Erik Young – Senior Vice President and Chief Financial Officer Thomas J. Nimbley – Chief Executive Officer Thomas D. O'Malley – Chairman.

Roger D. Read – Wells Fargo Securities LLC Ed G. Westlake – Credit Suisse Securities LLC Jeff A. Dietert – Simmons & Co. International Doug Leggate – Bank of America Merrill Lynch Evan Calio – Morgan Stanley & Co. LLC Paul Cheng – Barclays Capital, Inc. Paul I. Sankey – Wolfe Research LLC Cory J. Garcia – Raymond James & Associates, Inc.

Clay Rynd – Tudor Pickering Holt & Co. Securities, Inc. .

Welcome to the PBF Energy First Quarter 2014 Earnings Conference Call and Webcast. At this time, all participants have been placed in a listen-only mode, and the floor will be open for your questions following management's prepared remarks. (Operator Instructions) It is now my pleasure to turn the floor over to 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, pbfenergy.com.

Attached to the earnings release are tables that provide supplemental financial and operating information on our business. Before we get started, I'd like to direct your attention to the forward-looking statement disclaimer contained in today's press release.

In summary, it outlines the statements contained in the press release and on this call that express the company's or management's expectations or predictions of the future are forward-looking statements intended to be covered by the Safe Harbor provisions under federal securities laws.

There are many factors that could cause actual results to differ from our expectations, including those we described in our filings with the SEC.

As also noted in our press release, we will be using several non-GAAP measures while describing PBF's operating performance and financial results as we believe those measures provide useful information about our operating performance and financial results, but they are non-GAAP measures and should be taken as such.

It is important to note that we will emphasize adjusted pro forma earnings information, our GAAP net income or GAAP EPS figures reflect only the percentage interest in PBF Energy Company LLC, owned by PBF Energy, Inc which averaged approximately 55% during the first quarter and with 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’ve reported first quarter operating income of $260.2 million, an 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 continue 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 four to eight weeks depending on the refinery, the crude point of origin, modes of transportation and other commercial factors.

We had approximately $30 million of rent expenses in the first quarter, which is higher than planned as the market price of rents has remained elevated in the face of uncertainty caused by the continued delays in the EPAs 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 spend $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’ve 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 capital 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 share holders of record as of May 12. At this time PBF dividend policy remains unchanged.

For modeling our full year and second quarter operations, we expect refinery throughput volume 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 and 160 barrels per day. And East Coast should average between 305,000 and 325,000 barrels per day.

One 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 if Canadian heavy during the second quarter.

We expect our operating cost 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 experience 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 slice in the price of natural gas.

While it 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 MMBTU basis for the quarter.

Before I turn the call over to Tom Nimbley, I’d like to briefly comment on the MLP filings and the secondary offerings we completed during the quarter.

As we leave you well noticed in addition to our earnings release this morning PBF Energy 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 this morning’s PBF Logistics press release and the PBF Logistic 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 am now going to turn the call over to Tom Nimbley..

Thank you, Eric 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 scene 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 plan to normal operations as quickly as possible under extreme weather conditions. At the end of the quarter, we bought a significant portion of the refinery down for plan turnaround of its lube block.

This work last 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 are fun, 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 to our overall systems was about 431,000 barrels a day. The Mid-continent averaged about 138,000 barrels a day and the East Coast sytem 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 the 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 the 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 months and our operating expenses to adjust accordingly. The Mid-continent 431 crash spread averaged $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 reflective of improvements to our landed cost of crude in the quarter and the stronger product cracks. Our landed cost 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 price is $0.99 a barrel under WTI on an FOB basis. However, as Eric 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 211 East Coast crack averaged $11.41 a barrel, up from the fourth quarter average of $9.08. 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 changing crude diets that we are seeing in the Gulf Coast, as those assets take in more North American barrels.

Our landed cost of crude on East Coast reflects the optionality we now have as a merchant refiner to pursue the most economic barrels available to our refiners.

We have made significant investments in our East Coast rail assets, which has given us access to increasing 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 all 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 crudes 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 dialog regarding increased rail safety measures. We apply the same rigorous safety practices to our all rail operations that we do across the refining business.

We have voluntarily, as of April 1 of this year, taken in added safety measure of only accepting unit trains comprised solely of CPC-1232 cars or the new DOT-111A 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 all unit trains going to the refineries is an important step to increase the safety of our operations and the responsible thing to do for the communities in which we operate.

While the second quarter of 2014, we expect Atlantic crude costs excluding any hedging or LIFO effects to be about $2 to $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 systems. 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 sytem by procuring additional volumes in North American crude has proven and should continue to prove profitable for our refineries.

And our flexibility to take advantage of opportunities when any waterborne crude oils become economically advantageous, provides us with the ability to react quickly to favorable market conditions and with reliable operations catch you the benefits. 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 hope some of 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 quickly say at this point in terms of all the organization 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 probably we should have anticipated it, but we’re certainly taking steps to avoid seeing something like this next year.

On that note, we’ll be pleased to take whatever questions the audience has.

Operator?.

(Operator Instructions) Our first question is coming from Roger Read with Wells Fargo. Your line is now open..

Hi, good morning..

Good morning, Roger..

Good morning..

I guess, great first quarter number one. Number two, as we look at the second quarter, you’re going to get more light barrels and obviously, but we’ve seen differentials tied.

And can you kind of walk us through what the advantage of railing more light barrels in, is or what you’re 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 maybe some of the issues along the Gulf Coast, you’re starting to benefit you on the East Coast, maybe just 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 are 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 on the refiners on the U.S.

East Coast, cannot substitute the 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 keep the 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.

It’s 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 U.S. 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 four different types of crude a year ago and you’re running eight or 10 now, and I know that’s just sort of an example of numbers, can be much different than that.

Is that where the change has been or…?.

The answer to that is, yes.

I mean, we will today look at – during a month we might look at eight to 10 different crudes and half of them we haven’t run on a traditional basis, but we also see crudes coming back to us, back 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 sulfur to 4% sulfur.

So it’s just a terrific flexibility 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? Kind of walk us through CapEx, share repo, dividend that sort of approach..

So I think that was a multi-faceted based question. At this point no plans to do anything with the balance sheet other than stated course. We do have long-term Senior Secured Notes that are in place through the year 2020. And we currently did not have, all right at the end of the quarter, we did not have anything outstanding on our revolver.

So we feel like, we have ample liquidity to operate the business or keeping the dividend program the same ended 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 in three years though in terms of purchasing refineries in getting them operating and of course we had our private equity partners over the last 18 months active sellers of our shares.

As mentioned earlier by Erik, we now have about 70% of the shares in public hands traded on 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 will 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 barrels a day certainly can grow.

And we’ve got a good young management team and I think they are 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..

And our next question comes from Ed Westlake with Credit Suisse. Your line is open..

Hey, good morning and congratulations on demonstrating that you can benefit from what’s going on in the domestic crude business in the quarter. 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 a profit for the fact that are a good outlet before that crude and then reflective of the railcars, I mean we are starting to see the sort of term compositions creep up, that’s Canada, and then also I would love any color on how the Mexicans are thinking about the fact that they may loose 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, heavy 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 very attractive and stable outlet particularly for Canadian heavy crude.

We have a fleet, modern rail cars, 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 and say, do from time to time and want to sell crude to us on a forward basis normally we would buy three months forward, but they came and say six months, nine months a year, we have had an organization that can handle that easily.

With regard to what the Mexicans are thinking, I must tell you I do not opine on what the Mexicans are thinking. But what we are seeing with virtually every type of crude coming to the U.S. 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 the gravity of 24.

In my previous experience was that I don’t think we brought a barrel of crude in there with an API gravity over 30. Our engineering staffs, when looking at the opportunity of running like crudes was able to create a situation at that refinery where we can run over a 100,000 barrels a day like 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 backout, Maya, you get them backout, Isthmus get them backout, our light, our 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 are 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 are going to see more of this in the future.

I think you could say by intelligence or probably just as well by luck, we managed to only two refineries on the East Coast to compress, it’s just about anything, and we are starting to benefit for us, and I believe we are going to continue to..

Thank you, that’s fair, 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 in the sell trying to agree the right value of the option that PBF offers these producers?.

Yes, we are interested in working roughly with the producers and we are having increasing success, and frankly going back to the 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 wanted 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 are seeing more and more of that on the national company level getting often the credit from people, which we previously had not and this just drives us forward and make us a better company..

Okay, hopefully a very quick one.

Any self help we should be aware of to lead our turnaround?.

Yes, Tom..

We’ve advertised before, during this turnaround and then extended into next year because we’re actually be putting tie-ins to execute some of the 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 the – from September over the next 12 months into 2015.

So, over that period of time, you would expect to see, it generates about $80 million in more EBITDA on a Toledo basis..

And in essence, what we are looking at is a profitability yield of an additional $1.50 a barrel on the throughput there, and that’s not kind of that, I would call that with very resilient less market dependent circuitry coming through certainly the availability of significant additional crude oil storage there, we’ll drive it and we haven’t calculated anything to adding a rail discharge facility at that refinery and making that calculation probably would be problematic.

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

Thank you..

And our next question comes from Jeff Dietert with Simmons. Your line is open..

Good morning..

Good morning..

Good morning. .

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 that Bakken is field zone trading maybe more than the normal $2 of transport under ClearBridge.

Could you talk a little bit about that in and are those Bakken rail economic at current spot prices..

They are certainly economic for us at current spot prices.

Our last purchases Bakken crude oil which I can tailor made yesterday land in 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 may be under a bit of pressure.

We have very favorable rail economics compare to our competitors on the U.S. East Coast. So that does play in to our hands. And I should point out that on Brent WTI differentials we are generally well forward out from months. So if you look at June-June today, I don’t know whether this has been in Brent better would be $8.

Well on the crude that we are buying for June, we have certainly not looking at that differential, we’re looking two months forward. It is just the way these things price out. So the tips for us are reasonably good, and I don’t see a situation in the near term were we will be buying Bakken any premium to Brent.

In fact, our rail movements move up and down a bit, because if we see Bakken getting too pricy, 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 about the quality? Are WCS type barrels? Are they Bitumen? Is that going to change as we come out the winter months in December months?.

Yes, so this time, basically you could look at us, we base load a volume of sour Bitumen, which we’re bringing in, that can go from depend upon the availability, it’s a little lower in the first quarter because of severe weather conditions in the slower transit finds. But somewhere around 12,000, 15,000 barrels a day of Bitumen.

That has typically been very economic and more economic in even WCS that a little bit. The balance will be WCS type grades, as we move up from, say call it 15,000 barrels a day of Bitumen on the margin everything else was likely be a Canadian heavy blended crude..

Thanks for your comments..

And our next question comes from Doug Leggate with Bank of America Merrill Lynch. Your line is open..

Thanks good morning, fellows. I just got a couple of quick ones hopefully, and I guess the comments around Mexican crude, should we not be thinking about heavy Mexican, whether it’s Isthmus or Maya whatever, becoming a more reasonable part of your diet.

Given all the commentary before about the strategic optionality have in the East Coast?.

Yes, I think you should look at Mexican grades becoming a very regular part of diet and don’t confuse Isthmus with Maya. I mean Maya is a real heavy crude. Isthmus is much more like an Arab Light, very easily run in either one of 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 a 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 of those refineries..

I would add also when it comes to the takeaways 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 approved 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 issue.

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 is 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 Christie up to the U.S. 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 decided that saving $6 or $7 a barrel, which is a Jones Act number to move crude up in the Gulf Coast, is not in our best interest..

Right, I appreciate the answer. My follow-up is really something that I guess doesn’t get a whole lot of attention. As you continue to shift your diet in one 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 give 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.

So 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 at Bakken and Delaware City, but we’re not going to run anymore than that. So the increment on light crude, if it’s Bakken, will be into our Paulsboro system again if it’s economic.

I will also say that all light crudes are not light. We are now running light sour blends from North America. And again, to Tom’s point that he’s 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 – it’s not as light as the Bakken crude. 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..

And our next question comes from Evan Calio with Morgan Stanley. Your line is open..

Hey, good morning, guys..

Good morning..

Just a follow up on Tom’s earlier comments, Tom O'Malley’s earlier comments on growth, I mean any comments on the MA environment? You mentioned a broader North American interest. I assume that includes all regions including California. Any comments and I have a follow-up. Thanks..

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 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 is always a question, well, are there going to be more refineries available in other areas alike.

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, we counted on one finger, and independents have done a 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 and have the management team that knows how 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 would fire me because that’s – and I don’t want to be fired and I want to work a little bit longer. So I hope that answers your question Evan..

Yes, 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. .

Thomas J. Nimbley:.

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 a continued rise in the crudes available in North America. I’m extremely optimistic about what's happening, I mean and this it’s happening in spite of the government.

Can you imagine what will happen if the government was actually supportive of anything like this. So, we have a 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 you consider, if it’s surrounding the quarter joined infrastructure pipelines today.

So we have a very positive view, by the way that view extends to the State of California..

Awful guys, thank you..

.

:.

Hey, guys. Good morning..

Hi.

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?.

Thomas J. Nimbley:.

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

So if something came along and it had retail attached to it and that was a requirement to do the business, I suppose we’ll do it but I think, we’d probably then turnaround 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, pre-historical..

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 maybe in terms the nature of the contracts?.

Yes, sure well very often work with people on a longer-term basis and in action to agree to let’s say take 10,000 barrels a day from one producer or another and generally will set a differential in most cases to WTI for a more limited time period in the frame contract may run.

We really go with the producer and if the producer wants a longer-term to map with that a fixed differential, we’re prepared to do so we are 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 is no fixed formula and as and far approach to this business is to talk to the producers and see what the producers want to do and well accommodate them. If you want it for three months, we’ll accommodate you, if you want it for 12 months we can do it, frankly if you want it for longer we can do it.

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 formally 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 that were disappointed about this.

There are people within our company who are happy about it because we can certainly offer that service and indeed you really don’t need a middle men involved in it and that we potentially want one. So it is a nice situation for us going forward..

And Tom, can you give us a rough estimate that 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 brand or something like that?.

Just be careful here and 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 the Brent based goods or WKI based goods. And if we looked at Bakken, you would say the majority of our purchases on a WTI basis where we have to put on the front Brent WTI spread.

We do that at the time when we fix a differential to WTI but sometimes we’ll lag in a bit, sometimes we’ll lead it a bit depending on our view of the Brent – WTI’s Brent but not by March, we’re pretty ratable in the way we handle things.

On an imported basis from more of our crude has a front portion day one coming into us, up in Canada most of it is WTI based. But again the sellers were – when we talk to sellers they should just tell us what they want to do and we’re equipped to do it..

Thank you..

And our next question comes from Paul Sankey with Wolfe Research. Your line is open..

Hi, good morning everyone..

Good morning.

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 just 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..

I don’t well have an overhang but I think if you 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 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 there is frankly private equity did a very good job in supporting us. They have been no extraordinary dividends if anybody reads the newspapers very often private equity has taken extraordinary dividends out of companies.

In our case, all 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 I frankly, if you don’t want some growth it’s probably wrong place to be.

And what I would refer, really one reason, can it be accretive and accretive is not earning $0.05 or $0.10 a share to the earnings of the company, accretive is significantly accretive to the share price, and we are bust in way, many of the companies the independence out there have a very large number of shares outstanding, we have less than 100 million shares outstanding.

So we can figure out some way to add a $1 a share and profitability to the company. Well, we’re going to go and do that, and as for a separate entity, everybody sitting around this tables employed by PBF and we’re going to drive it through PBF, we are not doing any separate entities..

Got you, it's clear. Just 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 U.S. 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, when you buy one of these refinancing companies one always has to be realistic and you have to say you’re buying the crack and that’s true, whether you talked about the PBF Company, Valero, Marathon, Tesoro, whoever you are talking about this is big issue.

What if you study or a product assumption long period of time, 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 see growth of 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 part of that is the oil boom itself.

The oil boom has massive implications across its country, it’s creating well in a very rapid manner and certainly people are doing well we can see that loan loss across the spectrum of the Northeast is a good marketplace for us. And we are 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 will be up and down, there will be seasonal changes, there will be things for we didn’t have a hurricane last year on the Gulf Coast, very unusual environment. So it will be affected by outside basically 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 nearly up to the East Coast.

They are going to Mexico, their [indiscernible] has a well and I think they are still buying gas only – so there are such a big exporters it’s now in the United States that we are benefitting from the conversion of products from Gulf Coast. So I see a reasonably strong crack market up here in the East Coast..

Understood and then if I could follow up you’ve been vocal in opposing that is for the crude. Is it really this big for you guys I mean won’t you still if crude was allowed to be exported wouldn’t you still have a transport advantage against a European refiner? And I will leave it there. Thank you..

Well just answering that quickly we are not particularly vocal and opposing the export of crude. What we have been vocal about is level playing field for heaven sakes, if we are going to take the crude and export it to all around the world; please us export it to the U.S 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 Jones Act shift which cost us $6 to $7 a barrel, so we have been opposed to that.

Additionally, you all may remember or you may not remember that the 2007 Energy and Security Act, which mandated volumetrics on the use of ethanol was justified, because we were trying to get energy security for the United States.

Well, if we are 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 are not opposed to export per se.

We are opposed to a situation where we are not on in 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..

And our next question comes from Cory Garcia with Raymond James. Your line is open..

Good morning, guys. You know what? Actually all of my questions have been answered. I appreciate it and great quarter..

Thanks Cory..

And we will next go to Clay Rynd with Tudor Pickering. Your line is open..

Good morning, everyone..

Good morning. .

Good morning..

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 kind of hedge for natural gas prices to lock in the cost?.

I’ll look the guys. 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 than what’s out risk. And we should have had that color 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 kind of 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 buyer power plants and the interstate movement of the resulting CO2, I think we’re going to see a great demand for natural gas and I actually think natural gas at today’s pricing levels were probably at the lower end in the spectrum.

That’s kind of how we try and look at things with left what’s the story here it 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, we’ll do more than that, but we can never do 100% of these things because you’re always accounting on perfect operation of your refineries.

So we’re always going to be exposed to something great, but we never should have been exposed to the degree we were and I suppose we sat there preserving previous ventures and said this can I mean, who predicted this, I guess nobody did. But that doesn’t excuse it. So yes we’re going to take steps have taken steps..

I appreciate it..

This does conclude the question-and-answer session. I 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 listening with you in the future. Have a nice day..

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