expended in 2016 and 2017 and when we look at 2018 we normalize that over a three-year period. It's going to be $40 million or $30 million to $40 million. The tier three number that we had earlier in our estimate we had $35 million to $40 million.

Notionally it's going to be about $30 million or even less than that we believe. We can't land on that yet because frankly we believe we're going to be able to reduce the cost of tier three beyond what we had earlier by doing it a different way. In the previous model we were effectively reducing sulfur by increasing octane on existing running units with a rather significant margin (inaudible). We think there's a better answer using some of the idled equipment and that's not in this number yet but in total the $80 million, $90 million or $90 million to $100 million is the correct number ex margin improvement opportunity.

Sorry, Tom, I must still being really stupid this morning because I am still having a tough time with it so at $30 million to $40 million you said as a turnaround number, is that an annual number or is that the total number before a full-year turnaround?

It's a three-year average number with when you look at the base load barely on is very low. In 2018 the number jumps up when there's the next significant number so that's an annualized number over a three-year period.

Okay so what--

Yes our last quarter--

What is it that -- what is the turnaround capital that the other Tom perhaps can answer that? I'm just looking for the total turnaround that you're actually amortizing.

(multiple speakers)

Just hold on one second. This particular refinery turns around on a multi-year cycle and in essence the big year is going to be 2018. From our budgeting point of view we're simply going in and saying yes turnaround expenses for this refinery average $30 million to $40 million a year every year but the real big spend is going to be in 2018 so if you look at 2016 and 2017, Tom or our operating people can't give you the exact number of what they'll spend in each of those particular years and perhaps they'll spend $10 million, $15 million but if you look at that three-year cycle, well then you're going to add it up but the big spend is going to come in 2018 so light spend on turnarounds in 2016 and 2017 and heavy spend on turnaround in 2018. Did I handle that correctly, Tom Nimbley?

Yes, Tom, that's really helpful. What is the 2018 number then, Tom, is what I am trying to get to?

Well, you certainly -- I think if you -- we can't give you an exact number. If you said it was 35 million bucks each year the midpoint of the $30 million to $40 million you'd be up at $105 million. My own guess is you'll probably spend $25 million in the first two years and then $80 million in that 2018 but if you write that down as cast in stone, we're six weeks into this evaluation. I don't think that's such a good idea.

I'll take the next off line. My follow-up here, Tom, is real quick. On your assumptions of the uplift with I guess the crude slate seems to be the primary driver. Correct me if I'm wrong there. What is the TI Brent or perhaps more appropriate heavy oil where there's a [MIA] benchmark or whatever. What discounts are you assuming to get to those numbers and maybe some ideas as to what the slate change is that you assumed to get to those numbers, and I'll leave it there. Thank you.

Yes okay Tom.

Of course we've said the base case is based on an LLS $11 three, two, one crack, 350 [GIP] on total crude input versus LLS and a $75 flat price of crude. We have obviously embedded in our assumptions various differentials for [Bakken, ASCI] etcetera that really go into a 350 all-in aggregate discount. The crudes that they were running were predominantly medium to heavy sour crudes, a lot of (inaudible) crude obviously. We are looking at a number of different things. First of all, even in the base case medium sours we think we could substitute some of the crudes that they were running i.e. domestic crudes, which were probably equity crudes from one of the parents with waterborne sovereign crudes and our current view is based on projections that we have that that would improve margin in the facility.

But second and biggest, a bigger step that we're looking at is if you envision Chalmette with two [more big] units, think of it half Toledo perhaps and half Delaware City. What we're going to look at if the margins are there -- we think they will be -- is running a lot more light, three crude Permian Basin crude, Bakken or other lights, putting that on one still, one crude unit and cracking the bottoms into the SEC, backing out (inaudible) purchases. That's the way we run Toledo and on the other side running the Venezuelan crew that will get with the contract and other heavy crudes at medium crudes to fill out that crude's weight and run the program.

Tangentially in there we have some of the things that I talked about that Exxon and the JV identified as opportunities. There's a project to beat, a very minor project decreased cycle times on the cokers which will allow us to actually increase heavy crude runs at constant crude just because we have more capacity in the cokers there. So those are some of the things. There are quite a few more and we can talk about them as we go down the road. We continue to see emerging opportunities to commercially change the way this operation is being run.

Paul Sankey, Wolfe Research.

Tom, to the extent that you can, could you talk more about the [Creek] contract? I think you've mentioned obviously that it's flexible but is there any other details you can give us on that, the Chalmette Creek contract [obviously] I'm talking about?

Regrettably, Paul, the answer to that and I've got people staring is no. Other than the fact, as we said, it is market based contract but we are under strict confidentiality guidelines in not disclosing anything more on that.

I completely understand. The previously very high level stress question for you, you talked previously about wanting to get to a million barrels a day I think at PBF. Can you update us on whether that's changed and what's the timing you now think about since the taking--?

Tom, let me take that. Look, we don't have a quantitative goal that's completely clear. Our goal, as I've said in my very brief remarks, is driving free cash flow and driving earnings per share. Certainly from a scale point of view we will benefit going forward from adding capacity. We have very little addition as a result of this acquisition to corporate overhead. We can run this pretty much with the people we have. We will be adding some people outside the refinery. So we want to grow the Company and we're continuing to look at every asset that is available but it's a process that's going to take us some more time and I don't want you to sit there and say we're aiming at a million barrels a day. I mean we're aiming at whatever number will produce the most money per share and earnings and the most key free cash flow.

Understood. I guess given what you said about not adding a huge amount of staff and looking at the history of the Company for the next couple of years, you would assume that you're basically going to be busy with Chalmette now, right?

No.

So wrong then. So you could potentially be doing stuff over the next couple of years even if you integrate Chalmette?

I'd have to go down and shoot five people if we didn't do anything else.

Okay could I ask one quick question and then I'll leave it please? Obviously we've had very strong refining this summer basically due to gasoline. How worried are you about the margin environment that we'll see as we go into distillate leadership in global refining? Thank you.

Well, I don't think there's a clear distillate leadership in global refining. I think every time we try and predict the future and what's going to happen events overtake us. We just saw this morning extraordinary growth in gross domestic product here in the United States and of course that's resulted in a very strong domestic gasoline market for consumption. What is strong consumption driven by? Well, certainly growth in GNP but additionally, look we have much less expense in gasoline here in the United States as the result of these low crude oil prices and that's going to continue I believe to add to the importance of gasoline which has somehow faded a little bit, and I think to maintain refining margins. I mean refining margins this morning are excellent.

I'll leave it there. Thank you.

Roger Read, Wells Fargo.

I guess I'll say Chalmette for the most part has been pretty well beaten here but I was wondering as you've gotten in there and looked around, any issues you expect to see in terms of labor improvements or any particular issues that the current owners have been having on a labor front basis?

Tom?

We're not building anything in right now for a significant productivity improvements. It will take some time for us to really have the asset under our wing. We do expect that we will be able to -- we're going to attempt to infiltrate the facility with a PBF culture and that will take some time to change the culture of big oil and probably exacerbated in that plant with the culture of a JV. We do think that there's opportunities to reduce expenses on a go forward basis but other than what is built into the system which we're pretty confident of, which is about $25 million a year starting kind of in year -- or getting there in year two there will be other opportunities but we're not claiming any yet until we get in there and see what we're really dealing with.

I will comment that the staff itself is we've met with the staff. We've met with the leadership. Exxon is retaining some of their leadership. We have already taken steps to start to fill those positions that are being retained by Exxon and we're -- we know we're getting an experienced group of [well borers]. That is clear to us.

Okay great. And then I guess my follow-up unrelated question here although along the same topic, [Total] put their Port Arthur facility up as a potential JV partner. I'm sure anything could be negotiated for a full sale if the numbers work out. Is that something PBF would have an interest in or are there other more attractive targets that you're looking at at this point?

I'll take that. We're not interested in joint ventures. That's -- we're an operator, refineries. Total so far has indicated publicly through their investment pack that they want to operate the refinery and bring in a 50% partner. That has utterly no interest to us. If the refinery was available as a complete unit, we would do what we do in each and every case, take a very close look at it and see if it can be additive. There are other opportunities out there. I am not going to list them, that we're looking at that we're active on all the time. We probably turn down more than we truly go after because we can't make the numbers work but there are opportunities out there and we continue to be after them.

Okay great. Thank you and thanks for the incremental views on Chalmette.

Chi Chow, Tudor Pickering Holt.

Regarding the Chalmette guidance, the $30 million to $45 million on refinery optimization, I just want to clarify that that figure does not include the restart of the hydrocracker reforming unit and also can you talk about why those units are actually shut down right now?

Tom?

Yes for your first point absolutely it does not include any benefit associated with the restart of the units. We clearly believe there are going to be benefits and frankly quite excited about it but until we get in there and see the condition inside the reactors etcetera and know what it will take to restart them, we're not putting a number on it yet so the $30 million to $45 million is basically good old oil boiling optimization, as I said, and frankly commercial, getting further into the [R-Bar] market and things of that nature. We have some ideas with asphalt and slurry that -- taking benefit with that and getting into some businesses that Chalmette used to be in and got out of in the petrochemical market because they sourced the production to Baton Rouge so we would obviously entertain becoming a competitor in some of these areas. So it's $30 million to $45 million is ex the new units or the restart units.

Now, as to why the facility was shut down, we pondered that a lot. That was a decision that was made by the JV and I can't really say why they shut it down. They did say that it was part of the -- a new business model and clearly they were focusing on operating costs at the time. We're looking at these things from the very simple standpoint. We look at the units that are being shut down. There's the hydrocracker that's been shut down. How many hydrocrackers have been -- grass roots hydrocrackers, have been built in this industry in the last four or five years and with terrific returns? We actually contemplated one in Delaware City but given the price we decided to save our powder for acquisitions. We believe there's an opportunity with that hydrocracker.

This refinery, as we've talked before, one of its weaknesses is a relatively low clean product yield relative to say our Delaware City refinery in Southern Toledo. Part of that is due to the fact that they're producing unfinished distillates, hydrocracker restart would address that issue.

The second one frankly, that we're pretty excited about is it's got a reformer down. Octane, if you're following the price of octane recently, it's pretty juicy. People are making more chemicals. There's a whole lot of light straight run gasoline that's coming out of shale, which is low octane that's got to figure out a way to get into the pool. Our personal view is octane is going to be strong going forward with refineries selling [NAFTA] and has a reformer that's shut down so we're going to look pretty hard at whether or not it makes sense to start that. So semi [regens] felt that a small regional but we're going to look harder starting that up.

Great yes, that seems -- sounds like there's just huge upside there. A couple of other items, you mentioned that you want to potentially penetrate the regional markets more. Could you expand on that and then secondly, regarding the assumption of environmental liabilities associated with Chalmette, how do you sniff those risks of future liability coming back to the Company, particularly in light of this Louisiana legacy litigation statute?

First question, I really kind of alluded to it; regional markets, it's really coming out of Chalmette getting into perhaps either an E-10 or certainly the R-bar market which they had historically not done but have recently started. We see upside potential with getting into those markets in a more pronounced way.

On the environmental liability question, we've had a lot of people looking at this. We don't think that the -- we are taking the environmental liability, that's clear. But we don't think that it's a risk that is problematic for us or they're going to buy some insurance to cover ourselves. The site itself has got well definition on some of the issues and our environmental people have site consultants and our legal department has indicated that certainly not something to be overly concerned about.

Thanks for your comments, Tom, appreciate it.

Ed Westlake, Credit Suisse.

This is actually [Johannes VanderTuin] with Credit Suisse for the moment. Ed had to step off, apologies. Just a couple of quick questions that both of us had; one if kind of a more market question. The other has to do with Chalmette. So start that on the MLP side realistically how quickly can we kind of picture a dropdown of any Chalmette asset happening and what sort of assets are you interested in looking at and kind of how the timing might work, if you could at least give a framework for that it would be useful.

Let me do that, Tom. Look, we've demonstrated an ability to operate pretty quickly and we've grown our MLB I think faster than almost everybody else. Where we have a backlog of MLP assets in the existing structure before we acquire Chalmette certainly we could do something quickly on Chalmette. We don't see anything holding us up on that but we're going to be a bit measured here. We're not going to be dropping down something every two months. Perhaps we'll do something more before the end of the year, perhaps not so that's as much guidance as we're going to give on that.

And of course we, in the remarks I believe that Erik made, we have an independent group of directives at PBFX and at the end of the day they're going to be the ones that determined whether these suitable assets that we're envisioning dropping down. There is a PBFX earnings call following this call and I would suggest you listen into that.

Secondarily the question about crude, you had mentioned a Canadian crew to come in but also to ASCI Brent had come in. I was just kind of wondering if you had any comments on the availability of crudes in the Atlantic, particularly kind of Saudi? I mean you know, what -- that makes you think about those crudes going forward into the future?

Well, let me just comment quickly. Crude would appear to be in surplus. Why do I say that? Because the price of crude oil is dropping. Certainly we're seeing availabilities in the Atlantic Basin we're seeing Iraqi availabilities coming in. Certainly the Saudi crude is still coming to the United States and we have crudes and we have crudes coming out of South America, particularly out of Mexico. The exact ASCI spread hard to say on any particular day but the important thing for any analyst to note would be that the discount from Brent on heavier crudes is not just an absolute number but it's a percentage number. It's very important to take that into consideration.

So let's say a $5 differential on an $80 barrel of crude, that's not such a happy moment in time. A $5 differential on a $40 barrel of crude, that's happy because it's the petroleum coke and sulfur that we're producing from these heavy crudes that have to be sold at very, very large discounts on it. At the end of the day the loss on selling those products drops drastically as the price of crude comes down. So availabilities are certainly sufficient and personally I can only -- you know, we could sit around and try and draw an economic model for you. Certainly at Credit Suisse you have far more capability than we do but it looks like we're in a bear market for crude oil for some period of time so we see relatively low prices and I think the model that we've used for Chalmette where we have LLS at $75 will prove to be a high number and that in turn will benefit us and be a bit (inaudible).

Okay thank you very much.

Jeffrey Dietert, Simmons.

You highlighted some of the strength in Canadian heavy and Bakken prices due to temporary events in your opening remarks. Could you talk about the flexibility to hear how much -- how many rail barrels you brought in be it Bakken and be it Canadian during 2Q just to explore what the minimum levels look like in a period where the rail arbitrage is closed?

Yes I can handle that. In 2Q we ran about 60,000 barrels a day of rail related crude, maybe a little more than that. That is obviously lower than the take-or-pay requirements that we have. We obviously have made the point before and continue to make the point that given the [dist] that existed in the second quarter that even with the sum cost associated with the rail facilities that (inaudible) would be the source of sovereign waterborne crudes was far more economic to the East Coast facilities and that's what we did. As we move forward, the third quarter will probably be the talk of what we run that we're showing somewhere around 40,000 to 45,000 to 50,000 barrels a day I believe of rail crude.

Again, we buy our crude three months, basically two to three months early so the crude that we're running in third quarter was based on prices that existed in the second quarter and those prices just did not support rail economics. The good news here is the market and that was driven, as Erik mentioned, by updated downtimes in Canada as the wildfires that existed, a lot of fresh pipeline filled a lot of things. Certainly the market has started to readjust. We're back over $20, $20 to $22 right now when you put the Brent [DI] spread on it on WCS versus W -- versus Brent so the Canadian barrels are coming back into us late for the fourth quarter. The same is true of Bakken back over $10, $11 a barrel dip to Brent. Commercial people are telling me now that we would expect to run somewhere between 70,000 and 100,000 barrels a day rail crude in the fourth quarter based on these economics. So we're not all the way there to covering the take-or-pay commitments but we're significantly back in the right direction.

Thanks for the detail on that. On Toledo Syncrude, I believe it's one of your major feedstocks and line nine reversal is upcoming and it looks like it's been delayed till the end of the year. I don't know if you've got better information than that but do you expect to reduce Syncrude as feedstock at Toledo once line nine starts up?

Actually no we don't although I would say that -- and on line nine your guess is as good as ours. They keep delaying it, whether it be they want to put additional safety valves or hydrostatic testing refiners on the line, or we've read the same thing you have. I've heard end of the year or sometime first half of next year or Q1. These things seem to have a way of just continuing to having the can kicked down the road.

Syncrude is a good crude for us. We don't expect that we'll be significantly reducing our volumes of Syncrude. I would say however we are now running I think this month we're running somewhere around was 15,000 barrels a day of [Utica] crudes, condensates that you know, we call them crudes but it's 60 degree API stuff. We're running some Michigan crudes. We get crudes that are being locally sourced that we didn't run last year so it's a little bit of a cantilever that we have and to the extent that there's increasing production out of Utica we haven't been really counting on that but recently there was at least some reports that perhaps the reserves are greater than expected. We'll be sourcing those crudes in and again, that would potentially displace some other crudes including Syncrude but frankly Syncrude is a valuable crude for us.

Thanks for your comments.

Evan Calio, Morgan Stanley.

Maybe coming in at a hard level, Tom, and I know you love political questions, yes I think there are several proposed bills on crude export removal. Any update on how you see the risk there and probably of getting the needed 60 votes in the Senate or whether or where that challenge likely resides?

Well, I think again, personal opinion as opposed to absolute fact, we are following the debate closely. We are part of a coalition that's trying to explain to the Congress that if you do this you're going to raise gasoline prices in the United States. My own reading of the situation would be pretty straightforward. There's no chance this thing is going to go through Congress prior to the election in 2016. Too many people could get hurt. After the election in 2016 I think you're looking at the issue of who wins the election.

I would tell you that if it was a Democratic victory and I'm not telling you that that's Hillary Clinton; who knows? I would think that the chances of the bills' passage would be reduced. I think if there's a Republican victory I think the chances of passage would be increased. Our real drive on this, particularly as an East Coast refiner, is to say wait a second, guys. If you do this you've got to make some changes in the Jones Act and we would hope if that happens we'll see some changes there.

And we also as a coalition keep looking at the question of ethanol. I think ethanol, leaving aside the fact that the first primary is in Iowa, probably would have the rules and regulations would have been changed already if that first primary didn't exist because ethanol doesn't improve the environment. All it does is raise food prices so your guess I guess is as good as ours but we are running on the assumption that you're not going to see anything until after the election. There's going to be a lot of noise on the thing. There are many people in favor of it. We just have to see what develops. We don't think, by the way, it's -- we think it's going to raise the cost of crude oil across the United States for refiners. Thus, it's going to raise the gasoline price but ultimately we think we're in a pretty good market situation so if it happens it happens. We'll do well in every case.

Clear. Let me, my second question and I'll follow-up in really more color on the M&A market as you see it. I mean do you expect more refining assets to come to market, I mean particularly given the continued stress to the majors? Both Shell and Chevron announced layoffs. Shell announced additional asset sales this week and really reflecting the existential challenge that they're facing at the strip and frankly it appears potentially similar to a market that you've witnessed before in your career. Just any comments how you see that market unfolding and comments on maybe the refining asset market versus standalone midstream market and I'll leave it there?

Well, I've been buying in refineries since the early 1980s and it always seemed that there were a few available in the United States and the principal sellers seemed to be the very large oil companies. And if you look at it relative I would think that almost any other business the industry is, so to speak, outsourcing the refining or manufacturing step. They -- you know, John B. Rockefeller's theory was you had to be integrated from the wellhead all the way through to the selling the gasoline and the gas station or the diesel as it may be and that's no longer the case. It's a world of specialization. We're a refiner. I think the majors are going to continue to sell. Indeed I think we've seen some of the spinoffs from the larger integrated independents. No there's stuff out there. We're looking at it and PBF I hope continues to grow.

Fair enough, thanks.

Vikas Dwivedi, Macquarie.

This is Vikas. Just two quick questions, one is can you guys share any more color on the product disposition opportunities out of Chalmette? You know, we think South American markets are still going to be pretty strong given a lot of these delays in refining startups there but in general are there a lot of other opportunities to improve that part of the margin structure?

Yes I think actually we are pretty excited about that. Obviously you see the US is now getting over 750,000, 800,000 barrels a day of gasoline, maybe even north of that. Some of that is due to what you pointed out, problems in Mexico, problems in Latin America, certainly a lot of refining capacity expansions perhaps are in somewhat in jeopardy or have been cancelled so one of the things we've always looked at is the opportunity to participate in that export opportunity. Now it clearly has been very, very beneficial for Gulf Coast in [Florida] as we would expect it to be beneficial for Chalmette.

Again, we have advantage in the country right now in that we have the cheapest natural gas, had one that's cheapest natural gas in North America. We have the highest complexity. We have favorable crude economics even if there is an export, lifting of the export ban, so we are -- the US has a pretty competitive industry and we view Chalmette as being part of that and we expect to be able to take advantage of it. Beyond that, as I said, there are other opportunities we see other than the export market to try to increase the netbacks on clean products by changing to have some of the (inaudible) or movement into some middle market including blending ethanol into the gasoline.

Got it, thank you. And the second question was the -- as we move into winter grade gasoline, there are some views that the additional C4 you can put in will resolve this octane problem. We are a little skeptical but would love to hear your view on how that might play out.

I think there's going to be seasonality and cyclicality in this as you go from season to season. You're going to see a swell in production because you're putting [butane] into gasoline but butane is not a big octane contributor as say (inaudible) would be or other things. My view and I think others in the industry perhaps are there; there is -- you know, I wouldn't say it's a seismic change but there's a significant change associated with a couple of things. One is everybody is trying to make the increased chemicals. We're doing it. We're actually at a point now that octane has gotten so strong that in our own system we're diverting chemical production back into the gasoline pool because it's more valuable and the gasoline pools across the spread because of the price of octane. That in combination with how you blend up some of these very low octanes straight runs that come off of effectively Permian Basin or the very high crudes, we're bullish on octane going forward.

Yes got it, thank you.

We have reached the end of our allotted time and I now turn the call over to Tom O'Malley for closing remarks.

I want to thank everybody for attending the call. I appreciate your interest in the Company and we're going to work hard to keep improving our results, our operations in every way we can. Thank you very much and have a great day.

Thank you. This does conclude today's teleconference. Please disconnect your lines at this time and have a wonderful day.