PBF Energy Inc (PBF) 2014 Q2 法說會逐字稿

Welcome to the PBF Energy second-quarter 2014 earnings conference call and webcast.

(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'd like a copy of today's press release, you can find one on our website, www.PBFenergy.com. Attached to the earnings releases 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 describe 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 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 the 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 reported second-quarter operating income of $87.9 million, and adjusted pro forma net income for the second quarter of $34.2 million or $0.35 per share on a fully exchanged, fully diluted basis. This compares to operating income of $133 million and adjusted pro forma net income of $71.5 million, or $0.73 per share, for the second quarter of last year. EBITDA for the quarter was $120.1 million and $411.6 million for the first half of 2014.

Our results for the quarter reflect the impacts of a rising flat price environment on our input costs. Under LIFO, the most recently purchased barrels are the first barrels recognized in our cost of sales, which results in higher input cost in this type of environment. The inverse is true in a declining price environment.

For the second quarter, LIFO expense amounted to a pretax charge of $46.2 million, or $0.28 per share on an adjusted pro forma basis. And our year-to-date results reflect a LIFO charge of approximately $107.8 million. Our LIFO figures are calculated on a changing value of our base total hydrocarbon inventory, which for 2014 is approximately 13.9 million barrels.

We had approximately $29.5 million of RIN expenses in the second quarter, which is higher than planned, as the market prices of RINs has remained elevated in the face of uncertainty caused by continued delays in the EPA's yet-to-be-determined rule making for 2014. For the second quarter, G&A expenses were $33 million, compared to $19.1 million during last year's second quarter. The increase in G&A expenses primarily relates to higher employee compensation expense, mainly related to increases in headcount and incentive compensation.

D&A expense for the second quarter was $34.7 million, as compared to $27.6 million for the year-ago period. And second-quarter interest expense was $26.2 million, compared to $21.7 million last year. PBF's effective tax rate for the second quarter was 39.2%, and going forward for modeling purposes you should assume a normalized effective tax rate of approximately 40%.

At the end of June, our cash balance was approximately $317.5 million. This cash position reflects earnings and working capital movements mainly related to a build in hydrocarbon inventories. We received approximately $335 million in net proceeds from the IPO of PBF Logistics.

CapEx was $82.5 million, and we paid $84.3 million in taxes, dividends, and distributions. Our net debt to cap ratio was 17% at the end of the second quarter, down from 28% at year end, and we had over $800 million in available liquidity at quarter end.

Our Board has approved a quarterly dividend of $0.30 per share, payable on August 27 to shareholders of record as of August 11. At this time, PBF's dividend policy remains unchanged.

For modeling our full-year and third-quarter operations, we expect refinery throughput volumes should fall within the following ranges for the full year. The Mid-Continent should average 135,000 to 145,000 barrels per day, and the East Coast should average between 315,000 and 335,000 barrels per day. For the third quarter, the refinery throughput volumes for the Mid-Continent should average between 145,000 and 155,000 barrels per day, and the East Coast should average between 300,000 and 320,000 barrels per day.

On the East Coast we expect to receive by rail approximately 80,000 to 90,000 barrels per day of light crude oil, and 50,000 to 60,000 barrels per day of Canadian heavy during the third quarter. We expect our operating costs for the year to range between $5 and $5.25 per barrel, which is consistent with our guidance provided on the first-quarter earnings call.

For 2014, we expect CapEx, including turnarounds but net of rail cars, to be approximately $300 million, an increase from our previous guidance of $275 million. The change in guidance is primarily attributable to increased costs associated with the approximately 40-day plant-wide turnaround at Toledo in the fourth quarter.

In addition to the financial recap, I'd like to comment on a few notable items that occurred during the second quarter. In May, we successfully completed the IPO for our MLP, PBF Logistics LP. This event is a significant milestone for the Company, as it strengthened our balance sheet and provides PBF Energy with a partner for growth.

For more information on PBF Logistics, please refer to that Company's earnings release, which was also distributed this morning and is available on the PBF Logistics website at www.PBFlogistics.com. PBF Logistics will host its first earnings call at 11:00 AM this morning to review its second-quarter results.

In June, our private equity investors, Blackstone and First Reserve, successfully sold an additional tranche from their existing holdings through an underwritten offering by Citigroup and Deutsche Bank Securities. After the effect of the sales, over 90% of the fully diluted, fully exchanged shares are now listed on the New York Stock Exchange and in the hands of public investors.

Also in June, we announced the termination of our Mid-Continent crude supply agreement with Morgan Stanley. Under the terms of the agreement we were required to hedge 100% of the crude, or approximately 4 million barrels, purchased through Morgan Stanley for the Toledo refinery.

In addition, PBF also hedged approximately 6 million Brent-based barrels for our East Coast system. The net cost of this combined hedging program was approximately $22 million for the first half of 2014. In conjunction with the termination of the Morgan Stanley agreement, the Company no longer hedges approximately 10 million barrels of crude oil and thus will avoid in the future the cost of rolling this hedge in a backwarddated market.

In the past 18 months, we transitioned away from our original supply and offtake arrangements that were necessary in our initial development. Our strong financial position allowed us to complete the latest transition from the Morgan Stanley crude supply deal, and PBF now faces the market directly, versus working through intermediaries.

As we continue to grow, we feel that an unhedged strategy aligns us with our peers and is indicative of the continued evolution of our Company. We believe the combination of PBF facing the market and the unhedged strategy will result in lower cost of crude throughout our refining system. I'm now going to turn the call over to Tom Nimbley for his comments.

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 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 barrels a day, with the Mid-Continent averaging 147,000 barrels a day, and the 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 the East Coast, and $5.41 per barrel in Toledo.

The Mid-Continent 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 a $2.50 per barrel swing. On average, syn crude price $0.72 under WTI on an FOB basis during the second quarter, versus $0.99 under WTI in the first quarter. It is very important to note that our landed costs can differ from the calendar-quarter average for several reasons, basically associated with the timing between the pricing of a deal and when it is ultimately run through the refinery.

The Brent 2-1-1 East Coast crack averaged $13.70 per barrel, up from the first-quarter average of $11.41. The refining margin for our East Coast system was $6.38 per barrel, versus a margin of $13.71 in the first quarter.

On the East Coast, our landed cost of crude was about $5.16 per barrel under Brent, versus $8.23 under in the first quarter. For the quarter, we discharged approximately 75,000 barrels a day of light crude oil, and about 41,000 barrels a day of heavy crudes to Delaware by rail.

In addition to our rail delivered crudes, we continue to use our flexibility to take advantage of favorable pricing for water-borne barrels when the opportunities arise. It is important to note that while the benchmark cracks improved slightly for each of our refineries, the high flat price environment means that the margins for our low value products such as coke, sulfur, C02, and LPGs, are negatively impacted, as those prices are not elastic. Those prices generally do not rise like clean product prices, as the price of crude goes up.

Additionally on the blending side, during the summer months margins are placed under additional pressure as refiners for the most part lose the ability to blend butane into the product pool as we must meet the summertime RVP specifications. In summary, these impacts along with the overall tighter crude differentials result in lower capture rates of the benchmark cracks across our refineries.

In the third quarter, we expect to bring in by rail about 80,000 to 90,000 barrels a day of light crude oil, and approximately 50,000 to 60,000 barrels a day of heavy crudes. As mentioned in our press release this morning, the heavy crude oil unloading expansion, or west rack, is complete and has already begun discharging crude oil.

The expansion of PBF Logistics' loop track should be complete next week. The loop track capacity increases from 105,000 barrels per day to 130,000 barrels a day, and the heavy unloading capacity increases from approximately 40,000 to 80,000 barrels a day. Both of these projects are being delivered on time and on budget.

The completion of these projects will enable us to more aggressively pursue our strategic goal of sourcing cost-advantaged North American crude oil in greater volumes. Today, these North American heavy and light barrels are at the top of our preferred feed stocks list.

Staying on the rail for the moment, we are aware of the recent announcements in both Canada and the US regarding new standards for rail operations and tank cars. I would like to reiterate that as of the end of the second quarter, 100% of the crude oil deliveries, light and heavy, to PBF's rail facilities are being transported on the newest and safest CPC-1232 standard rail cars. We are evaluating the various proposals that have been announced and feel that we are well positioned to meet any standards that are finalized.

For the third quarter of 2014, we expect our landed crude costs, excluding any hedging or LIFO effects, to be about $2 to $3 a barrel over WTI for the Mid-Continent, and $5 to $6 a barrel under Brent for the East Coast. Looking forward, we continue to see the benefits of increasing our ability to import greater quantities of North American crude into our East Coast system.

Overall, we had a positive second quarter despite some missed opportunities. Our first-half results continue to reflect the improvements to the East Coast operation, as the East Coast has contributed more than 45% of the approximately $475 million in refining EBITDA through the first half of the year.

As I mentioned earlier, we are undertaking a major turnaround in Toledo in the fourth quarter, and I want to expand a little bit on the benefits of this work. In general, turnarounds are staying business activities meant to keep the units operating.

Our $130 million turnaround in Toledo this year includes modifications that will result in incremental gross margin of between $40 million and $50 million. The increased margin is a result of improved yields from the cat cracker and increased distillate production capability.

Coupled with the new 450,000-barrel crude tank that we are currently in the process of completing, the increased storage of crude oil at Toledo, we expect the total annual margin uplift for the refinery to be about $60 million. Our strategy of sourcing the most economic barrels available for our system, and by being flexible between domestic and water-borne crude oil procurement, has proven and should continue to prove profitable for our refineries. We will continue to invest in our assets to increase their profitability and look to grow the Company through sensible acquisitions in order to increase shareholder value.

From a market perspective, so far the third quarter has presented a challenging landscape in which to operate. We will continue to run our refineries safely and position ourselves to take advantage of any opportunities that the market presents.

While crude oil differentials remain tight and product margins have contracted, we have experienced some relief as flat price has come down from the second quarter. I would now like to turn the call over to our Executive Chairman, Tom O'Malley.

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.

The takeover for Morgan Stanley in Toledo will, I believe, in fact I'm certain, lower Toledo's crude costs, and Tom Nimbly 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.

Good morning, guys.

Good morning.

I noticed you provided the operating cost by region. That's helpful. I guess I'm surprised that East Coast is lower than the Mid-Con or Toledo. Is that just related to the FCC issue in the quarter and not representative? And maybe that's also going to change with this major 4Q turnaround effect. Maybe if you could comment on that, I'd appreciate it. And I have follow-up.

Toledo was impacted slightly because of the lower throughput and the cat cracker shut down that we had at the end of the quarter. 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 Marcellus and Utica. So we have an advantage on the East Coast. In fact, we have an advantage in the East Coast versus anywhere on the Atlantic basin.

Also Toledo outsources some of their waste water treatment facilities to a third party and there's a little bit of an extra cost there. I would expect Toledo's costs to continue to come down, but I suspect the East Coast will also come down some as we go across the rest of the year and there will be a slight spread with Toledo being a little bit higher.

Okay. That's helpful. My other question is Delta recently announced it's securing a Jones Act vessel for crude supply. I know you have superior rail position. Given maybe crude export uncertainty that could relate to the Jones Act, how does PBF 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 a 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 a barrel, while foreign flag movement is up to the East Coast a little bit less than $2 a barrel. How can anybody make that delta up, I'm not quite sure. But we're not considering Jones Act at the present time.

I would add one thing on that. For a refinery like Trainer PES, other light sweet refineries in the East Coast, their only option is sweet crude. 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 Forcados or Qua Iboe from West Africa.

We have the optionality of not only running the domestic heavy crudes or light crudes, but also we have water-borne 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. Maybe lastly if I could, one for Tom, Tom O'Malley, a broader policy question. I know the East Coast refiners played a key role in the proposed RVO reduction that reduced Brent pricing last year. But do you see a similar position for the East Coast and for PBF and the crude condensate debate as it affects your region? And also relates to the Jones Act which as you mentioned is more other people and regions, movement of choice.

Well, 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 the United States is 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, a 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 whiz, 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.

Thanks. Good morning everybody. Either Tom, I wonder if I could start with a quick housekeeping question. You did mention the 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 prices. So I'm just curious to what extent you can quantify any reversal in LIFO quarter to date? And then I've got more of a strategic follow-up please.

I'll take the first piece of this. The lost profit opportunity for Toledo is about $15 million for the FCC down time, and a very high percentage of that as you can imagine was margin, a little bit of OpEx but mostly margin.

With regard to LIFO, obviously with the 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 of the $100 million-odd 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 30 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 that 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. When you look at your markets, at least the way we think about it is if the US becomes self-sufficient gasoline as 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. We're trying to figure out if this is some kind of transitional period when domestic gasoline prices are moving more towards domestic price, of crude that is. Just curious what you're seeing in your market. If I may, I've got one final one.

I think if you look at 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's 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's taking 450,000, 500,000 barrels a day. And of course, the East Coast will always be an importer, either from the Gulf Coast or from sources outside the United States. The East Coast is about 25% self-sufficient in its gasoline production.

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 own guess is Brent TI normalizes somewhere between $5 and $8 a barrel, the out months probably a bit higher, the near-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 another question with that, where you are in the exchange of your leased tankers relative to your lower cost fleet that you talked about?

Tom, why don't you take that?

Okay. Well, I could barely hear you there, Doug. But at least I think the first part of the questions was regarding the rail facilities in terms of what they cost? Is that correct?

That's right, Tom, the threshold economics, don't know if you can hear me better now, threshold economics to basically continue to basically deliver into those new completed facilities at the higher rate.

Let me just take that question, since they still think I know more commercially. Look, the threshold economics are comparative. They'll 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 significant volumes of Iraqi crude coming in, which could conceivably reduce our appetite on the Canadian side.

The Bashrah 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 suddenly, gee whiz, that's better than the Middle Eastern crude coming in, we'll pull a little bit more on that. It is a comparative thing.

On the Bakken side, we are 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 and run it at very high numbers. My own 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, well 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 whiz, we said we'll take in 80,000 a day of Canadian heavy and say 120,000 a day of Bakken. We will take in as much as we can, provided we don't see better economics on the import side.

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 push-pull and we'll watch that all the time.

But one thing I would point out is we are in a process of improving our transportation costs, particularly on the heavy crude. We are now bringing in unit trains of heavy instead of manifest trains that we've been doing up until 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 by a couple of dollars a barrel.

Thanks, guys. Appreciate the answers.

We'll go next to Jeff Dietert with Simmons. Please go ahead.

Good morning.

Good morning, Jeff.

A kind of a follow-up to Doug's question. You talked about the volumes you're 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 operations. 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'd 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.

Generally speaking, the rail volumes are competing with imports?

The rail volumes are absolutely competing with imports.

Secondly, a strategic question with Blackstone and First Reserve having significantly sold down their interest and some reorganization on the Board; are there any changes we should expect in the strategy of the Company, perhaps specifically related to acquisitions?

Well, 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're 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 have 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.

Thanks for your comments.

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

Good morning, guys.

Good morning, Paul.

I know that it's early stage. Have you guys looked at the new rail car proposal, the option one and two, what is the rough estimate and how much do you have to spend to comply to those two options?

Tom, why don't you take that?

Sure. Paul, we have looked just as backdrop, we'll get to specifically give you our views on the costs. Obviously there's two proposals out there, one from Canada, TC, Transport Canada, proposal, and then there's the three options from the DOT that are out for consideration and comment. There's a difference between those. We certainly hope and believe that in this 60 day period and then beyond when the final rule making is done, that those proposals will converge and that North America will have one proposal that will be consistent for both Canada and for the US.

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 will make and that prevailed. So somewhere in that $15,000 to $20,000 range. That's dependent upon where you are. Obviously, to put full shields on the front and the back of the rail cars, jackets, the brakes, if they prevail, 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 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 are pretty much moved 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're talking about a fleet across the country of such massive size that the facilities simply don't exist at the present time to do this.

So my own take on the DOT is that 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're suggesting.

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

I'm going to defer that to Erik because the actual ownership could be confused with lease. 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 lease the vast majority of those. We have 200 that we own today.

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

The average lease term is between 5.5 and 6 years.

Right. But the lease term you would not be responsible for the capital costs, right?

No, typically within these leases the lessor is not responsible. The lessee is responsible for the cost.

I just want to note that. How many cars 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 rail cars 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 loss? Seems that you guys are not going to do any more hedging.

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

$40 million. Pretax, right?

That's at pretax.

Do you have 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. If you mark them 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 in 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 never understand why they want to hedge it.

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. We're not going to be rolling crude oil in the future in a backwardated market. We have periods 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?

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, 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 average somewhere close to $7.50, $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 day. So we don't speculate on the spread. We're simply trying to get to that point which then let's say we'll deliver either the WCS into our plant at a $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're 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.

You're just in the basis.

We have to mark that to market every day. By the way, if we mark the Brent WTI trades to market today I suspect you'd have $10 million, $15 million, $20 million to the better.

Two final questions. Tom, on the 50,000, 60,000 barrels per day of the Canadian heavy you rail in, are those neat 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 help [ease 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. That'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, of the impact of going into the lower RVP season, it's actually rather significant for the industry. For our system you can look at it, it's somewhere between 1.5% and 2% of a 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, frankly today the spread is $75 a barrel between gasoline and butane. So now I've given you the number you can --

1.5% is $1. Across the production.

Very good. Thank you.

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

Thanks for taking my questions. This is Mohit Bhardwaj from Citigroup. 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 update us on where do you stand with that? And you mentioned California in the past. Are there other opportunities available right now either just under the fixed side or on the refining side?

I don't want to talk about PBFX. There will be a second, 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 a -- 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 has a different set of requirements. But we're familiar with them and certainly we've 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 what's happening in the market and we're 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.

Thank you for that. 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 Thomas was talking about in terms of 65% to 70%. Is that the right way to read it?

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

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 [your well] has come online and Russia is putting more product into Europe, if you could just talk about that a little bit.

Well, I think, look, the European refining market is under enormous pressure. Certainly Russia is exporting less crude oil and more product and they're 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 Eni, they're trying to close down three refineries.

European refining and indeed of course I have some experience there, and I don't want to tell you it's a very positive experience, but there are structural issues that are in my view probably not possible to overcome. How can they compete? They're having a 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 looked at wage rates and benefits you could say $1 equals 1 euro, and if you have a euro trading at a 36%, 37% premium to the dollar, that makes it tough.

And then this final issue on crude oil. It's quite clear, notwithstanding the possibility of some condensate or lightly processed light end 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. So I'm quite negative on European refining.

Thanks for your comments.

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

Just to quickly turn back to crude by rail. 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, the ability to source coiled rail cars. Is it safe to assume that sort of these hurdles are behind you guys at this point? 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 insulated 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 -- well, 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're growing palm trees up at Hardisty and Edmonton. A severe winter will always tend to complicate things a bit.

But we're pretty well placed that we're 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. I guess turning to Toledo, any updated thoughts on rail potential there? We've had quite a few Bakken pipeline announcements that are heading in the Midwest, seemingly three years from now. Obviously the flexibility that a rail terminal would provide in Toledo, just hoping for some updated thoughts.

Tom, why don't you take that.

Very good question. 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 -- we also plan and in fact will resume this, move unit trains into Toledo and do that through 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. 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 either 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. Lastly, just I guess a quick housekeeping item for Erik. Should we be just assuming that LIFO charge 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 a relatively even pro rata split.

Thanks for the color, guys.

And 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. 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.