PBF Energy Inc (PBF) 2014 Q1 法說會逐字稿

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

(Operator Instructions)

It is now my pleasure to turn the floor over to Mr. Erik Young, Chief Financial Officer. You may begin, sir.

Thank you. Good morning, everyone, and welcome to our first-quarter earnings call. With me today are Tom O'Malley, our Executive Chairman; and Tom Nimbley, our CEO.

If you would like a copy of today's press release, you may find one on our website, www.pbfenergy.com. Attached to the earnings release are tables that provide supplemental, financial and operating information on our business.

Before we get started I would like to direct your attention to the forward-looking statement disclaimer contained in today's press release. In summary, it outlines that statements contained in the press release and on this call that express the Company's or Management's expectations or predictions of the future are forward-looking statements intended to be covered by the Safe Harbor Provisions under Federal Securities Laws. There are many factors that could cause actual results to differ from our expectations, including those we described in our filings with the SEC.

As also noted in our press release, we will be using several non-GAAP measures while describing PBF's operating performance and financial results, as we believe those measures provide useful information about our operating performance and financial results. But they are non-GAAP measures and should be taken as such. It is important to note that we will emphasize adjusted pro forma earnings information.

Our GAAP net income or GAAP EPS figures reflect only the percentage interest in PBF Energy Company LLC owned by PBF Energy Inc, which averaged approximately 55% during the first quarter and was 71.9% at quarter end. We think adjusted pro forma net income and adjusted pro forma EPS are more meaningful to you because they present 100% of the operations of PBF Energy Company LLC on an after-tax basis.

With that I'll move on to discussing our first-quarter 2014 results. Today we reported first-quarter operating income of $260.2 million and adjusted pro forma net income for the first quarter of $140.7 million, or $1.44 per share on a fully exchanged fully diluted basis.

This compares to operating income of $100.1 million and adjusted pro forma net income of $46.7 million, or $0.48 per share for the first quarter of last year. EBITDA for the first quarter was $291.4 million.

In the fourth quarter of last year, we benefited from widening crude differentials, and due to the lag involved, we continued to capture this benefit during the first quarter of 2014. Spot prices we see in the market are typically not realized at the refinery for 4 to 8 weeks, depending on the refinery, the crude point of origin, modes of transportation and other commercial factors.

We had approximately $30 million of RIN expenses in the first quarter, which is higher than planned as the market price of RINs has remained elevated in the face of uncertainty caused by the continued delays in the EPA's yet to be determined rule making for 2014.

For the first quarter of 2014, G&A expenses were $36.6 million, compared to $30.1 million during last year's first quarter. The increase in G&A expenses primarily relates to higher employee compensation expense mainly related to increases in headcount, incentive compensation and severance costs.

D&A expense for the first quarter was $33.2 million, as compared to $26.5 million for the year-ago period. First quarter 2014 interest expense was $25.3 million, compared to $21.6 million last year. PBF Energy's pro forma effective tax rate for the first quarter was 39.6%, and going forward for modeling purposes, you should assume a normalized effective tax rate of approximately 40%.

Cash from operations for the first quarter was approximately $260.6 million, which primarily reflects earnings and normal working capital activity. During the quarter, we spent $52.7 million on CapEx, net of $37.8 million in proceeds from the sale of railcars, and $29.7 million on dividends and distributions. For 2014, we expect CapEx, net of railcars, to be approximately $275 million.

We have completed one of our two turnarounds scheduled for this year, and we still have a plant-wide turnaround at our Toledo refinery that is currently scheduled for the fourth quarter of this year. That turnaround is expected to last 40 days.

At the end of March, cash was approximately $240 million. Our net debt to cap ratio was 22%, down from 28% at year end, and we had over $950 million in available liquidity.

Our Board has approved a quarterly dividend of $0.30 per share, payable on May 29 to shareholders of record as of May 12. At this time PBF's dividend policy remains unchanged.

For modeling our full year and second-quarter operations, we expect refinery throughput volumes should fall within the following ranges for the full year. The Mid-continent should average 140,000 to 150,000 barrels per day. And the East Coast should average between 315,000 and 335,000 barrels per day. For the second quarter, the refinery throughput volumes for the Mid-con should average between 150,000 and 160,000 barrels per day. And the East Coast should average between 305,000 and 325,000 barrels per day. On the East Coast, we expect to receive by rail approximately 75,000 to 85,000 barrels per day of light crude oil and 30,000 to 40,000 barrels per day of Canadian heavy during the second quarter.

We expect our operating costs for the year to range between $5 and $5.25 per barrel, which is an increase over previous guidance, based primarily on higher than expected natural gas cost that we experienced in the first quarter. It's important to note that natural gas purchases comprise a significant portion of our variable operating costs, and on annual basis, we consume approximately $37 million MMBtus across all three of our refineries.

In the first quarter, as a result of the harsh weather, we saw some fairly dramatic spikes in the price of natural gas. And while they did not persist, they did increase our operating costs as the Transco Zone 6 non-New York price averaged $14.93 versus the Henry Hub average price of $4.72. Those are all on an MMBtu basis for the quarter.

Before I turn the call over to Tom Nimbley, I'd like to briefly comment on the MLP filing and the secondary offerings we completed during the quarter. As many of you will have noticed, in addition to our earnings release this morning, PBF Energy's subsidiary PBF Logistics LP today announced the launch of its initial public offering for its Limited Partnership units. This process started well over a year ago and represents a great deal of effort from all that are involved in the process.

On today's call we will not be taking questions related to the MLP and I ask that you refer to this morning's PBF Logistics press release and the PBF Logistics filings that are available on the SEC website for additional information.

In January, our private equity investors, Blackstone and First Reserve, successfully sold an additional 15 million shares out of their existing holdings through an underwritten offering by Deutsche Bank Securities. In March, First Reserve sold an additional 15 million shares through an underwritten offering with Citigroup.

After the effect of the sales, Blackstone and First Reserve collectively hold approximately 22 million shares. Following the most recent offerings, over 70% of the fully diluted fully exchanged shares are now listed on the New York Stock Exchange and in the hands of public investors.

With that I'm now going to turn the call over to Tom Nimbley.

Thank you, Erik, and good morning, everybody.

Before discussing the first-quarter results, I want to briefly comment on the Paulsboro refinery operations in the month of January and on its recently completed turnaround. As we mentioned on our year-end earnings call, the Paulsboro refinery experienced a complete loss of steam in January, primarily due to an instrumentation freeze up in the boiler feed water system. Refinery personnel responded appropriately to this unplanned outage and returned the plant to normal operations as quickly as possible under extreme weather conditions.

At the end of the quarter we brought a significant portion of the refinery down for a planned turnaround of its lube block. This work lasted just over three weeks and has been completed in the first part of the second quarter, on time effectively and on budget. I mentioned these two items up front because we had an excellent first quarter that could have been even better, if we had been operating for the entire period.

Regarding our first-quarter financial results, PBF had another strong quarter following a positive quarter at the end of last year. As we have discussed previously, the market was the biggest factor for all of our refineries, and, if we are operating well, we put ourselves in a position to capture what the market has to offer.

Throughput for our overall system was about 431,000 barrels a day. The Mid-continent averaged about 138,000 barrels a day and East Coast system ran approximately 293,000 barrels a day. Throughput was slightly below guidance as a result of the unplanned outage at Paulsboro and other weather-related issues experienced in the quarter.

Operating cost on a system wide basis averaged $6.93 a barrel, which is also above our guidance for the year. As Erik mentioned, operating expenses were adversely impacted by the spike in natural gas prices, which was a result of the extreme cold and some infrastructure issues with natural gas deliveries on the East Coast, as well as lower throughput. For the year, we expect natural gas prices to return to their seasonal longs and our operating expenses to adjust accordingly.

The Mid-continent 4-3-1 crack spread average $16.79 a barrel, an increase over the fourth-quarter average of $10.28. Our margin at Toledo was $19.09 a barrel for the first quarter.

The margin in Toledo is reflected -- reflective of improvements to our landed course of crude in the quarter and the stronger product cracks. Our landed course of crude into Toledo in the first quarter was $1.44 a barrel under WTI.

The primary driver of this cost differential was the improved Syncrude diffs realized during the quarter. On average, Syncrude priced $0.99 a barrel under WTI on an FOB basis.

However, as Erik mentioned previously, it is very important to note that our landed cost 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. We were able to capture some of the benefit of the wider fourth-quarter differentials in the first quarter as a result of this lag effect.

The Brent 2-1-1 East Coast crack averaged $11.41 a barrel, up from the fourth-quarter average of $9.08 per barrel. The refining margin for our East Coast system was $13.71 a barrel. On the East Coast, our landed cost of crude was about $8.23 a barrel under Brent. For the quarter, we delivered 62,000 barrels per day of Bakken crude oil and about 40,000 barrels a day of Canadian heavy crudes to Delaware.

In addition to our rail delivered crudes, we were able to take advantage of favorable pricing for some waterborne barrels that may have come about as a result of the change in crude diets that we are seeing in the Gulf Coast, as those assets take in more North American barrels. Our landed course of crude on the East Coast reflects the optionality we now have as a merchant refiner to pursue the most economic barrels available to our refineries.

We have made significant investments in our East Coast rail assets, which has given us access to increase in volumes of North American crude oils. And our coastal location provides us with continued access to economic waterborne barrels.

As we have said in the past, other than maintaining safe and reliable operations, our ability to procure the most economic crude oils and feedstocks for our refineries is the greatest lever we have as an organization to drive the profitability of PBF Energy. In the second quarter, we expect to bring in about 75,000 to 85,000 barrels a day of light crude oil and approximately 30,000 to 40,000 barrels a day of Canadian heavy crude into Delaware.

We continue to work on expanding the capacity of both our light and heavy rail crude oil unloading facilities and expect this capacity to increase to 130,000 barrels a day of light crude oil unloading capacity, and 80,000 barrels a day for heavy crude oil unloading capacity in the third quarter of this year.

As we increase our rail activities, we are also fully engaged in the industry dialogue regarding increased rail safety measures. We apply the same rigorous safety practices to our rail operations that we do across the refining business.

We have voluntarily, as of April 1 of this year, taken the added safety measure of only accepting unit trains comprised solely of CPC-1232 cars or the new DOT-111 cars for delivery of Bakken crude oil to our Delaware City refinery. Additionally, as of June 30, 100% of the Canadian crude unloading activities at Delaware will be from new style DOT-111A railcars.

We feel that using the safest cars available in our unit trains going to the refinery is an important step to increase the safety of our operations and the responsible thing to do for the communities in which we operate.

For the second quarter of 2014, we expect our landed crude costs, excluding any hedging or LIFO affects, to be about $2 or $3 a barrel over WTI for Toledo 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.

It is unwise to claim victory in the cyclical and volatile industry, but our strong first-quarter results are demonstrative of our efforts to increase the profitability of our Company. Our strategy of sourcing low-cost feedstocks for our system by procuring additional volumes of North American crudes has proven and should continue to prove profitable for our refineries. And our flexibility to take advantage of opportunity when any waterborne crude oils become economically advantageous provides us with the ability to react quickly to favorable market conditions, and, with reliable operations, capture the benefit.

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

Thank you very much, Tom.

Certainly I can only be pleased and I assume our shareholders are pleased with the results for the first quarter of this year. We had a very difficult operating environment with the extreme weather and certainly the Company handled it well.

More than anything else, it's a maturing of our organization and I can truthfully say, at this point, in terms of all the organizations I've worked with over the years, this one has now achieved a level of excellence which should allow us to capture what the market has to offer.

The extraordinary move in the natural gas price in the Northeast area, particularly during the month of January, was something we didn't anticipate, I make the argument we probably should have anticipated it, but we're certainly taking steps to avoid seeing something like this next year.

On that note, we'd be pleased to take whatever questions the audience has. Operator?

(Operator Instructions)

Roger Read, Wells Fargo.

Great first quarter, number one. Number two, as we look at the second quarter you're going to get more light barrels in obviously, but we've seen differentials tighten, can you walk us through what the advantage of railing more light barrels in is or what your flexibility is as you go through the quarter to take advantage of some of the other opportunities? I believe you mentioned in the commentary that may be some of the issues along the Gulf Coast are starting to benefit you on the East Coast, maybe an understanding of that flexibility on the crude coming in.

Well, we will certainly take more light crude during the second quarter by rail than we did during the first quarter of the year. Generally we're buying crude three months in advance. We know now that the number will be up around the 75,000 barrel a day level. Really all you have happening in the marketplace as you have more of this domestic production pushing down to the Gulf Coast, the Gulf Coast refiners are pushing out barrels that they have traditionally handled.

So we're seeing availabilities of medium sour crudes. We can substitute it -- other refineries on the US East Coast cannot substitute a medium sour barrel for a light barrel. So we're trying to stay very flexible and the organization has built itself up to a level where we really can react almost instantaneously to cheaper barrels being available.

We're going to add to that flexibility down the road. We certainly want to have rail facilities at our Toledo refinery, which we don't yet have and something that we need because with the number of unit trains we're moving we can easily divert a train here or there. But just an item of flexibility, having a commercial organization that can react instantaneously and having a refining organization that has become incredibly flexible. The facilities we have on the US East Coast are unmatched by anybody else in this market area.

Okay, thanks. As maybe another way to think about that particular question, if you were to look at the number of different types of crudes that you were running on the East Coast say a year ago and then compare that to Q1. In other words, if you were running 4 different types of crude a year ago and you're running 8 or 10 now, and I know that's just an example of numbers, if can be much different than that. Is that where the change has been? Or --

The answer to that is yes. We will today look at -- during a month we might look at 8 or 10 different crudes and half of them we haven't run on a traditional basis. But we also see crudes coming back to us that in another iteration of this team's various refining activities when most of the team was involved with the Premcor organization and we owned the Delaware City refinery within Premcor, we ran a fairly significant volume of Mexican crude and we're back doing that again today. And that's a new area.

We're seeing other South American crudes that we had never run coming up to us. But really what it comes down to is a plant and equipment that effectively can take anything from a 50 gravity crude to a 12 gravity crude. And it can take anything from no sulphur to 4% sulphur. So it's a terrific flexibility in it and that's going to prove in my view to be a great driver of profitability going forward.

Okay, thanks. And then changing gears a little bit I guess Erik a question for you, as you look at the balance sheet, relatively speaking you have more debt than the peer group. Obviously solid quarter here cash is up and I recognize there's timing issues with cash whether the $237 million is completely available or not, it's another story.

But what do you want to do with the balance sheet with a much stronger obviously first-half 2014 performance here on the cash flow side? Do we look at you paying down debt, you've got the IPO, the MLP coming forward which should raise some funds as well? Walk us through CapEx, share repo, dividend, that sort of approach.

So I think that was multi-faceted question. I think we have -- at this point we have no plans to do anything with the balance sheet other than stay the course. We do have long-term senior secured notes that are in place through the year 2020. And we currently do not have -- or at the end of the quarter we do not have anything outstanding on our revolver. So we feel like we have ample liquidity to operate the business. We're keeping the dividend program the same, and at this point we have no plans to do any type of share repurchase

Let me interject there. Our various companies over the year have had a reputation for growth. We set this Company up a little bit more than three years ago in terms of purchasing refineries and getting them operating. And of course we had our private equity partners over the last 18 months act as sellers of our shares. As mentioned earlier by Erik, we now have about 70% of the shares in public hands trading on the New York Stock Exchange and we are truly a public Company.

We have a very clear focus on wanting to maintain a very strong balance sheet and we want to look like our peers. We want to play in the same league. At the same time, the Company is once again set up to grow and we'll look at every opportunity that's out there. We'll limit at the present time our view of growth to North America, but we want to have all options on the table.

And this Company at 500,000-odd barrels a day certainly can grow. And we've got a good young Management team. And I think they're interested, given their ownership of shares and holding of options, of really improving shareholder value. And to do that we have to operate well but we also have to grow. I hope that adds to the answer.

Yes. Thank you.

Ed Westlake, Credit Suisse.

Good morning and congratulations on demonstrating that you can benefit from what's going on in the domestic crude business in the quarter.

Thank you.

With the conversations you've had, obviously the international prices for Mexican Isthmus medium crude and Mexican Mayan crude they move around all the time and obviously you run that in your LP. The Canadian discounts, they move around all the time. Is there a movement by the producers say of Canadian crude who you're going to be buying from by rail to perhaps link some of their pricing in the East Coast towards wherever your alternatives are plus some kind of profit for the fact that you are a good outlet for that crude and then reflective of the rail cost?

Are we starting to see those term conversations creep up, that's Canada? And then also I'd love any color on how the Mexicans are thinking about the fact that they may lose some customers in the Gulf and therefore you may become a more valuable outlet for their crude as well.

Well I think the answer to that is the crude oil market is a very transparent market and the producers in the marketplace have very smart people operating, keeping track of things. Everybody has an enormous amount of information available to them.

But we have become a very attractive and stable outlet particularly for Canadian heavy crude. We have a fleet of modern railcars. We've proven we can run virtually any quality of Canadian crude and again no one else on the East Coast can. So -- and we are prepared to operate in a commercial manner, in essence if somebody comes to us as they do from time to time and want to sell crude to us on a forward basis, normally we would buy three months forward, but if they came and said six months, nine months or a year, we've got an organization that can handle that easily.

With regard to what the Mexicans are thinking, I must tell you, Ed, I do not opine on what the Mexicans are thinking. But what we're seeing with virtually every type of crude coming to the US Gulf Coast is that the Gulf Coast refineries can back out barrels and take domestic barrels. I think a case in point, and a very interesting one from an overall evaluation, is that we have this very, very heavy refinery located in Delaware. Traditionally this refinery ran a stream of crude oil that probably averaged a gravity of 24. In my previous experience with it I don't think we bought a barrel of crude in there with an API gravity over 30.

Our engineering staff, when looking at the opportunity of running light crudes, was able to create a situation at that refinery where we can run over 100,000 barrels a day of light crude. Extend that now to the Gulf Coast and you've got a lot of smart people down there. And if we could do it, they can do it and therefore there you get them backing out Maya, you get them backing out Isthmus, you get them backing out Arab light, Arab medium, heavier grades from all over. Well where is the oil to go? And who else has capacity to handle some of these oils?

So we're very well placed and it's starting to have an impact on us. I think we've so far in the first quarter frankly seen only a minimal impact of this. I think we're going to see more of this in the future. I think you can say by intelligence or probably just as well by luck we managed to own the two refineries on the East Coast that can process just about anything. And we're starting to benefit for it and I believe we're going to continue to.

Thank you that's clear. And to be clear in terms of some of the conversations you are starting to have people call you up and try and offer longer term contracts and then it's a question of PBF and the seller trying to agree the right value of the option that PBF offers these producers?

Yes, we are and we're interested in working directly with the producers and we're having increasing success. And frankly going back to Roger Read's question about the balance sheet and our financial standing, our goal and objective here is not just to come to improve the profitability. We want that profitability to drive a much better balance sheet and we want to be a Company, and we are a company today, that a producer can come to and say hey, these guys are there, they've got a great balance sheet and I want to deal with them. And we're seeing more and more of that on the national Company level getting open credit from people which we previously had not and this drives us forward and makes us a better Company.

Okay hopefully a very quick one, any self-help we should be aware of at the Toledo turnaround?

Yes, Tom?

Yes, Ed, we've advertised before during this turnaround and extended into next year because we'll actually be putting in tie-ins to execute some of these projects as we move into 2015. But we've got about $80 million of EBITDA that we think is going to be coming forward over to -- from September over the next 12 months into 2015. So over that period of time you would expect to see us generate about $80 million more EBITDA on a self-help basis.

And in essence what we're looking at is a profitability yield of an additional $1.50 a barrel on the throughput there and that's not -- I would call that with very resilient less market dependent certainty coming through. Certainly the availability of significant additional crude oil storage there will drive it and we haven't calculated anything for adding a rail discharge facility at that refinery. And making that calculation probably would be problematic.

But there's no question having the flexibility to take 20,000 or 25,000 barrels a day of rail delivered crude into that refinery will turn out to be a smart thing. And having the additional storage available so that when these pipelines get prorated, which they seem to on a fairly regular basis, will allow us to have a more consistent run level.

Thank you.

Jeff Dietert, Simmons.

We're in the public domain restricted by looking at Bakken prices at Clearbrook, which are not necessarily representative of the field zone prices. But if you look at Clearbrook prices now at $98 versus Brent at $109 it's $11 under. My suspicion is the Bakken field zone is trading maybe more than the normal $2 of transport under ClearBridge. Could you talk a little bit about that and are those Bakken rail economics economic at current spot prices?

They're certainly economic for us at current spot prices. Our last purchases of Bakken crude oil, which I can say were made yesterday, land in the plant at somewhere between $3 and $4 under Brent. Certainly we do see in the field different pricing levels. Many times it reflects the transportation to the terminal at other times, somebody maybe under a bit of pressure. We have very favorable rail economics compared to our competitors on the US East Coast, so that does play into our hands.

And I should point out that on Brent WTI differentials, we are generally well forward of the prompt month so if you looked at June today, I don't what it is this minute, but it would be $8. Well on the crude that we're buying for June, we're certainly not looking at that differential. We're looking two months forward just the way these things price out. So the diffs for us are reasonably good and I don't see a situation in the near term where we will be buying Bakken at any premium to Brent. In fact our rail movements move up and down a bit it's because if we see Bakken getting too pricey, we simply take in imported barrels. Again that tremendous flexibility within the organization.

Secondly on your Canadian heavy barrels, could you talk a little bit of about the quality, are they WCS type barrels, are they bitumen? Is that going to change as we come out of the winter months into the summer months?

Yes, this is Tom Nimbley. Basically you could look at us, we base load a volume of pure bitumen which we're bringing in. That can go from, depending upon the availability, it was a little lower in the first quarter because of the severe weather conditions and slower transit times. But somewhere around 12,000, 15,000 barrels a day of bitumen that has typically been very economic and more economic than even WCS [deal bid]. The balance will be though WCS type grades so as we move up from the say call it 15,000 barrels a day of bitumen on a margin everything else will likely be a Canadian heavy blended crude.

Thanks for your comments.

Doug Leggate, Bank of America Merrill Lynch.

I got a couple quick ones hopefully. I guess the comments around Mexican crude should we now be thinking about heavy Mexican, whether it's Isthmus or Maya or whatever, becoming a more ratable part of your diet given all the commentary before about strategic optionality helping the East Coast?

Yes, I think you should look at Mexican grades becoming a regular part of our diet. Don't confuse Isthmus with Maya. Maya is a real heavy crude. Isthmus is much more like an Arab Light, very easily run in either one of our refineries. I should point out again, we've mentioned this in the past, we don't look at Delaware as Delaware or Paulsboro as Paulsboro, we look at the combination of these two refineries.

And we're constantly -- if a crude is let's say scheduled to come in to be run at Paulsboro and suddenly we see better economics over at Delaware or we have a hiccup at Paulsboro, we shift one to the other and then the opposite is true also. So it's really that system that you look at of more than 300,000 barrels a day with significant coking, cracking, every kind of capacity you can imagine. And really whether it's Maya or Isthmus we can run those crudes in both the refineries.

I would add also when it comes to particularly or specifically Isthmus, in Paulsboro we have as you're well aware a large lube operation which currently we have a number of crudes that are certified for lube production by Exxon who we have a contract with. We are moving to expand the number of crudes that we can run on that lube still and we will include Isthmus to see if we can get that certified as a crude -- lube crude.

I guess what was really behind my question was are you having any issues with transportation cost? I mean obviously you're not -- given that it's Mexico there's no Jones Act issues so should we be thinking -- I've always thought a couple bucks would be order of magnitude for moving crude from -- is that about right or --?

Yes, actually we do have ships on time charter, a couple bucks is the right number. The actual all in freight probably about $1.60, $1.70 but then you have to add some other items to that. So $2 out of the Gulf Coast is a fair estimate.

We do not move on Jones Act barges or tankers domestic crude, there's quite a bit of movement out of Corpus Christi up to the US East Coast. And we have not gotten involved in that given the scale of our rail facilities and the availability of those facilities really ahead of the rest of the market. We've decided that paying $6 or $7 a barrel which is a Jones Act number to move crude up from the Gulf Coast is not in our best interest.

Right, I appreciate the answer. My follow up is really something that doesn't get a whole lot of attention. As you continue to shift your diet in line that you like, I'm assuming more Bakken crude over time, what are the implications for your yield across your system? I'm really thinking more about as you change the slate, do we see a better gasoline lift on your output or is it not really that material? Just to get an idea if that's something we should be watching as you continue to move forward with your rail expansion?

Well obviously, Doug, you're well aware that Bakken being a 40 plus gravity crude oil, lighter crude oil will have a higher neat yield off of the crude units of light products. Everybody sees it in gasoline yield and also jet. But that's basically loaded into our system pretty much because we are running, if we don't have weather problems, we expect to run 80,000 to 90,000 barrels a day of Bakken in Delaware City, but we're not going to run any more than that. So the increment of light crude if it's Bakken will be into our Paulsboro system, again if its economic.

I would also say that all Iight crudes are not alike. We are now running light sour blends from North America. And again to Tom's point that he made a number of times, we're the only refining system in the East Coast that can run these things because of our sour handling capability. That is a lighter crude but it's more -- not as light as the Bakken crudes. I would not expect to see a material shift going forward on the amount of light products we make.

Great, I appreciate the answers, guys. Thank you.

Evan Calio, Morgan Stanley.

A follow up on Tom's earlier comments, Tom O'Malley's earlier comments on growth, any comments on the M&A environment? And you mentioned a broader North American interest, I assume that includes all regions including California. Any comments and I have a follow up, thanks.

Well I wouldn't want to comment on any individual opportunity, but there certainly are opportunities out there and I think everybody knows that a number of people want to reduce their exposure in California. Our team has experience across the refining environment in the United States and particularly in the great state of California. And we know the marketplace out there. We know how to operate refineries out there, we've done it before. And certainly it's an area where we have an interest.

Everything with us is driven by economics and where we look at everything that is in the market. I've been doing this now I suppose for more than 30 years, buying refineries and in some cases selling companies. And there's always the question -- well, are there going to be more refineries available in other areas?

Well I think the trend is very clear that your major integrated companies are in essence exiting a significant part of the refining business in North America and your independent refiners, and when I first started doing this the number of independent refiners I think could be counted on one finger and independents had kind of 15% of the market. Today the independent refining sector controls far more than half of the refining capacity in the United States. And I suspect that is a trend that will continue and there will be opportunities every year to acquire additional assets.

And I think our Company is extremely well placed. We have the balance sheet now, we have the Management team that knows how to do it. And probably more important than anything else, we have the desire to do it. So we'll be there, hopefully we'll see growth in the Company. If we don't see growth in the Company they ought to fire me because that's what I do. And I don't want to be fired, I want to work a little bit longer. So I hope that answers your question, Evan.

Yes, no that is helpful. My follow up is also a follow up on crude flexibility comments. Are you seeing -- are there any other rail opportunities in the East Coast from basins other than the Bakken that you're seeing or you think might emerge? And somewhat related, not necessarily by rail, but any update on sourcing Utica condensate given the increasing level of activity and positive upstream results? Thanks.

Well this is an opinion, okay and of course protected by the Safe Harbor Statement. You've only seen the beginning of the fracking production and the Bakken is one particular field, but there are more fields out there in the Mid-Continent and of course you mentioned Utica. We haven't seen a hell of a lot coming out of Utica but it's there and it will produce.

I think the other issue that most people miss in the whole fracking discussion is the percentage of oil from the field actually recovered with current fracking technology, it's very low. In the mature oil recovery processes you're up and the 25%, 30%, 35% recovery zone. In fracking you're in 5%, 6%, 7%. People involved in that business at the present time are spending a huge amount of money developing technology to increase that recovery ratio and that's going to drive the continued rise in crudes available in North America.

I'm extremely optimistic about what's happening. I mean it's happening in spite of the Government. Can you imagine what would happen if the Government was actually supportive of anything like this? So we have the view that this is a long-term gain that the movement by rail is not something that's going to go away in two or three or four or five years. This is something where you can go into a field where you don't necessarily need pipeline connections, where you can move the oil out relatively speaking in an inexpensive manner when you consider the issues surrounding the cost of giant infrastructure pipelines today. So we have a very positive view. By the way that view extends to the state of California.

Always helpful. Thank you.

Paul Cheng, Barclays.

Tom, back in the Tosco time, you actually moved into retail after you made a number of refining acquisitions. What's your thinking, is retail maybe part of the portfolio in the future or then [permit] change?

I don't think so. My colleagues here could overrule me I suppose, but I think the opportunities on the refining side and in essence infrastructure side relative to MLP assets are more attractive than retail. One learns never to say never. If I look back on Tosco, which is back in prehistoric times, we actually got into retail by accident. We bought the Ferndale refinery from a British Petroleum, Ferndale in the State of Washington and as part and parcel of that, they said you got to take the retail. So we took the retail and we managed to build it up over some period of time.

So if something came along and it had retail attached to it and that was a requirement to do the business, I suppose we'd do it. But I think we'd probably then turn around and sell the retail. I no longer have a desire to sell doughnuts, hotdogs and coffee.

I think you and me are both getting old right, we can go back [another] time.

As I said prehistoric, Paul.

On the -- Tom you talk about a little bit on the contract that you had with the Bakken producer, can you tell us then what's percentage that you actually is based on at the time when you signed the contract based on just the spot differential? Or that you really have some form of a more longer term contract exists that -- and is not necessarily linked to the spot differential but maybe it's more on a rolling smooth out for 6 month or 12 month or that some kind of netback. Can you help us understand [on the opinion] in terms the nature of the contracts?

Sure. We'll very often work with people on a longer term basis and in essence agree to let's say take 10,000 barrels a day from one producer or another and generally we'll set a differential in most cases to WTI for a more limited time period than the frame contract may run. We really go with the producer and if the producer wants a longer term commitment at a fixed differential, we're prepared to do that as we're prepared on the flip side of it to turn it into a Brent-based contract by putting on appropriate Brent WTI swaps in the out months.

So it's really -- there's no fixed formula. In essence our approach to this business is to talk to the producers and see what the producers want to do and we'll accommodate them. If you want it for three months, we'll accommodate you. If you want for 12 months, we can do it. Frankly if you want it for longer, we could do it. It's -- as a buyer we view ourselves as a partner with the producer and we want to offer the producer the best service that's out there.

Effectively what's happened, and those of you who work for investment banks who are on the phone, the banks formerly did a lot of this, but the banks are effectively going out of the commodity trading business. And while there may be people within the banks who were disappointed about this, there are people within our Company who are happy about it because we can certainly offer that service and indeed we really don't need a middleman involved in it nor do we particularly want one. So it is a nice situation for us going forward.

And Tom, can you give us a rough estimate what's the percent of your current crude purchase maybe have some form of a [tie-up] say netback contract, either linked to your delivery cost to and then Brent or something like that?

If you're talking -- just be careful here, a netback contract we would define as linked to product prices, the percentage of our crude product, our crude oil purchases on that netback basis is approximately zero.

Right.

Really what we're buying is either Brent-based crudes or WTI-based crudes. And if we looked at Bakken you would say the majority of our purchases are on a WTI basis where we have to put on the Brent WTI spread. We do that at the time when we fix a differential to WTI. Sometimes we'll lag it a bit. Sometimes we'll lead it a bit depending on our view of the Brent WTI spread, but not by much. We're pretty ratable in the way we handle things.

The -- on an imported basis, far more of our crude has a Brent portion day one coming into us. Up in Canada, most of it is WTI-based. But again the sellers, when we talk to sellers, they should tell us what they want to do and we're equipped to do it.

Thank you.

Paul Sankey, Wolfe Research.

On this issue of growth, why continue to pursue it as you've highlighted getting the overhang of private equity ownership out of the stock? Why for example not start a new vehicle for what you seem to be hinting will be a California venture? It strikes me that given that you're achieving what you've aimed to do in terms of crude discounts and operating better, you're almost adding a new overhang to the stock. Thanks and I've got a follow up, thanks.

Well I don't know about an overhang. I think if you're going to be interested in our share, we've been very, very clear from day one that we want to have some element of growth in our Company. And the element of growth -- and we've been very clear that the business that we're in is a refining business. So I don't want to talk about an overhang of the stock. The overhang is finally going away.

And frankly private equity did a very good job in supporting us. There have been no extraordinary dividends. If anybody reads the newspapers very often, private equity has taken extraordinary dividends out of companies. In our case, our private equity partners have been more than reasonable in working with us. But yes, I think you should look at this as a growth stock and now frankly if you don't want some growth, it's probably the wrong place to be.

And why would we grow, well there's only one reason. Can it be accretive? And accretive is not adding $0.05 or $0.10 a share to the earnings of the Company, accretive is significantly accretive to the share price. And we're blessed in a way, many companies, the independents out there have a very large number of shares outstanding. We have less than 100 million shares outstanding, so if we can figure out some way to add $1 a share in profitability to the Company, we're going to go and do that.

And as for a separate entity, everybody sitting around this table is employed by PBF and we're going to drive it through PBF. We're not doing any separate entities.

Got you, it's clear. One thing that has come up briefly but I guess is the other side of the equation, product markets. Can you talk -- tell about your perspective about for example what seems to be pretty good demand for gasoline in the US right now. The risk I suppose given that you're delivering so well on discounted crudes has historically has as much been a problem of weak product markets in the Northeast. How exposed to risk are you there and how do you see those markets developing? Thanks.

Well I think first of all the -- when you buy one of these refining companies, one always has to be realistic and you have to say you're buying the crack and that's true whether you talk about the PBF Company, Valero or Marathon, Tesoro, whoever you're talking about this is a big issue.

What -- if you study oil product consumption over a long period of time, you always see that it is a function of GNP. And traditionally we used to say that if you had a 1% rise in gross national product you'd see growth of 0.7% in the oil product consumption across the country. And on a global basis, that same formula held true. I think the number has dropped here in the United States, but we do see a growing economy in this country and we've seen more demand across the barrel.

Industrial production is up. A part of that is the oil boom itself. The oil boom has massive implications across this country. It's creating wealth in a very rapid manner and certainly people are doing well, we can see that almost across the spectrum.

Of course the Northeast is a good marketplace for us. And we're much more competitive than the European traditional suppliers to this marketplace. We basically have cheaper crude and it's a big advantage, so we see product imports from traditional suppliers falling. And I see a crack market here that I think is going to stay robust. And of course there'll be ups and downs, there'll be seasonal changes, they'll be things where -- we didn't have a hurricane last year on the Gulf Coast, very unusual environment. So we'll be affected by outside things but basically the environment is good.

Really what are we affected most by? Well the old surpluses that existed on the Gulf Coast which used to be pumped willy-nilly up to the East Coast, they're going to Mexico. The Venezuelans I think are still buying gasoline. So there's such a big export business now in the United States that we are benefiting from the diversion of products from the Gulf Coast. So I see a reasonably strong crack market up here on the East Coast.

Understood. And that if I could follow up, you've been vocal in opposing the export of crude, is it really such a big threat for you guys? Won't you still, if crude was allowed to be exported, wouldn't you still have a transport advantage against the European refiner? And I'll leave it there, thank you

Well answering that quickly, we're not particularly vocal in opposing the export of crude. What we've been vocal about is the level playing field. For heaven sakes, if we're going to take the crude and export it all around the world, please let us export it to the US East Coast. We cannot do that if you can export crude oil to Europe at a cost of $2 a barrel and we have to use a Jones Act ship which cost us $6 or $7 a barrel. So we been opposed to that.

Additionally you all may remember, or you may not remember, that the 2007 Energy and Security Act, which mandated volume metrics on the use of ethanol, was justified because we were trying to get energy security for the United States. Well, if we're going to be exporting crude oil we obviously must have energy security and therefore let's get rid of the mandate. We would still use ethanol and we would use it in substantial manner. But we wouldn't have the Government mandating it.

So we're not opposed to exports per se. We're opposed to a situation where we're not on a level playing field. And would we still have a crude advantage over the Europeans if exports were permitted? I suppose so, but I don't see exports of crude oil taking place anytime in the near future.

Always helpful, always interesting. Thanks, Tom.

Cory Garcia, Raymond James.

Actually all of my questions have been answered. Appreciate it and great quarter.

Thank you.

Clay Rynd, Tudor, Pickering.

You guys had talked about how the quarter was impacted by the high natural gas prices which drove higher OpEx and mentioned taking some steps to avoid dealing with that impact as we move forward. Are you guys willing to hedge forward natural gas prices to lock in a cost?

Well look the guys and ladies and gentlemen that work with me are sometimes annoyed at my directness and willingness to say that we screwed up. We had a basis risk and the basis risk was really the north, south risk. And we should have had that covered is the answer.

And so are we taking steps that would reduce that risk in the future? You bet we are. And was I annoyed at the $36 million extra cost on natural gas? Did you ever see anybody go a bit berserk? Yes, I was annoyed and I felt that -- we can make a mistake, but we make it once.

And so with regard to hedging the natural gas, the gas itself, the commodity risk associated with it, we do that and have done that and we do buy gas on a forward basis. I will say as I look at the marketplace, particularly with the Supreme Court decision on coal-fired power plants and the interstate movement of the resulting CO2, I think we're going to see a greater demand for natural gas. And I actually thinking natural gas at today's pricing levels is probably at the lower end of the spectrum. That's how we try and look at things.

What's the story here? Should we be in there buying some natural gas on a forward basis? And the answer is yes, we should be. And should we be covering our basis risk? Yes, we'll do more than that. But we can never do 100% of these things because you're always counting on perfect operation of your refineries.

So we're always going to be exposed to some degree, but we never should have been exposed to the degree we were and got caught. And I suppose we sat there observing previous winters and said this can -- who predicted this? I guess nobody did, but that doesn't excuse it. So yes, we're going to take steps, have taken steps.

Appreciate it.

This does conclude the question-and-answer session. I'd now like to turn the program back over to Mr. Tom O'Malley for closing remarks

Thanks for attending today's conference call. We look forward to visiting with you in the future. Have a nice day.

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