Welcome to the PBF Energy's Second Quarter 2014 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. (Operator Instructions) It is now my pleasure to turn the floor over to Erik Young, Chief Financial Officer. Sir, you may begin.

Thank you. Good morning everyone and welcome to our second quarter earnings call. With me today are Tom O'Malley, our Executive Chairman; Tom Nimbley, our CEO; and other members of our management team. If you would like a copy of today’s press release, you can find one on our Web-site, pbfenergy.com. Attached to the earnings release are tables that provide supplemental financial and operating information on our business. Before we get 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 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 those measures provide useful information about our operating performance and financial results, but they are non-GAAP measures and should be taken as such. It is important to note that we will emphasize adjusted pro forma earnings information. Our GAAP net income or GAAP EPS figures reflect a percentage interest in PBF Energy Company LLC, owned by PBF Energy, Inc. which averaged approximately 74.8% during the second quarter and was 90.5% at quarter end. We think adjusted pro forma net income and adjusted pro forma EPS are more meaningful to you because it presents 100% of the operations of PBF Energy Company, LLC on an after-tax basis. With that, I'll move on to discussing our second quarter 2014 results. Today we…

Thank you, Erik, and good morning everybody. Regarding our second quarter financial results, PBF had another sequential quarter of positive earnings. As expected, second quarter earnings were not as robust at as our strong first quarter. The market was the biggest factor for all of our refineries. In the second quarter we saw narrower crude oil differentials across the board and the increase in the flat price of crude put pressure on the bottom of the barrel. Operations for the quarter were relatively stable with the exception of the unplanned shutdown that the Toledo FCC experienced in June. Relative to the guidance we provided, this did not materially impact overall throughput for the quarter but it did impact product yields and was a lost opportunity for the Company. Throughput for our overall system was about 470,000 thousand a days with the Mid-continent averaging 147,000 barrels a day and East Coast system ran approximately 324,000 barrels per day. For the quarter, operating cost on a system-wide basis averaged $4.92 per barrel, $4.67 per barrel on East Coast and $5.41 per barrel in Toledo. The Mid-confident 4-3-1 crack spread averaged $18.78 per barrel, an increase over the 2014 first quarter average of $16.79. Our margin at Toledo was $12.79 per barrel for the second quarter versus $19.09 in the first quarter. The decrease in refining margin in Toledo is reflective of the higher realized landed cost of crude in the quarter as well as the broader increase in flat prices for crude oil. Our landed cost of crude in the second quarter was $1.53 per barrel over WTI versus $0.99 per barrel under TI in the first quarter, approximately $2.50 per barrel swing. On average, Syncrude priced $0.72 under WTI on an FOB basis during the second quarter versus $0.99 under WTI…

Thank you very much, Tom. I of course had hoped that we would do a bit better in the second quarter, but all in all, I'm satisfied with the results, particularly when considering the LIFO charge. We are always dependent on the general market conditions but we see improvements within our general refining system, with our new rail facilities which are coming on-stream as we speak and will improve our crude oil economics on the East Coast. To take over from Morgan Stanley in Toledo will I believe, in fact I'm certain, lower Toledo's crude costs, and Tom Nimbley already outlined the Toledo improvement from our turnaround and this will clearly allow us to capture a higher percentage of the market crack. All in all, PBF is well-positioned in a very tough industry. And on that note, we'll be pleased to take your questions.

(Operator Instructions) Our first question is coming from Evan Calio with Morgan Stanley. Please go ahead.

I noticed that you provided the operating cost by region and that's helpful. I guess I'm surprised that East Coast is lower than the Mid-con or Toledo and is that just related to that FCC issue in the quarter a non-representative and maybe that's also going to change with this major 4Q turnaround effect, maybe you could just comment on that, I'd appreciate it, and then I have a follow-up?

Toledo was impacted slightly because of the lower throughput and the cat cracker shutdown we had at the end of the quarter but directionally you would expect to see higher operating costs in Toledo than you would on the East Coast. East Coast actually is advantaged on natural gas pricing right now because of the significant amount of gas that's coming out of the Marcellus and Utica. So we have an advantage on the East Coast. In fact we have an advantage in the East Coast versus anywhere in the Atlantic Basin. Also Toledo outsources some of their wastewater treatment facilities to a third-party and there's a little bit of an extra cost there. I would expect Toledo's cost to continue to come down but I suspect that the East Coast will also come down some as we go across the rest of the year and it will be a slight spread with Toledo being a little bit higher.

Okay, that's helpful. My other question is, Delta recently announced that securing a Jones Act vessel for crude supply, I know you have superior rail position and given maybe crude export uncertainty that could relate to the Jones Act, how would you consider potentially securing Jones Act capacity?

We're not at the present time looking at Jones Act capacity. The rail facilities we have in place we believe offer us significant advantage over some of the other East Coast refiners, and particularly we're looking at 80,000 barrels a day of heavy crude coming into that refinery, and that effectively has started I believe on Wednesday with the first discharge on our new heavy facility. So when you look at Jones Act and just think about it clearly, Jones Act movement is somewhere between $6 and $7 dollars a barrel while foreign flagged movement is up to the East Coast a little bit less than $2 a barrel. How can anybody take that delta up, I'm not quite sure, but we're not considering Jones Act at the present time.

I would add one thing then on that. For a refinery like Trainer, PES, other light sweet refineries in the East Coast, their only option is sweet crude. So as they bring in crude on Jones Act transportation with the cost that Tom just mentioned, it still could be economic for them versus bringing in [indiscernible] from West Africa. We have the optionality of not only running the domestic heavy crudes or light crudes but also we have waterborne medium sours that we source in, and when ASCI moves out, we just have a different set of economics. We'll never be able to source in light sweet crude on Jones Act better than what we can get probably Vasconia or some of the Middle East medium sours.

Great. And maybe last if I could, one for Tom O'Malley, a broader policy question, I know East Coast refiners play a key role in the proposed RVO reduction that reduced Brent pricing last year, but do you see a similar position for East Coast and for PBF in the crude condensate today as it affects your region and also relates to the Jones Act which as you mentioned is more other people and regions' maybe movement of choice?

Certainly, we want to be active in the debate and discussion with regard to the export of crude oil, and I don't mind speaking up on that issue, it's a terribly politicized issue. Certainly in the United States, it's nowhere near self sufficient on crude oil. And frankly our position at this moment in time, of course we're opposed from the point of view of our shareholders but also candidly from the point of view of the country, at a moment in time when the Middle East seems to be more or less on fire, we have enormous problems in Iraq, in Syria, obviously Israel and the Gaza Strip, no one knows what's going to come out of this mess and there certainly could be some interruption on crude oil shipments. At the same moment in time, one of the principal exporters to the West, couple of million barrels a day, Russia is in the process of mucking things up a bit in the Ukraine, and God only knows what's going to come out of that. It just seems to me a bad moment in time on an overall basis to say, oh gee wiz, let's export crude. Additionally, I'm not quite sure how any politician is going to be able to justify an increase in the gasoline price in the United States, which will surely come if we start exporting crude oil at this time. Nothing is forever but this seems to me to be a bad moment in time and we will indeed speak up about it.

Appreciate it, helpful as always guys.

We'll go next to Doug Leggate with Bank of America. Please go ahead.

Either Tom, I wondered if I could start just with a quick housekeeping question, you did mention a lost opportunity cost at Toledo, I wonder if you could quantify that for us, and also I guess you've had a little bit of a pullback in domestic pricing, so I'm just curious to what extent you can quantify any reversal in LIFO quarter-to-date and I have more kind of strategic follow-up please?

I'll take the first piece of this. The los profit opportunity for Toledo is about $50 million for the FCC downtime, and a very high percentage of that as you could imagine was margin, a little bit of OpEx but mostly margin.

With regard to LIFO, obviously with a drop in crude oil pricing, it's hard to put the exact number on, we don't have it for the end of the month of July, but my guess is, off the 100 odd million dollars of LIFO charges in the first half of the year, I would have to guess that per today $60 million to $70 million comes back the other way, but who knows what the number will be when we get to September 30th and our next reporting time. I think the drop that we see in crude oil prices and the drop that we've seen concurrent and a bit more in product pricing is probably overdone at this point and it's hard to put one's finger on why we have an expanding economy in the United States. Certainly the world is not doing badly, we do have all this turmoil going on, there doesn't seem to be much in the way of a risk premium to crude, and I would be of the opinion that that premium will probably come back.

Thanks for your answers, guys. If I could just try a bigger picture question then, when you look at your markets, at least the way we think about it is that the U.S. becomes self-sufficient in gasoline, it appears to be heading towards, the East Coast is obviously still going to be a net importer, to what extent are you seeing sustained or maybe even conversely a breakdown of regional gasoline prices relative to Brent, because obviously to your point it seems that we have seen some weakness here but we're trying to figure out if this is some kind of transitional period when domestic gasoline prices are moving more towards the domestic price of the crude that is, just curious what you're seeing in the market? And if I may, I've got one final one if that's okay.

I think if you look at this historically, at the market as you approach the month of August, indeed as you get into August and early September, cracks generally have come down absent hurricanes, and we're certainly not praying for anything like that. I think the market is normalizing here a bit. Effectively the United States is already self-sufficient in gasoline production. We have the Gulf Coast exporting a great deal of gasoline down to particularly markets in South and Central America. I think Mexico is taking 455,00,000 barrels a day. And of course the East Coast will always be an imported even from the Gulf Coast or from sources outside the United States. The East Coast is about 25% self-sufficient in its gasoline production. So I think the markets are normalizing a bit. The whole discussion and indeed the movement of share prices in the refining business, the domestic refining business can be traced over the past few months to changes in the Brent TI spread. I also think that's a bit overdone. My only guess is, Brent TI normalizes somewhere between $5 and $8 a barrel, the out months probably a bit higher than the in-months probably a little bit lower.

My final question guys is, can you just remind us where the threshold economics run for the completed rail facilities, and maybe a question with that, where you are in the exchange of your leased tankers relative to I guess your lower cost of fleet?

Tom, why don't you take that?

Okay. I could barely hear you there, Doug, but I think the first part of the question was regarding the rail facilities in terms of what they cost, was that correct?

Sorry, Tom, the threshold economics, I don't know if you can hear me better or not, threshold economics to basically continue to – to basically deliver into those nearly completed facilities at the higher rate.

Let me just take that question since I think I know more commercially. Look the threshold economics are comparative, they will always be comparative, what does a Bakken crude look like relative to the alternative of an imported barrel of crude. In fact in the third and fourth quarter, we have a significant volume of Iraqi crude coming in which could conceivably reduce our appetite on the Canadian side. The Bushehr crude is landing at differentials which are very, very attractive to us. Now it's a push/pull. If we see an opportunity here on the Canadian side that's suddenly, gee wiz, that's better than the Middle Eastern crude coming in, we'll pull a little bit more on that. So it is a comparative thing. On the Bakken side, we're landing Bakken into the refinery at a discount to Brent. I think as long as we're able to discount Bakken into that refinery at a discount to Brent, we're going to try on running that very high numbers. My only guess is, we will creep up very quickly above the 100,000 barrel a day Bakken number, and I think that's sustainable for quite some period of time. The Canadian, as the production grows, yes, it's very attractive crude to us, but we are if anything a commercially driven company and we don't want to go on autopilot in the sense of, gee wiz, we said we'll take in 80 a day of Canadian heavy and say 120 a day of Bakken, we will take in as much as we can provided we don't see better economics on the import side.

The one thing I would add to that in terms of, as I said in my remarks, right now Bakken and heavy Canadian crudes are near the top of the pecking order. As Tom says, it's a push/pull and we like that all the time, but one thing I would point out is we are in the process of improving our transportation cost particularly on the heavy crude but we are now bringing in unit trains of heavy instead of manifest trains that we've been doing uptil maybe two, about six weeks ago or so. It's going to increase, we're looking to do more of that out of Hardisty and that frankly does improve the transportation economics value couple of dollars a barrel.

We'll go next to Jeff Dietert with Simmons. Please go ahead. Jeff A. Dietert - Simmons & Co.: Kind of a follow-up to Doug's question, as you talked about the volumes you are expecting to bring in by rail in 3Q, as you've got the facilities fully operational in 4Q, what do you think the rail volumes will look like on the light and heavy barrels and what barrels do you expect to displace as you ramp up your rail volumes?

Let me take that. Obviously the rail facilities, the enhanced rail facilities didn't really operate during the month of July. So for one third of the third quarter you can assume we had the same or slightly less capacity, particularly on the dual loop track where we had to work right around the operation. So when we're welding and doing work like that, we in essence had to slow it down. If you look at the fourth quarter, and I think that will be the telling quarter, we certainly like to run the light rail facility over 100,000 barrels a day and we would certainly like to run the heavy facility over 70,000 barrels a day. Whether we do or we don't is not relative to our operational capability, it's relative to what we see in the marketplace. And again, in terms of replacement crudes, given the complexity of Delaware and Paulsboro, we really can switch back and forth rather easily. So we're not in a situation where we would have to replace every light barrel with another light barrel, we could bring in a medium sour barrel and we could run that. It's really hard to give you exact numbers because we want to maintain that commercial flexibility. Jeff A. Dietert - Simmons & Co.: But generally speaking, the rail volumes are competing with imports?

The rail volumes are absolutely competing with imports. Jeff A. Dietert - Simmons & Co.: Secondly on strategic question with Blackstone and First Reserve having significantly sold down their interest in some reorganization on the Board, are there any changes we should expect in the strategy of the company perhaps specifically related to acquisitions?

I think it's fair to say that instead of 'significantly sold down their position', let me put it this way, I think I own more shares than Blackstone and First Reserve do combined. So they are basically out of the picture. We have one Director from Blackstone, David Foley, still on our Board of Directors. I don't know how long he will stay on. He's an extraordinarily experienced energy executive and certainly we're not interested in pushing him off, but my own guess is that from Blackstone's point of view that's probably not something that they want to maintain. The departure of these two private equity firms from the Company certainly frees up our ability in the future to do transactions, acquisitions a bit more easily. It really practically speaking would've been impossible for us to have an equity component of any substantial acquisition while at the same time we had private equity selling. So certainly we're in a much more comfortable position from that point of view. We are now truly a public company and we don't have that overhang issue which has been there since we took the Company public in December of 2012. In fact, it's been a pretty quick exit on their part.

We'll go next to Paul Cheng with Barclays. Please go ahead.

I know that it's early-stage, have you guys looked at the new railcar proposal, the option one and two, what is the rough estimate that how much you have to spend to complying to those two options?

Tom, why don't you take that?

Sure. Paul, we have looked – just as backdrop, we'll specifically give you our views on the cost. Obviously there's two proposals out there, one from Canada TC, Transport Canada proposal, and then there's these three options from the DoT that are out for consideration and on comment. There's a difference between those. We certainly hope and believe that in this 60 day period and then beyond when the final rulemaking is done, that those proposals will converge, and at North America we'll have one proposal that will be consistent for both Canada and for the U.S. Basically we look at the cost of retrofit to be somewhere between $15,000 and $25,000 a car if you go with the United States version. A little bit less actually if it was the Transport Canada rulemaking that prevailed. So somewhere in that $15,000$ to $20,000 range and that's dependent upon where you are, but obviously to put full shields on the front and the back of the railcars, jackets, the brakes, if they prevailed, we think it would be somewhere in that range. I might also point out that it's going to be very interesting with these proposals because it is not just rail, a crude by rail, obviously as you look at these things you all see that it covers all flammable liquids including ethanol and in fact petrochemicals, and petrochemicals pretty much move by rail out of the refining industry in the United States and the Gulf Coast. So I suspect there's going to be a lot of comments that are made and a lot of discussion that has to happen because this as I said is really going to have an impact much broader than just moving crude by rail.

Let me just add something there, Tom. If you will recall, the EPA's desire for 15% ethanol, which turned out to be in essence a mathematical impossibility, the timing on the proposal from the DoT is undoubtedly an impossibility. Could we meet the timing? Yes, I believe we probably would not have a problem because our entire fleet are new cars already and the revisions that we would have to make are relatively marginal. But you are talking about a fleet across the country of such massive size that the facility simply don't exist at the present time to do this. So my own take on the DoT is, if they will come up with revised requirements, and certainly the full crush shields front and back on the cars will be an important part of that, but I think you're going to see the timing extended there by 18 to 24 months because they simply can't get the fleet revised. There will be changes in railcar requirements. Hopefully the United States and Canada can come up with a common standard. But for us again, I think we're – whether you can call it by intelligence, blind luck or some other method, we're probably the best placed company with a completely modern rail fleet. Every car we have in the crude oil movement fleet was built I believe post-2010 and meets most of the standards that they are suggesting.

Tom, can you remind me how many railcars that you actually own?

I'm going to defer that to Erik because the actual ownership could be confused with leased. The overall fleet will be a bit over 5,000, but Erik, why don't you comment?

We have the fleet size that we estimate by the end of 2015 is going to be approximately 5,900 cars. We currently have just over 3,000 in hand and we leased a vast majority of those. We have a couple of hundred that we own today.

And Erik, why don't you mention the lease term for the benefit of the listeners?

Average lease term is between 5.5 and 6 years.

Right, but the lease term, you will not be responsible for the capital cost, right?

No. Typically within these leases, the lessor is not responsible, the lessee is responsible.

Right. So I just wanted to note that, I mean how many car you actually are responsible for the retrofit yourself?

The lessees generally are responsible. If some type of legislation is put in place, they will be required to not necessarily pay upfront, they can actually spread the cost of the retrofit throughout the life of the lease, but the lessee will be responsible for upgrade.

I think you should look at, if there are significant changes on railcars and the cost is let's say $15,000 a car for the cars that we have, I think you should make the assumption that one way or another it will come out of our pocket.

Sure, absolutely. Three simple questions. Erik, what's the second quarter hedging losses? Seems that you guys are not going to do any more hedging.

The overall second quarter hedge loss was approximately $40 million.

$40 million, pre-tax right?

That's the pre-tax.

Do you have a breakup, a breakdown between the two systems?

No, the breakdown really should be between the crude oil portion which probably represents – Erik, if I'm wrong, correct me – 65% or 70%, and the balance relates to trades, quality trades, Brent WTI, Brent Mars, ASCI hedges, which at the end of the quarter had a negative impact on the hedge front, but it's been marked-to-market. Today I suppose the negative would go to a positive while the hedge loss on the crude side is a true loss, if you could talk about poor timing. And here the full responsibility should rest on my shoulders rather than anybody else. We made a decision in principle that when the Morgan Stanley deal came off, that we would remove the crude oil hedges. If you had told me that prices would drop the way they did drop, maybe I would have acted differently, but we established that and we've in essence, Paul, normalized the Company relative to our peer group. Most of our management team has been involved in the past and other independent refiners and this was really the only independent refiner we were involved in that had to hedge its crude oil, and that was a function of the financial arrangements that the company made when it was in essence owned by private equity.

I totally agree with you. I mean I never understand why they want to hedge it. So you said as of the…

By the way the hedge, I don't know if you missed in Erik's remarks, the hedging cost during the first half of the year was about $22 million and we're not going to be rolling crude oil in the future in a backwardated market. We average where the roll was $0.80 or $0.90 a barrel and where a one month roll on the Toledo hedge was costing us $3 million. And we had no choice, that was the terms of the agreement. And again, not being critical of private equity, but everybody on the phone understands private equity's desire, rate of return on capital employed, they love to see a lot of leverage in the company, and absent the leverage we did these commercial arrangements. Certainly not something I ever liked or desired but we did I believe set a record, and you can please check this, private equity did not take special dividends and that is…

That is probably a record. So, Tom, should we assume that starting from June 30, that you no longer have any hedges on?

That's what you should assume that we don't have any crude oil hedges on. We consistently, and the market should be aware of this, if our commercial team enters into a contract to acquire WCS, and let us make the assumption $24 under WTI for let's say delivery of 5,000 barrels a day in the fourth quarter, we will at that moment in time put a Brent WTI spread on, and since it's out month spreads, those numbers generally come in at a higher level. So today perhaps that would be averaged somewhere close to $7.5, $8. Those are put on because our pricing basis is not WTI. If we buy in the Bakken from one of the suppliers there and let's say we buy Bakken at $10 under TI in the field, and again the same type of thing, 5,000 a day in the fourth quarter, we really don't want to be exposed to the movement of Brent TI. So we want to put on, is it a good deal for us? Yes, if we put that spread on that base. So we don't speculate on the spread. We're simply trying to get to that point which then let's say will deliver either the WCS into our plant at $14, $15 under Brent and the Bakken into our plant at $2 or $3 under Brent. That's the basis. So, we always have those trades on and they are substantial, but that's effectively the extent. And I don't view that as hedging in the classic sense of the word. I view that as establishing your price basis.

Right, you're just not in the basis?

Yes, but we have to mark that to market every day. And by the way, if we marked Brent WTI trades to market today, I suspect you have $10 million, $15 million, $20 million to the better.

Two final questions. Tom, on the 50,000, 60,000 barrel per day of the Canadian heavy you were in, are those niche bitumen or WCS look-alike? Second one, versus the first quarter, when you're talking about the lower earnings due to lesser butane branding, any rough number that you can share that how big is that impact?

The first part of the question, we run a mix of blended crudes, WCS crudes, and we also bring in straight neat bitumen. There's bitumen in that number that you just quoted and we've given you, is about 15,000 barrels a day right now, so 15,000 a day of bitumen and the rest is blended crudes. On the second part of the question, the impact of going into the lower RVP season, this is actually rather significant for the industry. For our system, you can look at it, it's somewhere between 1.5% and 2% of the shift from gasoline to LPGs seasonally. So in the summer you'll see our clean product yield, gasoline yield go down by 1.5% to 2%. Actually it's a little bit higher in Toledo. And you'll see LPG yields go up by a corresponding amount and you can take a look at the pricing of those two commodities and figure out what the impact is. It is not insignificant.

Frankly, it's massive. Just think in terms of selling gasoline at I don't know $3 a gallon hypothetically and then selling butane at, I don't know what it is today Tom, but certainly I would guess maybe $1.

Yes, so frankly today the spread is $70 a barrel between, or $75 a barrel between gasoline and butane. So now I've given you the number, you can…

So 1.5% is $1 across the production.

We'll go next to Mohit Bhardwaj with Citigroup. Please go ahead.

Tom, I just wanted to ask you about, you mentioned briefly about more freedom as far as acquisition opportunities are concerned and you have mentioned that in regard with PBFX as well. Could you just update us on where do you stand with that, and like you mentioned California in the past, are there other opportunities available right now either just on logistics side or on the refining side?

I don't want to talk about PBFX. There will be a separate conference call on that. The only thing we can say is that when we did our roadshow, we were very straightforward about our ability to drop-down, and certainly there has been research published by your industry which encourages the independent refining sector to drop-down now rather than later, and by the way, that was by another company not yours, and I do tend to agree that dropping down sooner rather than later is a good idea. With regard to the refining market, we've been very clear that we've been looking at opportunities particularly in California, and we say particularly in California because that's where most of the opportunities have been, it's a market where we have as a team experience, it's a very difficult market. I always warn our team that when we look at California, we must look at it to some degree almost as a different country and as a different set of requirements, but we're familiar with them and certainly we have lived with them in the past. There's nothing to report today on that. Obviously I think most of the folks on the phone are aware of the most recent chatter about Citgo and assets coming available from that source. It's certainly something that we would follow up on. But you can assume that we will follow-up on absolutely everything. That's our job, we need to be aware of what's happening in the market and we are in a much better place today than we were at the beginning of the year in terms of our ability to consider acquisitions that might potentially require some equity portion to make the acquisition.

And Erik, if you could just clarify for us, out of the $40 million hedging impact that you talked about, $22 million is the realized part of it, so that's what I think Tom was talking about in terms of 65% to 70%, is that the right way to read it?

It is approximately $30 million across everything on the realized basis and $10 million for unrealized.

Okay, thank you for that. And if I could just one final one, Tom, if you could just talk to us about the European refining market and in fact the slowdown in the shutdowns this year and the impact on the Atlantic Basin margins overall just because of that as Juvel has come online and Russia is putting more product into Europe, if you could just talk about that a little bit?

I think, look, the European refining market is under enormous pressure. Certainly Russia is exporting less crude oil and more products and they are exporting that product to Western Europe. I think there will be additional pressure coming out of the Saudi export refineries. I think everybody is aware of the comments from [many] (ph), they are trying to close down three refineries. European refining, indeed of course I have some experience there, and I didn't want to tell you, it's very positive experience, but there are structural issues that are in my view probably not possible to overcome. How can they compete? They are having their natural gas price up around $11, our natural gas cost in the month of August at Paulsboro and Delaware will I believe be delivered into the plant will be under $3. They have a currency which if you look at wage rates and benefits, you can say $1 equals €1, and if you have euro trading in the 36%, 37% premium to the dollar, that makes it tough. And then there's a final issue on crude oil. It's quite clear, notwithstanding the possibility of some condensate or lightly processed light and export that the United States is going to enjoy a crude oil price advantage over Western Europe of a number that is probably more than $1 a barrel and could be $3 a barrel. I don't think you can make that up. And so I'm quite negative on European refining.

We'll go next to Cory Garcia with Raymond James. Please go ahead.

Just quickly turning back to crude by rail side, I believe some of the strains on the Canadian heavy side were based on sort of loading capacity up north and also some of the sourcing, ability to source coiled railcars. Is it safe to assume that sort of these hurdles are behind you guys at this point and it is just simply commercial economics driven decision?

I think we can say with some degree of certainty that as we start this winter, we are far better placed first of all in the availability of our own coiled and inflated railcars, and secondly the Canadian industry is far better placed at this point in time with loading facilities as Tom Nimbley mentioned, we're actually now bringing in unit trains of Canadian heavy. The difference in a unit train loading and a manifest loading is enormous for us. It's measured in anyway a couple of dollars a barrel, less cost to get that crude oil into our refinery. Notwithstanding that, no one should make the assumption that they are growing palm trees up at Hardisty and Edmonton, and a severe winter will always tend to complicate things a bit, but we're pretty well placed that, we are confident of our ability that we can bring in much larger volumes of Canadian heavy, and indeed we've taken steps to buy it right through the end of the fourth quarter. So this is not hopes and dreams.

Okay, that's great. And I guess turning to Toledo, any updated thoughts on rail potential there? I mean we've had quite a few Bakken pipeline announcements that are beginning ahead into the Midwest seemingly three years from now, but obviously the flexibility that a rail terminal will provide in Toledo, jus help me with some updated thoughts?

Tom, why don' you take that?

Very good question. I'll just make a couple of comments. You'll see we actually have expanded the amount of crude we're bringing in through our truck unloading rack and we're going to be upwards of 15,000, 16,000 barrels a day. We actually were at [Oso] (ph) plant and in fact we'll resume this, move unit trains into Toledo, and do that with third parties and move it over. We were planning to do that just about the time that we had the FCC come down in Toledo. So we just moved those trains over to Delaware. And again, that's the benefit of the optionality that we have. So we were going to go to Toledo, that option shut down, and we just simply shifted it and used those trains, had the capability of unloading them in Delaware City. As I mentioned, we're going to start that up. Again it's kind of third-party based but we are actively looking at how to effectively put in a rail unloading facility here within the property of Toledo or very close that will be our own so that we can reduce the cost of the middleman, and those studies are underway as we speak.

Okay, perfect. And lastly just I guess a quick housekeeping item for Erik. Should we be just assuming that LIFO charges is spread evenly between the two refining systems?

Yes, that's a decent assumption. It's a little bit more weighted towards the East Coast simply because you have more barrels there, but overall it's relatively even pro rata split.

There are no further questions. I'd like to turn it back over to Mr. Tom O'Malley for any closing or additional remarks.

Thank you very much for attending today's call. We're going to do the best we can to capture every single penny available that the market gives us. We look forward to having you on the next earnings call. Thank you.

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