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 opened for your questions following management's prepared remarks. (Operator Instructions) It is now my pleasure to turn the floor over to Colin Murray, Investor Relations. Sir, you may begin.

Thank you, Kevin. 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 will refer to on today's call and a copy of that is also available on our website. Before getting started, I would 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 are forward-looking statements intended to be covered by the Safe Harbor provisions under federal securities laws. There are many factors that could cause actual results to differ from our expectations, including those we described in our filings with the SEC. As 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 the percentage interest in PBF Energy company LLC owned 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 you because they represent 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 to 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 an 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 oil 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 a headwind to earnings. As we discussed on the first quarter call, rail economics for both light and heavy crude oils continue to be unfavourable for 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 mid-continent barrel such as Bakken. As a result, we reduced our rail delivered supply and used our sourcing flexibility to pursue more economic waterborne barrels. We incurred approximately $36.1 million of RINs expenses in the second quarter. We were pleased to see some progress from the EPA on the resolution of the RINs issues which plagued 2014 and '15 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…

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 timeframe. 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 poured 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 the East Coast and Toledo were strong throughout this quarter while the flat price of crude increased and crude differentials narrowed. As Erik mentioned, the higher flat price environment (faced) in 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. Brent averaged $62 during the quarter versus $54 in the first quarter. During the quarter, total throughput for our…

Tom, I'm on. 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 $1 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'm 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 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 at PBF have 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 require assets that are creative and cash flow positive, thus helping us on the road to an investment-grade credit rating and continuing on the road to increase earnings-per-share. I will 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.

[Operator Instructions] Your first question comes from Doug Leggate with Bank of America. Your line is open.

Thanks. Good morning everybody. Tom, thanks for the clarity and detail on what was pretty a fairly substantial uplift on 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 there was, actually a $100 million to $110 million of go forwards total capital excluding Tier 1. So now you're seeing $90 million to $100 million, but an uplift in the actual year of the turnaround. Can you give us some idea as to how we should break that down? So in other words, if maintenance assumes those $60 million, what is the – how does the turnaround capital in the turnaround year on top of what's going on, in the interim years in what has appeared to be the capital? And I have got a follow-up, please.

Okay, Tom, take it.

I will indeed. We are saying $90 million to $100 million for sustaining in turnaround inclusive of Tier 3. 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. It maybe a little bit lower but that's the number we are using. We have no significant turnaround, so really, money is extended in '16 and '17 and when we look at '18, we normalize that over a three year period, it’s going to be $40 million, or $30 million to $40 million. The Tier 3 number that we had earlier in our estimate, we had $35 million to $40 million, notionally it’s going to be above $30 million dollars or even less than that, we believe. We can't land on that yet because frankly, we believe we are going to be able to reduce the cost of (debt) beyond what we had earlier by doing it a different way. In the previous model, we were effectively reducing sulphur by increasing octane on existing running units with a rather significant margin that we think is a better answer using some of the idled equipment. And that's not in this number yet, but in total, the $80 million to $90 million, $90 million to $100 million is the correct number ex-margin improvement opportunity.

Sorry, so I'm not really disengaged with this matter because I'm still having a tough time with it. So the $30 million to $40 million you said is a turnaround number, is that an annual number or is that the total number for a four-year turnaround?

It’s a three-year average number. When you look at the base load early on, it’s very low. In 2018, the number jumps up when it’s the next significant number. So that's - it’s an annualized number over a three year period.

Okay. Lastly, what is the turnaround? The others Tom perhaps can answer that. Looking for the total turnaround that you are actually amortizing? Is that what will you get the $100 million number?

Doug, just hold on one second. This particular refinery turns around on a multiyear cycle. In essence, the big year is going 2018. From our budgeting point of view, we are simply going in and saying, yeah, turnaround expenses for this refinery are 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 '17, (Palm Oil) our operating people can't give you the exact number of what they'll spend in each of those particular years, perhaps they will spend $10 million, $15 million but if you look at that three-year cycle, well, then you know you are going to add it up but the big spend is going to come in 2018. So light spend on turnarounds in '16 and '17 and heavy spend on turnarounds in '18. Did I handle that correctly, Tom?

Tom, that's really helpful. What is the '18 number then, Tom, is what I'm trying to get to?

Why, certainly, I think if you – you know 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 a $105 million. My own guess is, you'll probably spent $25 million in the first two years and then $80 million in that 2018. But if you write that down, you know, cast in stone, we are six weeks into this evaluation, I don't think that's such a good idea.

Okay, I will take the last offline. My follow-up, in your comments, just 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 WTI-Brent or perhaps a appropriate heavy oil benchmark, whatever? What this [indiscernible] figure assumed to get to those numbers and maybe some idea as to what the slate changes do you assume to get those numbers now [indiscernible]? Thank you.

Tom, you go.

Go ahead, Tom.

We said the base space is based on an LLS $11, 3-2-1 crack sweet 50 dip 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 et cetera that really lows into a 350 (all-win) aggregate discount. The crudes that they were running were phenomenally medium to heavy sour crude. So a lot of Brent crude obviously. We are looking at a number of different things. First of all, even in the base case, median sour, we think we could substitute some of the crudes that they were running i.e. domestic crudes which were probably equity crudes with one of the parents with waterborne sovereign crudes and our current view is based on the projection that we have that that would improve margin in the facility. The second and biggest, a bigger spec we are looking at is if you were engaged in Chalmette with two new big units, think of it half Toledo perhaps and half Delaware City. What we are willing to look at if the margins are there, we think they will be is running a lot more light-sweet crude, Permian Basin crude, Bakken or other likes, bringing that amongst a one-crude unit; and cracking in the bottoms into the FCC, backing out these deal purchases. (That story will run) Toledo, and on the other side, are running the Venezuelan crude that we will get with the contract and other heavy crudes and medium crudes that fill out that crude slate and run the program. Tangentially in there, if we have some of the things that I talked about, that the Exxon and the JV identified as opportunities, there’s a project – a very minor project decrease cycle times on the cokers which will allow us to actually increase heavy crude volumes 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 could 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.

Our next question comes from Paul Sankey with Wolfe Research. Your line is now open.

Good morning all. Tom, to the extent that you can, could you talk more about the crude contract. I think you've mentioned obviously that's flexible, but is there any other details you can give us on that, the Chalmette crude contracts obviously I'm talking about?

Regrettably Paul, no answer to that, and I've got people stare at me. Other than the fact as we said, it is a market-based contract, but we outlined a strict confidentiality guidelines and not disclosing anything more on that.

I completely understand. The previous, it’s a very high level strategic question for you, you've talked previously about wanting to get to 1 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 to reach that?

Tom, let me take that. Look, we don't have a – quantative goal that's completely clear. Our goal as I 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 are 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 are aiming at a million barrels a day. I mean we are aiming at whatever number will produce the most money per share in earnings and the most 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 are basically going to be busy with Chalmette though, right?

No.

So, wrong then. So you could still 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. Can I ask you a market question, and then I will 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 see as we go into this leadership in global refining. Thank you?

Well, I don't think there’s a clear 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, strong consumption. What is strong consumption driven by? Well, certainly growth in GNP but additionally look, we have much less expensive gasoline here in the United States as a result of these low crude oil prices, and that's going to continue, I believe, to add to the importance of gasoline which had somehow faded a little bit and I think to maintain refining margins, I mean, refining margins this morning are excellent.

I will leave it there. Thank you.

Our next question comes from Roger Read with Wells Fargo. Your line is now open.

Yeah, good morning.

Good morning.

I guess I will say Chalmette for the most part 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 labour improvements or any particular issues that the current owners have been having on a labour front basis?

You know, we are not selling anything in right now for 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 are going to attempt to infiltrate the facility with the culture and that will take some time to change, because of Big Oil and probably exacerbate it in that plant with the culture of a JV. We do think that there’s opportunity to reduce expenses on a go forward basis but other than what we've already built into the system which we are pretty confident of, which is about $25 million a year starting kind of a year. We will get there in year two. There will be other opportunities but we are not claiming any yet until we begin the year and see what we are really dealing with. I will comment that the staff itself – we've met with the staff, we met with the leadership. Exxon is retaining some of their leadership. We have already taken steps to start to fill those positions that have been retained by Exxon and we know we are getting a experienced group of oil (borers), (that is quite a rustle).

Okay, great. And then, I guess my follow up on related 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 that 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 are not interested in joint ventures. That's – we are an operator of refineries. Total so far has indicated publicly through their investment bank 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 and 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 are looking at, that we are active on all the time. We probably turned down more than we truly go after because, you know, 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 the Chalmette.

Our next question comes from Chi Chow with Tudor Pickering Holt. Your line is now open.

Great, thank you. Regarding the Chalmette guidance, the $30 million to $45 million on refinery optimization, I just want to clarify that 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. So, to 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 et cetera, and know what will it take to restart them, we are not putting a number on it yet. So the $30 million to $45 million is basically good old (oil drilling) optimization, as I said, and frankly, commercial, getting further into the (oddball) 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 it got out in the petrochemical market because they sourced the production to that route. So we would obviously have to change and become a competitor in some of these areas. So the $30 million to $45 million is ex-the new units. At least five units. Now, as to why the facility was shut down, we (founded) that a lot. That 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 a new business model and clearly that we were focussing on operating the costs at the time. We are looking at these things from a very simple standpoint. We look at the units that have been shut down, the hydrocracker that's been shut down. How many hydrocrackers have been, grassroots hydrocrackers have been built in this industry in the last four or five years and with terrific returns. We actually contemplated more in Delaware City but given the price we decided to save our [indiscernible] for acquisitions. We believe there’s an opportunity with that hydrocracker. This refinery as we have talked before, one of its weakness is it’s a relatively low clean product yield relative to say, our Delaware City refinery in Southern [indiscernible]. Part of that is due to frac [indiscernible] that's producing unfinished [indiscernible], hydrocracker restart would address that issue. The second one frankly that we are pretty excited about is [indiscernible] is [indiscernible]. Octane, just following the price of octane recently is pretty juicy. People are making more chemicals. There are a whole lot of light [indiscernible] run gasoline that's coming out of shale which is low-octane and have to figure out a way to get into the pool. Our personal view is octane is going to be strong going forward. This refinery is selling naptha and has a reformer that shut down. So they roll up pretty hard whether it or not it makes sense to start that. It’s a semi- region, it’s small – relatively small region on the [indiscernible] but it was a little harder starting that up.

Alright. Tom, I think it sounds there’s huge upside there. Couple of other items, you mentioned that you want to potentially penetrate the regional market more. Could you expand on that and then secondly, regarding the assumption of environmental liabilities associated with Chalmette, how do you set those list of future liability to be back at the company particularly in light of this Louisiana’s legacy litigation statute?

First question, on really kind of a loaded [indiscernible] regional market, so it really, coming out of Chalmette getting into perhaps either an E10 or certainly the (oddball) market which they had historically not done but have recently started with the upside potential with getting into those markets in a more announced way. On the environmental liability question, we've had a lot of people working 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. We are going to buy some insurance to cover ourselves. The site itself has got, well, definition on some of the issues and our environmental people and outside consultants, and our legal department has indicated that that's certainly – it’s not something to be overly concerned about.

Thanks for your comment, Tom. Appreciate it.

Our next question comes from Ed Westlake with Credit Suisse. Your line is now open.

Hi, it’s great to speak with you, this is actually [indiscernible] with Credit Suisse for the moment. Ed had to step off, apologies. Just a couple of questions that both of us had. One is kind of a more market question, the other has to do Chalmette. So to start with that, on the MLP side, realistically how quickly can we kind of picture a drop down of any Chalmette asset happening and what sort of assets are you interested in looking at and 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 MLP, I think faster than almost everybody else. Where we have a backlog of MLP assets in the existing structure before we acquired 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 are not going to be dropping down something every two months. Perhaps we will do something more before the end of the year, perhaps not. So that's as much guidance as we are going to give on that. And of course, in the remarks, I believe that Erik made, we have an independent group of directors at PBFX and at the end, they are going to be the ones that determine whether these suitable assets were 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’d mentioned the Canadian crude had come in, but also the ASCI freight had come in. So just wondering if you had any comments on the availability of crudes in the Atlantic, particularly kind of Saudi? What 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 was dropping, certainly we are seeing availabilities in the Atlantic Basin. We are seeing the Rocky availabilities coming in. Certainly the Saudi crude is still coming to the United States 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 a $80 barrel of crude, that's not such a happy moment in time, a $5 differential on a $40 barrel crude, that's happy because it's the petroleum, coke and smelter that we are producing from these heavy crudes that have to be sold at very, very large discounts. At the end of the day, the loss on selling those products drops drastically as the price of crude comes down. Availabilities are certainly sufficient and personally, I can only – we could sit around and try and throw in an economic model for you, certainly at Credit Suisse you will 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 of $75 will prove to be a high number and that in turn will benefit us, indeed it is a high number.

Okay, thank you very much.

Our next question comes from Jeff Dietert with Simmons. Your line is now open.

Good morning.

Good morning.

Good morning.

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

Yeah, I can handle that. In 2Q, we ran about 60,000 barrels a day of rail related crude, they deliver more than that. That is obviously lower than the take-or-pay requirements that we have. We obviously have made the point before – continue to make the point that given the (gist) that existed in the second quarter, that even with some costs associated with the rail facilities, that [indiscernible] source, [indiscernible] and 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 trough of what we run with showing somewhere around 40,000 to 45,000 to 50,000 barrels a day. I believe of rail crude. Again, we buy our crude basically two to three months early. So crude that we are run in the third quarter were based on pricing that existed in the second quarter, and those prices just didn't rail economics. The good news here is the market – and that was driven as Erik mentioned by updated downtimes, in Canada, the wildfires that existed, a lot of great pipeline [indiscernible]. Certainly the market has started to readjust. We are back over $20, $20 to $22 right now when we put the Brent WTI spread on it on the WCS versus Brent. So the Canadian barrels are coming back into our slate for the fourth quarter. The same is true of Bakken, back over $10 or $11 a barrel [indiscernible] to Brent. Commercial people are telling me now that that we would expect to run somewhere between 70,000 and a 100,000 barrels a day of rail crude in the fourth quarter based on these economics. So we are not all the way there covering the take-or-pay commitments but we are significantly back in the right direction.

Thanks for the detail on that. On Toledo, Syncrude, I believe it’s one of your major feedstocks in Line 9 reversals upcoming. It looks like it's been delayed till the end of year. I don't know if you've got better information than that but do you expect to reduce Syncrude as a feedstock at Toledo once Line 9 starts up?

Actually no. We don't – although I would say that on Line 9, your guess is as good as ours, they keep delaying it, whether it’d be whether they want to put additional safety valves, hydro-status testing requirements on the Line [indiscernible] end of the year or sometime post half of next year for Q1. These things seem to have a way of just continuing to have (McCann) kick down the road. Syncrude is a good crude for us. We don't expect that will be significantly reducing all the items of Syncrude. I would say however, we are now running, I think this month, we are running somewhere around 50,000 barrels a day of Utica crudes, condensates [indiscernible] 16 API stuff. We are running some Michigan crudes, these are crudes that are being locally sourced that we didn't run last year. So it’s a little bit of an [indiscernible] that we have and to the extent that there is increase in production out of Utica, we haven't been really counting on that but [indiscernible] but perhaps the reserves are greater than expected, we will be sourcing those crudes in and again, that would potentially displace some other crudes including Syncrude but frankly Syncrude are valuable crudes for us.

Thanks for your comments.

Our next question comes from Evan Calio with Morgan Stanley. Your line is now open.

Hey, good morning guys. Maybe looking at a high level, Tom, and I know you love political questions, there’s several proposed bills and crude export removal. Any update on how you see the risk there and probability of clearing the needed 60 votes in the senate 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 are going to raise gasoline prices in the United States. My own reading of the situation would be pretty straightforward. There is 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 it was a democratic victory and I'm not telling if that's Hillary Clinton, who knows? I would think that the chances of the bill’s passage would be reduced. I think if there’s a republican victory, I think the chance of passage would be increased. Our real drive on this particularly as a 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 will 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 primaries in Iowa probably would have – the regulations would've been changed already if that first primary didn't exist because ethanol doesn't improve the environment. What it does is it raises food prices. So you guess, I guess is as good as ours, but we are running on the assumption that you are not going to see anything until after the election. There is going to be a lot of noise on the thing, there are many people in favour of it. We just have to see what develops. And I think by the way it’s – we think it’s going to raise the cost of crude oil across the United States for refiners plus it’s going to raise the gasoline price, but ultimately we think we are in a pretty good market situation. So if it happens, it happens, we will do well in very case.

That's clear. Then my second question, I have a follow-up and really more colour on the M&A market as you see it. I mean, do you expect some refining assets to come to market and then 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 facing at the strip, and frankly, it appears potentially similar to a market that you've witnessed before 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 will leave it there.

Well, I've been buying the 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 as a business, the industry is so to speak outsourcing the refining or manufacturing step. John D Rockefeller’s theory was you had to be integrated from the wellhead all the way through to selling the gasoline in the gas station, or the diesel as it may be. And that's no longer the case. It's a world of specialization. We are 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. So there is stuff out there, we are looking at it, and PBF I hope continues to grow.

Fair enough. Thank you, guys.

Our next question comes from Vikas Dwivedi with Macquarie. Your line is now open.

Hey guys, it’s just Vikas. Hey, just two quick questions. One is, can you guys share any more colour on the product disposition opportunities out of Chalmette. We think South American markets are still going to be pretty strong given lot of the delays in refining start-ups there, but in general, are there a lot of other opportunities to improve that part of the margin ?

Yeah, I think actually we are pretty excited about that. Obviously you see the U.S. now getting over 750,000 - 800,000 barrels a day of gasoline, maybe even more after 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 jeopardy or have been cancelled. So one of the things we've always looked at is the opportunity to participate in that export opportunity. Yeah, that clearly has been very, very beneficial for Gulf Coast refiners and we would expect it to be beneficial for Chalmette. We have an advantage in the country right now and now we have the cheapest natural gas, Piedmont has like the cheapest natural gas in North America. We have the highest complexity. We have favourable crude economics even if there is an export – lifting up the export ban. So we are – the U.S. 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 were other opportunities we see other than the export market to try to increase the net-backs on some products by changing perhaps some of the [indiscernible] or moving into some newer markets and some new geographies, (playing it along into) the gasoline.

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

I think there is going to be seasonality and cyclicality and it’s – as you go from season to season, you are going to see it swell in production because you put a butane into gasoline, but butane is not a big octane contributor, as you know, as say, alcohol would be or other things. My view and I think others in the industry (perhaps) is there is this – 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 these three chemicals. We are doing it. We are actually – we are at a point now that octane has gotten so strong that in our own system, we are diverting chemical production back into the gasoline pool because it’s more valuable – into the gasoline pool because it’s (spread because it supplies octane). That in combination with how you blend up some of these very low octane straight runs that come off of effectively Permian Basin or the very high crudes, [indiscernible] octane going forward.

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 are 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.