PBF Energy Inc (PBF) 2014 Q3 法說會逐字稿

Good day, everyone, and welcome back to the PBF Energy third-quarter 2014 earrings conference call and webcast.

(Operator Instructions).

It is now my pleasure turn the floor over to Erik Young, Chief Financial Officer. Sir, you may begin.

Thank you. Good morning, everyone, and welcome to our third-quarter earnings call.

On the call with me today are Tom O'Malley, our Executive Chairman; Tom Nimbley our CEO; and 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. Before we get started, I'd like to direct your attention to the forward-looking statements 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 with 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 90.5% during the third quarter. We think adjusted pro forma net income and adjusted pro forma EPS are more meaningful to you because they represent 100% of the operations of PBF Energy Company LLC on an after tax basis. With that, I'll move on to discussing our third quarter results.

Today, we reported third quarter operating income of $284.1 million and adjusted pro forma net income for the third quarter of $155.6 million, or $1.60 per share on fully exchanged, fully diluted basis. This compares to an operating loss of $55.6 million and an adjusted pro forma net loss of $46.9 million, or a loss of $0.48 per share for the third quarter of 2013.

EBITDA for the quarter was $357.7 million and $769.3 million for the first three-quarters of 2014. Included in our results was a $28.5 million one-time non-cash charge related to the abandoned hydrocracker project at our Delaware City refinery.

We were able to achieve certain goals of the project in terms of producing low sulfur distillates by commissioning alternative lower cost projects that reconfigured existing processees. Our results for the quarter reflect strong operational performance, lower input costs as a result of the cop in crude prices, and favorable product margins specifically distillates sold in our East Coast system. For example, New York Harbor jet and ULSD traded at significant premiums over heating oil in the quarter and we were able to take advantage of the strong margin environment.

Additionally, we realize the improved margins on the lower value products as a result of the decline in crude prices. As we mentioned in our last call, we moved away from flat price hedging in conjunction with our exit from the crude supply arrangement in the Mid-Continent. We continue to maintain a basis management program for the majority of our East Coast crude oil inputs. For example, when we purchase crude on a WTI basis and sell the products in a Brent-based market, we enter into a Brent TI contract to establish the differential.

In the third quarter, we recognized a $49 million benefit as a result of the narrowing WTI Brent and ASCII Brent spreads. Our year-to-date figures also reflect a LIFO benefit of $47.2 million as a result of the overall decline in hydro carbon prices.

We had approximately $29.9 million of rent expenses in the third quarter and $89.5 million year-to-date at the end of the third quarter. As with others in our industry, we await the final rulemaking for 2014 and any guidance that can be provided by the EPA on 2015 obligations. For the third quarter, G&A expenses were $34.3 million compared to $30.7 million during last year's third quarter.

Depreciation and amortization expense for the third quarter was $68 million as compared to $27.4 million for the year-ago period. As mentioned a moment ago, the primary difference relates to the one-time charge associated with the write-off of the abandoned project.

Third quarter interest expense was $24.4 million compared to $26.2 million last year. PBF's effective tax rate for the third quarter was 40.3% and going forward for modeling purposes you should assume a normalized effective tax rate of approximately 40%. At the end of September, our cash balance was approximately $742.3 million. This cash and marketable securities position reflects earnings and normal working capital movements.

We received approximately $150 million in net proceeds from the sale of the Delaware City west tract PBF logistics in the form of $135 million in cash and $15 million in PBF Logistics common units for approximately 589,000 shares. CapEx, net of rail car purchases was $122.3 million and we paid $32.6 million in taxes, dividends, and distributions. Our net debt to cap ratio was 16% at the end of the third quarter, down from 28% at year end, and we had over $1 billion in available liquidity at the end of the third quarter.

Our board has approved a quarterly dividend of $0.30 per share payable on November 25 to shareholders of record as of November 10. At this time PBF dividend policy remains unchanged. For modeling our full year and fourth quarter operations, we expect refinery throughput volumes should fall within the following ranges for the full year. The Mid-Continent should average between 135,000 and 145,000 barrels per day and the East Coast should average between 315,000 and 335,000 barrels per day.

For the fourth quarter, the refinery throughput volumes for the Mid-Continent should average between 95,000 and 125,000 barrels per day, which reflects the impact of ongoing turn around on Toledo's operations in the quarter. East Coast should average between 300,000 and 320,000 barrels per day. On the East Coast, we except to receive by rail approximately 75,000 to 85,000 barrels per day of light crude oil and 45,000 to 55,000 barrels per day of Canadian heavy during the fourth quarter.

We expect our operating costs for the year to range between $5.00 and $5.25 per barrel. For 2014, we expect CapEx, including turn around but net of railcar purchases, to be approximately $325 million. This is an increase are from our previous guidance and relays to increased Toledo turnaround and return project expenditures. In addition to the financial recap, I'd like to comment on a few notable items that occurred during the third quarter.

In September, we successfully completed the drop down of the Delaware City west rack, the newly commissioned heavy crude oil unloading facility that's located at the Delaware City refinery. This transaction has provided PBF with additional resources to grow the Company and return value to our shareholders. PBF Energy has initiated the process of a second potential dropdown by submitting to PBF Logistics conflicts committee a proposal for the acquisition of crude and product storage facilities that are located at PBF Energy's Toledo refinery.

The PBF Logistics conflicts committee is engaged in the review and we are unable to comment further at this time. Finally, during the quarter, our Board of Directors approved a $200 million share repurchase program. We implemented the program in the second half of September following the announcement of the west rack transaction and repurchased approximately 1.35 million shares at an average price of approximately $24.00 per share.

The program has been active in the fourth quarter and we repurchased an additional 2.8 million shares at an average price of approximately $23.85 bringing the total purchase to date to approximately $100 million. Additionally, as of yesterday our board approved an increase of $100 million to the repurchase program for a total of $300 million with approximately $200 million remaining. This repurchase authorization expires in September of 2016.

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

Thank you, Erik. And good morning, everybody. Before discussing the third quarter results, which we are pleased with, I would like to comment on the most significant activity occurring at our Company today, which is the Toledo refinery wide turn around. Again, this is a plant wide event that involves not only the Toledo personnel, but also support teams from our other location. It is a company event in that respect and we are spending approximately $140 million in turnaround and additional enhancement projects over the course of approximately 40 days.

While the execution phase of the turnaround is only about 40 days, the planning has been going on since we bought the plant in 2011. We have moved in a tremendous amount of material, and last week we had over 1800 people in the plant working on the turnaround versus the normal complement of about 700 employees and contractors. I am pleased to say that the amount of effort we have put into planning this turnaround and the effort of the people on the ground is paying off and the turnaround is progressing well. We expect the turnaround to be complete in approximately two weeks.

It is important to note that the margin enhancement projects being installed during this downtime account for approximately 50% of the total spend and are expected to provide four year EBITDA benefits of around $75 million. We expect to see most of the benefit from these projects immediately upon startup.

However, we are also installing tie-ins to the completion of a chemical expansion project, which we put in service in July of 2015. After the completion of this project, we expect to realize the full benefit of all of our return projects. Returning to the results for the quarter, as is almost always the case, the market was the biggest factor for all of our refineries. The market provided the opportunity for us to be successful and through our safe and stable operations we were able to make the most of that opportunity.

Perhaps the most significant market move in the quarter, was the overall decline in the flat price of crude oil, WTI average almost $98 a barrel in the third quarter versus $103 a barrel in the second quarter. Brent average $102 during the quarter versus approximately $110 during the second quarter Both crudes ended the third quarter about $7.00 a barrel under their respective quarter averages. Moves of had this magnitude create opportunities in the product markets which PBF was able to take advantage of.

As Erik mentioned, we saw wide differentials in the quarter for distillates, particularly jet fuel, and the lower flat price increased our margin across the bottom of the barrel. For example, the asphalt business on the East Coast is a traditionally lower margin business, and in the third quarter of 2014 market asphalt margins improved by $12.00 per barrel versus Brent over the second quarter. While every product margin is different, almost all of them benefit from the lower flat price of crude.

Throughput for our overall system was about 495,000 barrels a day with the Mid-Continent averaging 151,000 barrels a day and the East Coast system ran approximately 344,000 barrels per day. For the quarter, operating costs on a systemwide basis averaged $4.41 per barrel. $3.99 per barrel on the East Coast and $5.36 per barrel in Toledo. We feel that the operating costs reflect not only the benefit of cheap natural gas due to our proximity to the Marcellus Shale, but also our improved operations.

The $3.99 per barrel East Coast OpEx is competitive in any region in the country. The mid-Continent 413 crack spread average $16.63 per barrel, a slight overall decrease to 2014 second quarter average of $18.78. Our margin at Toledo was $16.73 per barrel for the third quarter versus $12.79 in the second quarter. The increase in refining margin in Toledo is reflective of the strong distillate market, and as we mentioned, the decline in the flat price of our feedstocks.

The Brent 211 East Coast crack averaged $13.99 per barrel essentially flat for the second quarter average of $13.70. The refining margin for our East Coast system was $10.78 per barrel versus a margin of $6.38 in the second quarter. Our margin East Coast was favorably impacted, again by the decrease in the flat price of crude, and by the sales of barrels in excess of production out of inventory. We were able to use these inventory barrels to capture additional benefit of the strong distillate market.

For the quarter, we processed approximately 83,000 barrels a day of light crude oil and about 47,000 barrels a day of heavy crudes at Delaware City by rail. As Erik mentioned earlier, we were able to capture the benefit of both strong distillate and gasoline cracks and increased margin on lower value products during quarter, which were significant contributors to our overall results. Despite the volatility, we are continuing to see opportunities on both the crude and product side to enhance our earnings potential.

On the crude side, we are using our sourcing flexibility to pursue the most economic barrels available whether those are waterborne deliveries of crude or rail deliveries. Over the past few weeks, we have seen differentials tighten as crude prices have come down and this has caused some pinch points which will endure until the market adjusts to these new price levels.

During these times, we have some resilience in our feedstock sourcing. Our rail-delivered crews are more resilient than the spot prices would indicate due to our sourcing efforts and our ability to substitute in waterborne barrels from margin rail delivery barrels allows us to continue to source an economic crude slate for our refineries. It is this optionality, which we have built into the East Coast system, that allows us to be more flexible, pursue the most economic raw materials, and provides a competitive advantage versus the other pad one refineries.

On the product side, we have experienced wider product margins, especially for distillates, and these margins should endure until the project prices adjust to the lower price of crude oil. One thing is certain. The market will adjust and will continue to be volatile. One benefit on the product side, we will continue to see crude prices remain at the current levels, and will be the increased margins for our lower valued products. These prices are generally not as elastic or linked to the crude market.

Overall, we had a very good third quarter and we were able to benefit from a strong operations performance. Of particular note, through three-quarters in 2014 our East Coast system has contributed over 50% of the approximately $850 million in refining EBITDA. It may be too early to declare victory, but this is a positive trend, and our East Coast has certainly established itself as a meaningful contributor to the earnings of the Company.

Before concluding my remarks, I wanted to add some detail to the hydrocracker project that we chose to write off in Delaware. The project was first conceived as a solution to meet the 15 part per million sulfur requirement for heating oil on the East Coast and it also would have provided a number of other additional benefits along with meeting these requirements. While we continued to review this project, we were also looking for other alternatives.

A hydrocracker is a large and expensive unit, notionally a $1 billion or more, including the ancillary projects, and would face significant permitting issues in the state of Delaware. Finally the return would be achieved over a few years in a very volatile market, we pressed our engineers and planners to come up with the solutions that would meet the sulfur standards, be lower costs, and have a higher return.

By looking at our two East Coast refineries as a system, as a single refinery, the solution they came up with was to reconfigure existing flows and processees which cost us about $50 million and allows us to make 100% ultra low sulfur distillate on the East Coast. Just as importantly, we were able to redeploy the remaining capital to other uses, including the return projects we are executing at Toledo and the repurchase of our shares. We are actively identifying and pursuing opportunities to grow our Business through sensible acquisitions in order to create additional value for our shareholders.

I would now like to turn the call over to our Executive Chairman, Tom O'Malley.

Tom, thank you very much.

I've commented in the past that I wasn't happy with the Company's performance in some of the previous quarters. Today, I can say, great job to our organization. We built up this company over the past four years from zero refineries and very few employees to what is today a fully functioning, independent refiner with an excellent balance sheet, probably the best management team I've worked with in my career, and what I view as a very bright future.

I'm particularly happy to take that $28 million charge that Tom and Erik mentioned and avoid an investment up in the billion dollar area. I can tell you that when the question came up, I was struck by the fact that our industry always seems to have projects with a 30% return when they are planning them, but they seldom, if ever, come true, and the long term rate of return in the refining industry certainly is marginal.

Instead of taking the typical industry route of the giant investment, Tom and his team solved the problem with smart engineering, a modest investment, and innovative plant realignment. I'm also happy with what's happening out in Toledo in terms of investment. We are putting an extra $50 million or so into the plant during the turnaround.

This is, of course, over and above the turnaround expense. The $75 million return that Tom mentioned is the type of resilient return that we will see right away. So, we're certainly hitting on all cylinders in that regard. Erik mentioned during his discussion that we spent $100 million buying back shares. I think the average price was marginally below $24.00 a share.

We certainly want to continue that activity. It's a way to return money to our shareholders. That final piece of the drop downs is certainly important to us. We promised our investors in PBF and the investors in PBF X that we would pursue that route and indeed we are trying not to let any grass grow under our feet.

So the quarter in general was excellent. The Company is operating extremely well and hopefully the share price will reflect that the at some point in the future.

On that note, we'd be pleased to take any questions you may have.

(Operator Instructions).

We can take the first question from Paul Cheng with Barclays. Please go ahead. Your line is open.

Hi. Good morning.

Good morning.

Tom, this is for Tom O'Malley, I think. I think over the last year or so that you have been spearheading the industry discussion with DC related to the export ban debate. Wondering that, is there any update with all the noise that we're seeing, is there any update that you can share with us?

I certainly can share with you that I talk to a fairly significant number of people in both the Senate and the House and I have yet to identify really anybody outside of the energy states who is in favor of lifting the export ban. I think the Obama Administration was, in fact, caught short with the Commerce Department licensing game. I don't thinking they knew about it and I think the licenses are going a bit slower these days.

I am struck by the idiocy of the argument that lifting the export ban would result in lower oil product prices in the United States. We had a philosopher in the United States long ago, Thomas Payne, and one of his remarks was, common sense is the most uncommon thing. We lift the export ban, and I think it's fair to say that the price of crude oil for almost every refinery in the United States will go up by three or four dollars a barrel.

Given the fact that while the industry has been profitable over the past couple of years, that profitability is certainly not massive. Those costs will be passed on to the consumer and the consumer will find themselves paying an extra $0.08, $0.10, $0.12 for gasoline, paying more for their heating oil, trucking companies pay more for diesel. In essence, thank you very much, this will be an enormous transfer of wealth from the American consumer to the US production companies.

I don't think you are going to find an awful lot of people in Congress who are going to want that, and I don't think that the Obama administration would put itself in a position where it would be in favor of that. You certainly tend to speak out on the subject and just the -- you know, the whole idea that it's going to result in lower prices, you know, everybody on the phone ought to think about that because it ain't going to happen. It's going to be higher prices.

Thank you, Tom. Tom, since I got you then, PBF has been active in looking at the M&A market. Can you describe -- I know you have been to date just a bit off in the M&A market remain too wide?

I don't think the bid ask is too wide. I think we are in a period of time when there is uncertainty in the marketplace relative to this export question. When there is uncertainty in the marketplace relative to the absolutely horrendous idiotic and stupid handling of the rims issue. I mean, we really can't predict what the government is doing. If it was in private industry, everybody would be fired who was handling this thing.

I think you're in a period of time when establishing the correct value for an asset is perhaps a little bit more difficult than it previously was. The remark, I can make to you, though, as a refiner, I suppose, perhaps as the individual who has bought and sold more refineries than anyone else, overpaying is something you never recover from. So while we are active in this market, and while we're always interested in expanding, right now the cheapest refining assets that I have been able to find are located within the books of our Company. So, frankly, I'd rather put the money buying back shares at this moment in time.

Excellent. Thank you.

Maybe I could have a quick question. Starting with Tom Nimbley, in the past you were very nice to give us some estimate what is the crude purchase cost in the current quarter comparing to the last quarter look like both in the East Coast and the mid-CON. Can you provide that information also?

Yes. We can give you certainly some color on it, Paul. Obviously, the third quarter, the crude cost versus the benchmarks, they are almost -- they're not as important as they were, frankly, because we were unhedged in a very significant decrease in flat price in crude. We bought our crude a little bit early. So our margins or our differentials were narrowed.

That was, of course, more than offset by the fact that the lower flat prices were benefited because of the coal products and other things that I referenced. In the current quarter you must realize, and we mentioned before, one of the things that our commercial team does, and does very well in my opinion, is -- and Erik mentioned it, when we buy WTI-based crude, whether it be something out of the Bakken or WCS, we look for the opportunity to put on hedges when we see what with believe are attractive raw material prices.

Nobody knows what was going to happen to the crack for sure. But if we believe they are attractive, we put those differentials on. We do so. We did that earlier this year for the fourth quarter.

In fact, a good percentage of our crude for the fourth quarter has hedges against it. And without giving you the exact numbers or what we believe the numbers will be, we are pleased with the sourcing of those crudes into our East Coast system.

Maybe this is for -- maybe this is for Erik. Erik, I think you indicated in the third quarter we got benefit from the inventory sales. Can you quantify that?

During the quarter, Paul, we probably received north of $40 million worth of incremental profitability as a result of drawing down inventory and selling in a robust market.

Okay. And do you plan or seeing that you are drawing down your inventory in the fourth quarter also?

I think you're going to see a build in inventory in Toledo, simply because Toledo is in the midst of a turnaround and will be ramping back up towards the end of the fourth quarter. And then as we do every year, we managed our inventory across the year.

So we don't -- you will see some inventory start to come down. There was an inventory build in the third quarter. That was part of the working capital of about roughly $100 million of cash, and I think going forward you will see us get back to where we normally are in terms of inventory every year.

Two short questions. One, do you have the number of the mark of your annual inventory in excess of the book, and second what is your working capital?

Paul, this is Tom. We do have to let some other people ask some questions. So let's make that your last one. Erik, if you could address that?

Paul, I don't have the inventory number in excessive of book. We will circle back with you on that one. In terms of working capital for -- in this particular quarter, I think, our working capital at this point is in relatively good shape and we had approximately $100 million of essentially working capital cash go out the door and it's primarily related to inventory.

Thank you.

And we can take our next question from Paul Sankey with Wolf Research. Please go ahead.

Good morning, everyone. Tom, on your argument against crude exports, wouldn't that imply you impose gasoline and distillate exports?

No, it does not imply that I impose gasoline and distillate imports. Historically, go back to 1975, January 14 or 19, can't remember the exact date when the United States put in place an export ban on crude oil. That followed the Arab and Israeli war in 1973 and shortages that resulted in really disruption within our system in the United States.

The opening line of that particular piece of legislation said that we wanted to establish energy security in the United States. That at the time our crude oil production was almost exactly what it is today. Very close to 9 million barrels a day.

The difference today is that our product consumption in the United States is higher. So it would seem to fly in the face of reality to export crude oil. Also, in the energy and security act of the year 2007 we had the same type of wording in the opening paragraph. Built into every one of those trade agreements since the time we negotiated is that particular law on crude oil exports. We have been always been an exporter of oil products. That's a constant business.

It has grown over the past years, certainly, but we have been moving products into Mexico for probably 25 years in the Caribbean, a longer period of time. We will continue to be an oil product importer in the United States, primarily on the US East Coast, some from Canada, the majority of the present time from Europe. Why from the US workers' point of view, particularly the United Steel workers who represent most of the refining workers in the United States, would they want to export those jobs?

Why can't we refine the oil here? We have the most sophisticated refining system in the world. We don't have a shortage of refining capacity here. We have enough capacity to meet the needs of the United States for products and at the same time export.

So, no, I don't think it does. Of course, I'm talking in the interest of the only heavy industrial sector in the United States that can provide for all the needs of the United States. Our policy in the past has resulted in us exporting jobs. I hope it doesn't change so that we export those jobs and, indeed, that's what's going to happen.

Great. That's interesting perspective, thank you. I have two questions and I will ask them both quickly because I suspect the answers may be fairly long. First, anything, Tom, you would add on the Jones Act and whether or not something can be done about that? And thirdly, there seem to be several stories about rail disruptions throughout the past several months in fact. Could you just update us on that --

Sure. Yes. Sure.

With regard to the Jones Act, of course that lore has been in place for a long time. If you had crude oil exports you would have to eliminate the Jones Act as otherwise your East Coast refining system would be put in such an enormous competitive disadvantage. You can move crude from the Gulf Coast area to Europe probably from marginally under $2.00 a barrel and then you can move the products back to it the US East Coast for marginally over $2.00 a barrel.

On the other hand, if you wanted the Jones Act tank it today to move crude oil up to the US East Coast you would have $6.00 to $7.00 a barrel. I personally don't think the Jones Act is going to be repealed. That's one of those things -- and your second question was about the rail?

Yes, rail construction.

I don't think -- I'd like to rephrase that. I think the railroads are starting to operate better. I think at the start of the crude movement on large-scale, they perhaps didn't have in place the -- all the safety procedures that they needed to have in place. And we certainly had some horrendous accidents as a result of that.

We're seeing far fewer serious incidents, even though we have much greater movement of crude oil. Some of the disruption that you're seeing involves redoing infrastructure, particularly in the Chicago area, which is slowing things down on a temporary basis. I think longer term, frankly, it's going to result in a little better operation. At least that's what the railroads hope for.

There is another issue, which I believe everybody should note, that BNSF, who is the principal supplier of rail transport out of the Bakken, has put $1,000 per trip surcharge on old railcars, the old 111s. That is the equivalent of $1.40 a barrel. I'm pleased to say that this does not have any impact on PBF as it's been our policy that we won't accept old railcars into our rail system in our refineries since, really, the end of June of this year. And the Company has sufficient new railcars at 1232s to provide for all of our prospective requirements. That's not true of all of our competitors.

Thank you. I should move on, but I can't resist asking you, do you think Saudi and OPEC cut in November? I promise I'll leave it there. Thanks.

Look, I have been watching OPEC since the early 1970s and the long-term history of OPEC is that it takes a little bit of time usually for them to act. But historically they have acted. One of the reasons that we don't view the export of crude oil as an export into a free market is that it's never been a free market. It's the only giant commodity controlled by a cartel.

The cartel has acted in the past. I don't know that they will act in November. But, again, if you look at history, it usually takes them somewhere between three and six months, and then something is done. And I believe they will have to cut.

Thanks a lot.

And we can take the next question from Ed Westlake with Credit Suisse. Please go ahead.

Good morning and congratulations on the numbers its seems a lot of it is down to the operations of the refineries. So congratulations.

Just a quick question on term contracts in rail. I'm sure you've seen the announcements from enterprise on this Bakken pipeline starting up in a few years of 450,000 barrels day and, obviously, Bakken operators on the upstream side are confused about where they can take production.

But you've also got crude by rail projects that potentially may get sanctioned on the West Coast, we sets up a little bit of competition for the barrels. I am wondering, particularly for the Bakken, you have seen any of the producers willing to sign term contracts with you and some color on that dynamic? Thank you.

We don't really sign up long-term contracts for crude oil in the Bakken. We have framed arrangements to some degree. Certainly I think if I was a producer out there I'd be always trying to achieve the best price. But my view of the rail out of the Bakken is that it's really a long-term operation.

Certainly we are going to have additional pipeline transportation. Indeed, we are going to have additional Bakken production. We are going to have additional production on a grand scale, I believe, out of the Permian Basin, out of eagle Ford, and indeed a few other fields.

It's a very expensive move by pipeline down to the Gulf Coast. When you add it all up, I think you're going to be looking somewhere in the neighborhood of $8.00 to get down there. You are going have to have pipeline fill that you are going to be working with. On top of that, the timing elements associated with shipping to the Gulf Coast will stretch out the working capital line.

As long as we can keep the rail movement efficient, and that means certainly reasonable fast, two, two and a half turns a month per car, and keep the cost of that movement down in the $11.00 category, I think rail is going to be a long-term proposition to the US East Coast. With regard to the West Coast, there is oil moving out there today. I think more oil will move out, but I don't think we are looking at massive quantities.

It will put some pressure on the crude oil market out on the West Coast and certainly the production that exists out there will have to be competitive. But, yes, sure. Look, we're going to see a lot more production and we will see some more demand for it. But that's our business. It's a very competitive business and we're happy with it.

By the way, I appreciate your remark on your being, I believe, the only refinery engineer. Your comment that it really came from great refinery operations, the good results and to a great degree that's correct. The guys really have the system lined out and the East Coast, which many people had given up hope on, that's going to be a great place. We have got great refineries and real good long-term assets.

No. You have certainly done a good job on the last few years. On the rail topic the D.O.T. is looking at new rules and speed, as you just mentioned, is one of the areas that makes rail efficient. So what sort of mileage per hour limit or what constraints would concern you in that DOT review?

Well, I think today when we look at that rail movement out of the Bakken, it looks like it's a bit over 20 miles an hour. Probably the average into our refinery is up in the 23-mile-an-hour range. We are not going to have a problem with any of that. The speed issue really is an issue in specific areas. And I'd rather see them, you know, drop it down to 20 miles an hour, go slower through the difficult areas.

We're fine with that. The railroads have really stepped up to the plate. They are really starting to do a good job on this. And they understand that there cannot be the type of accident that we saw up in Canada. That just can't happen. And I think the railroads get that. They are spending the money that they need to spend now.

We need to have these new cars. The BNSF's action with regard to the 111s was in my view long overdue. This would be like having your airliner equipped with 35-year-old aircraft. That wouldn't be a particular good airline to climb onto and fly around on. I think a lot of these cars are just -- you know, they are not suitable for the service. And we need new modern cars with the added safety procedures.

A mall one, final one for me. You have obviously flagged the secondary product benefits which are not in the cracks. But in LPGs, asphalts. We can track those prices. Asphalts are a little bit more opaque. You mentioned that $12 a barrel improvement. Do you think there will be a give back of that at the time and how long do you think that type of give back will take, because they tend to be a bit more sticky?

They tend to be a bit more sticky. But let's be realistic. This is a very competitive industry. We negotiate prices every day. And whenever anything gets particularly attractive the industry produces a bit more of it and the differential goes down.

But I think what you should note, and for me it was really interesting yesterday to see the statistics. The draw on middle distillate, I believe it was up in the 5 million-barrel range, and the draw on gasoline at this time of year, I believe it was 1.8 to 1.9 million barrels, extraordinarily bullish factors for the crack. Really the industry inventory levels are in good shape. The industry is operating well. We have become a powerhouse here in the United States.

The arb for gasoline from Europe was completely closed any number of times. And, yes, we have become an exporter. And that exporter is creating really valuable economic activity here in the United States.

The market probably looks better at this moment in time than I have seen it in the last four or five years. You know, absent a period of time when we have hurricane disruption. And we have had none of that, and yet, we are in pretty good shape.

Thanks, Tom.

Before we proceed, we ask that you please limit your questions to one at a time as we have several questioners. This is in the interest of time. Thank you very much. We can go next to Evan Calio with Morgan Stanley. Please go ahead.

Good morning.

Morning.

Tom, maybe a different take on M&A question. I know you have largely discussed refining acquisitions and your MLP can potentially augment or facilitate that strategy. How do you view M&A potential opportunity in the midstream sector outright?

Oh, that's something we have a team focused on right now. If you ask me what I'm spending me time on other over the next six months, there will be a disproportionate amount of time spent there, really for two reasons. Of course, the idea that PBF could benefit from better midstream infrastructure to service our needs, particularly on the East Coast, but also in Toledo.

And then, obviously, from the PBFX point of view, identifying and bringing in some third-party revenue streams will, I believe, enhance the value of those shares. And since I think I'm probably the -- I own four or five percent of the outstanding shares of that particular entity, I'm really quite interested in seeing that entity prosper. So I think third-party activity in the midstream is very, very important for PBFX and it's something we are really focused on.

I guess, given your time allocation, is that a statement that that's where you see better relative opportunity today, or is it barrel level pathing between the two -- ?

It's two things. Normally, Tom runs PBF and he kicks me out of the building every now and then. And, secondly, yes, we see good opportunities. You know, since Tom won't let me work all the time with PBF, I'm forced to go to work for PBFX.

So a combination. Really, I think, from the investment point of view, PBF has matured into a really sharp, albeit, a bit smaller than we might like, independent refiner. And we got a terrific management team and they don't need me standing around all day long telling them what to do.

So maybe one last one if I could here. It was good to see the drop down last month and the majority evaluating a second drop. But can you -- how much remaining MLP will EBITDA currently exist and can you quantify the EBITDA associated with the transaction that you mentioned was under, I guess, conflicts review?

Erik, why don't you answer that question?

Sure. Evan, we have about a hundred million dollars worth of dropdown EBITDA we think resides at the parent company. Unfortunately, we can't comment on size of the next drop at this point.

Fair enough. I appreciate it. Thank you.

And we can take the next question from Doug Leggate with Bank of America Merrill Lynch. Please go ahead. Mr. Leggett, your line is open. You might want to check the mute function on your phone.

Why don't you go to another question?

We can take Roger Reid with Wells Fargo. Please go ahead.

Hi. Good morning.

Good morning.

I'd like to kind of talk a little bit about some of the -- given the performance on the East Coast, which was, obviously, very impressive all things considered, rail economics look a little more challenged here with differentials where they are relative, I think, to where a lot of us expected them to be. Certainly where they have been in the last several quarters. Can you help us to understand how the Bakken or WCS, or maybe it is bitumen instead of WCS crude, remains a competitive crude or competitive crudes two-run to the East Coast given the rail costs?

Tom, why don't you take that question?

I'd be happy to. As I mentioned, when we look at the current quarter, the fourth quarter, because of the way we hedge our position on those big Continental, Canadian crudes, the current market does not reflect what our actual landing costs of those crudes will be, and they remain very viable and attractive crudes for us in the fourth quarter. Now, to your point, as we move into the first quarter, certainly WCS at today's price with the transport costs would not be an economic crude into the East Coast. We believe that those prices are influenced by line fill.

You cannot move WCS to the Gulf Coast of the United States and make money on it at the prices today. So, frankly, it's a crude that's added money to most of the sector with the expectation of the Midwest. So we'll see that what happens. But I want to make -- and the Bakken, it's not quite the same because when you look at clear book pricing, as we alluded to, we go back further upstream, if you will, and we're able to get [Sorsum] crude prices that are better than that. We continue to have Bakken attractive today, and even in today's price it would be an attractive crude railed in for us.

I want to make another point though. And it's very key. Right now if you look at today's current market, as I said, WCS is not going to be an attractive crude if we have to land it in at today's price differential plus transportation. However, Mayar an is an attractive crude. M100 is an attractive crude at today's price. Ismiss is an attractive crude at today's price.

If the Bakken becomes a type, we substitute frankly in Delaware and even in Paulsborough, because of our sour crude capability and our salter handling capability. Those crudes with these water born crudes, water born sours, today would be economic and we would be making money on it. Again, that differentiation is there for PBF East Coast system that doesn't exist for the rest of pad one because, candidly, trainer PES and even Bay Ray are dependent upon 100% dependent upon light sweet crude.

Is Eagleford, Bakken, something gets out of the market, their alternative becomes West African barrels, which is not necessarily -- clearly not as good an option as we have.

Okay. Thank you.

And it's still early days in the Utica, but definitely a decent amount of condensate production coming out there, maybe we will see something heavier available eventually.

Have you done anything about trying to run any of the production out of there as a test in Toledo or potentially on the East Coast, given drilling plans out there we should see continued growth if Utica production?

On the East Coast should the production come, you know, we will just move that over to the -- we can move that to the East Coast. I want to make one point on that that is fairly interesting. But at Toledo we are actually running about 2,000 barrels a day of condensate. As you say, condensate is being produced. It's actually some percentage of the condensate production. We certainly have the capability of running more if the production comes up.

And I just want to make a point that we haven't made before. It goes back to this whole ability to run light crudes in North America and handle the share revolution. And it even gets to condensate. It's fairly interesting to me that for running WCS crude everybody knows that WCS is a blended crude and it has 30% condensate or gasoline in it in order to be able to pump it in a pipeline.

Think if you will if you replace that with bitumen in some manner, and did not have that 30% gasoline get to a crude unit in the Gulf Coast or the East Coast. You have an immediate to bottle neck of the light crude handling capability throughout the entire system. So I wanted to make ma point because people talk about particular lit producers say the refining industry is not going to be able to process this crude. I personally believe we are resilient, and sometimes so resilient we kill a good golden goose. But there are ways for us to increase the processing capability of light shale beyond what we're doing today.

All right. Thanks. I'll adhere to the two question rule here. Thank you.

We can take our next question from Mohit Bhardwaj with CitiGroup.

Thanks for taking my question. Just a quick one on Toledo. There are two numbers I think I'm getting a little confused with. You have mentioned the past total process improvement EBITDA of $60 million and then you have highlighted today that's external spending. It's going to be 75 and probably more to come with the chemicals expansion. If you could just elaborate on that, that would be great.

Yes, sure. Actually, the $75 million on a full burn rate, which we would get, includes the chemical's expansion. And to go back to what we said earlier, and part of the reason for the CapEx increase what we just guided today, when we talked about the $60 million before of EBITDA associated with turnaround enhancements, we did not have that chemicals expansion in the horizon. We were going to push it out until after the turnaround. The economics on this are very favorable.

Not only does it have a return. It diversifies Toledo's slate further into chemicals away from light clean products and, frankly, it benefits PBF on Tier 3 gasoline compliance. So we made a shift here between the time we gave you the $60 million and agreed and decided to in fact go ahead and spend money to put tie-ins during this downtime that allow us to accelerate the startup of that project. As I said, that will come on stream mid July. That's the increment that takes us notionally from $60 million to $65 million.

Thank you for that. Tom, if I could just ask you about -- this is the first time I don't know if you have seen it before, but this is probably the first time you have seen an Atlantic Basin is actually net positive, as far as crude supply is concerned. And you are seeing there are people that are looking at refineries like Hovensa and we are not seeing any European shutdowns this year.

How do you think Atlanta basin develops? The margins have been strong in the past quarter, but you know if [something] aren't there, how do you see the glut of crude oil in the basin? And the refining capacities actually coming back, how do you see it progressing from here?

I don't think there is a glut of crude oil. I think crude oil is in modest surplus at the present time. If we have a severe winter, you might see a pickup in crude oil prices. That winter is actually the time of greatest consumption. Not the summer. With regard to European refineries, there are a number of them that simply aren't competitive.

I mean, there is no question that our side of the Atlantic Basin has become much more competitive. I suspect slowly you'll see some refineries taken out of service or their throughput reduced. Just a slow walk. Things in Europe, in terms of closing anything down, don't happen that fast.

Again, very competitive industry. But, I think what really we should focus on is the fact the arb from Europe has been closed more often than I've seen it in the past. In essence, the Europeans cannot produce at a price level that allows them to provide competitive oil product delivery to the United States.

And, in fact, we have the opposite happening. We're moving product over to Europe. We have certainly captured a good part of their previous export market to West Africa. We are -- you know, we're really increasing our market share. The crude, well, you know, crude moves around the world.

You get -- for heaven's sake, you get crude from the North Sea moving as far as China. So, you know, I don't see a glut on the crude oil side. I think there is marginally more than we need today. You're looking at a marketplace that's, you know, if the mid 90 million barrels a day. Is there an extra 500,000 or a million barrels a day today out there on the marketplace?

Probably. But look that as a percentage of the total. It's really not that great.

Right. Thanks for those comments. And one final one for Erik. Erik, if you could just quantify the realized versus unrealized in that $49 million hedging.

There was $33.5 million of unrealized gain and we pulled forward roughly $16 million of hedged gain that is realized in that 49 that would have been recognized in Q4. We elected it to take it in Q3.

Thank you. Thank you for taking my questions.

And we will take our final question from Blake Fernandez with Howard Weil. Please go ahead.

Thanks. I'll be brief. Just two questions for you. For one, just an indication on 2015 CapEx, if you could? I assuming that would be a rollover given the absence of the Toledo turnaround. But just looking for any direction at color you could provide there.

Secondly, going back to Roger's question as to relates to the crude differentials and what not. If I am looking at your guidance on rail volumes for 4Q it's very similar to 3Q, and obviously the differential has been compressed. I am just wondering is this base level of rail despite the differential environment? Any flexibility that we can get on volumes for rail depending on the movements and differential environment?

Tom, you don't take the investment question. I will comment on the rail.

No, on the rail side, actually, our economics on it, we establish economics particularly on Canadian crudes three to four months in advance. So our purchases of WCS and related crudes from Canada were made some months ago. And if we bought them based on a WTI diff, which we do sometimes, we would have put on a spread against brent at that time.

The spreads, of course, were more generous in that period of time. We were aware of the line fill requirement. WCS has tightened up because you are putting millions of barrels into new pipelines. That activity probably ends in December, and frankly we see a more generous differential a bit down the road. In that case, that's our expectation. So, no, it's not -- I mean, we could run it up at a much higher level or we could run it at a much lower level.

And that's the flexibility that Tom Nimbley described to you. We -- you know, depending on what the best crude is, that's the crude we're going to buy. Tom, why don't you take the investment question?

Yes. We are working through our 2015 budget as we speak so we haven't landed on the actual CapEx. I will make a couple of comments. 2015 will be a lower turnaround year than 2014 simply as you alluded to. Toledo refineries undergoing a refinery wide turnaround and we have a relatively light turnaround load in 2015.

There will be actually less turnaround expenditures as we go into 2015. The standard maintenance, if you will, sustaining CapEx on these refineries somewhere in the area of $70 million a refinery. And then the other thing that we have to factor in is, one, we will be spending likely some money next year as we go for Tier 3 compliance. We will tell you that we believe the bill for Tier 3 will be less than $100 million systemwide and we're pushing our people pretty hard to do the same thing we did with the ultra low sulfur diesel or 15 part per million heating oil to further get that number one down.

There is one project we are looking at. We took the writedown on the hydrocracker. However, we do believe a smaller investment which we might do with a third party to get additional hydrogen into the East Coast system into Delaware will be a favorable project. We had not made a decision on that and when we do we will let you know.

Appreciate the color. Thank you.

And, gentlemen, we do have one last question from Doug Leggate with Bank of America. Please go ahead.

Thanks, everybody. I think my *1 didn't seem to be working earlier. I apologize.

Tom, I wonder if you could address the potential restart of the Hovensa refinery in the US Virgin Islands. Obviously, that was a big supply in the East Coast when it was running and it looked like it was getting resurrected here. I wonder if you could give your thoughts on that, and I have got a follow-up, please.

Look. Hovensa shut down almost two years ago. That was the Hess Venezuelan partnership. We talked to the people involved in that any numbers of times and frankly we couldn't figure out how to make to a viable entity. Hovensa was a sour crude refinery with a very big cat cracker. Everybody looks at every project.

One of the problems down there was really no natural gas supply. Power is extremely expensive. Reliability in St. Croix was sometimes called into question. You know, I don't think it's going to imbalance the marketplace would be my comment if it does start up.

Our experience with refineries that have been shut down, and we restarted Delaware and it had only be down, oh, probably 45 or 60 days when we restarted, when we started the work on it, was that it takes a long time and requires a great deal of money. I wish the people luck who were beginning in the process. But I don't think it's going to be any instantaneous process.

Okay. I appreciate that. Tom, my follow-up, just a real quick one, is in the same vain. There is also some speculation that Citgo has taken its refinery potential deal off the table. I am just wondering how do you see the acquisition landscape, given that you are clearly primed and, obviously, you have been quite vocal about that? I am curious how you see the landscape from here?

Oh, I still say, you know, nothing has changed in these marketplaces. They always seem to be refineries for sale. And it is the battle between the seller and the buyer as to the price. I don't know what's going to happen with Citgo. I read the same press reports that you do. I take the Venezuelans at their word.

I suppose if they get the right price, they'd sell it. But, you know, there is a country that has been elected leadership, and the leadership makes the decision at the end of the day and we really can't front run that decision.

But I will repeat the comment that I made at the present moment, while I'm not quite sure what my share price has done, but certainly I viewed the purchase of somewhat more than 4% of our Company in a, I don't know, a 30-daytime frame, which would come up to about 20,000 barrels a day as one of the real great purchases of all time. So, we'll continue to do that if we don't find the right opportunities.

You're having a good day today, Tony. Glad to know. Thanks very much for taking my questions. Thank you.

And as we have no further questions, I will turn the floor back over to Tom O'Malley for any additional or closing remarks.

My only closing remarks is thank you for attending the call and we look forward to giving you a good reports in the future. Thank you.

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