Good day ladies and gentlemen and welcome to the third quarter 2013 PBF Energy Incorporated earnings conference call. My name is Katina and I’ll be your coordinator for today. At this time, all participants are in a listen-only mode. Later we will facilitate a question and answer session. To pose a question at any time, please key star, one on your touchtone telephone. If at any time during this call you require assistance, please key star followed by zero and a coordinator will be happy to assist you. As a reminder, this conference is being recorded for replay purposes. I would now like to turn the presentation over to your host for today’s call, Mr. Matt Lucey, PBF Energy’s Chief Financial Officer. Please proceed.

Thank you. Good morning and welcome to our earnings call today. With me are Tom O’Malley, our Executive Chairman, and Tom Nimbley, our CEO. If you have not received the earnings release and would like a copy, you can find one on our website, pbfenergy.com. Also attached to the earnings release are tables that provide additional financial information 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 the press release. In summary, it states statements 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 the 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 these measures provide useful information about our operating performance and financial results, but they are non-GAAP measures and should be taken as such. It’s important to note that we will emphasize adjusted pro forma earnings information, our GAAP net income or loss or GAAP EPS reflect only the interest in PBF Energy Company LLC, owned by PBF Inc. We think adjusted pro forma net income or loss and adjusted pro forma EPS is more meaningful to you because it presents 100% of operations of PBF Energy Company LLC on an after-tax basis. With that, I’ll move on to discussing PBF’s third quarter 2013 results. Today we report a third quarter operating loss of $55.6 million and adjusted pro forma net loss for the third quarter…

Thank you, Matt, and good morning everybody. Before discussing the third quarter results, I want to briefly mention the coker turnaround which is currently underway at our Delaware City refinery. The turnaround has been underway for about 30 days, and at this point we expect it to be complete on time, as Matt said, within the next two weeks. I would also like to highlight the fact that this turnaround comes on the heels of a record run of approximately 2.5 years for the Delaware City coker, and this run in many ways is indicative of the improved reliability of this asset. Regarding our financial results, PBF had a disappointing third quarter. The market was the biggest negative for all of our refineries. Throughput for our overall system was about 446,000 barrels a day, which as Matt mentioned was in line with our guidance. The midcontinent averaged about 148,000 barrels a day and the east coast system 298,000 barrels a day. Throughputs across the system were lower than planned as we adjusted run rates due to high flat prices for feedstocks, narrow crude differentials which results in poorer coking economics, and weaker cracks, particularly in the midcontinent. Operating costs on a system-wide basis averaged $4.69 a barrel. During the quarter, the midcontinent 431 crack spread averaged $14.97, down from the second quarter average of $29.26 per barrel, and our margin was $6.97 a barrel in Toledo for the third quarter. The Brent 211 east coast crack averaged $13.15 a barrel, down from the second quarter average of $14.67, and the gross margin for our east coast system was $3.66 a barrel. Our landed cost of crude in the midcontinent was approximately $5.64 a barrel over WTI, as Matt mentioned, principally as the result of the high cost for syncrude which…

Thank you. [Operator instructions] Your first question comes from the line of Paul Sankey, representing Deutsche Bank. Please proceed. Paul Sankey – Deutsche Bank: My first question regards how you see the Atlantic basin market playing out, just in terms of the pain that’s being suffered in Europe. We’ve agreed in the past that we probably need to see shutdowns in Europe, which would ultimately, I guess, improve the market. Can you give us your latest thoughts on how that could play out? Thanks. Thomas O’Malley: Sure. This is Tom O’Malley. I spoke at a conference yesterday in Las Vegas, the Opus event, and in essence that was the theme of the presentation, the Atlantic basin. And when looking at this, and this may be answer that’s a little bit longer than you like, but there we have it, if you looked through the 80s and 90s, you saw a period of time when North Sea production was at a very high level and where in essence European export refiners had an advantage based on what they viewed as domestic crude within the EEC, delivered in some cases directly by pipeline from the North Sea field and others on a one or two-day trip via shuttle tanker. They were a very big factor in the U.S. east coast marketplace and in essence they determined the price. During my presentation yesterday, what I said and what I believe is that we’re going through a sea change here. We’re going through a flip of the coin and now we’re on top of things here in the Atlantic basin. We, in essence, can take in crude oil at a lower price than our European competitors can. They’re paying Brent plus; we’re paying Brent minus, and you can’t make that up. When crude oil…

This is Tom Nimbley. I’d just add to get specific on one of the pieces of the question, we currently have the dual lube track completely done and we can do about 105,000 barrels a day of light-sweets or light-sours. I referenced this project that we were adding, which will be in addition to the dual lube track that will increase that from 105 to 125,000 barrels a day by May. As Tom mentioned, we have 40,000 barrels a day of capacity installed running today on the heavy side. That doubles to 80 right at the end of the second quarter. Paul Sankey – Deutsche Bank: That’s very clear, thanks. And then you gave the Q4 guidance – I think I heard that. We don’t need to—I mean, you might repeat it, but there’s guidance for how much you’re taking in Q4, right?

Yes. Yes, we’re going to do 85 to 95,000 barrels a day of Bakken. We might exceed that a little bit, but that’s the number; and 25 to 35,000 barrels a day of WCS, Canadian. We are running 10 to 12,000 barrels a day of pure bitumen into the east coast system. There are economics that are better than WCS on that, simply because we get a bigger discount by buying the lower gravity bitumen that more than offsets the increased transportation cost, but 25 to 35,000 barrels a day because of the coker downtime at Delaware on the heavy side. Paul Sankey – Deutsche Bank: Okay, great. And just to finish and round that out, then, so between the Q4 numbers and May-June, I guess we run forward with the Q4 numbers as your run rate?

Once we get the Delaware City up, we’re going to run 40,000 barrels a day. This is all obviously predicated on economics. Basically we’re going to run 40,000 barrels a day of WCS. We have very, very favorable economics right now until we get to the end of the second quarter, and then we’ll be able to double it. I also did make the point—maybe I wasn’t as clear on it. One of the thing we’re going to be looking at is we delayed, as a number of us have mentioned, including Tom, the second 40,000 barrel a day facility until midyear next year because of timing it up or syncing it up with infrastructure being built out in Canada to allow the loading of heavy Canadian into rail, and the timing of our rail car fleet. We are starting to see some indications of producers having their own cars, or other people perhaps offering some deals on a delivered basis. We’re going to watch that close. If that looks like it’s going to happen, we might try to see if we can advance the rack itself by six weeks or so. We’ll make that call as market conditions play out. Paul Sankey – Deutsche Bank: Thank you, guys.

Your next question comes from the line of Evan Calio, representing Morgan Stanley. Please proceed. Evan Calio – Morgan Stanley: Hey, good morning guys. A question on rail, and I realize that as you said, all the crude differentials for you in particular are much better now than they were in the third quarter. But with the east coast rail yard closed for a significant portion in the quarter, I think it looks like your Bakken volumes were 10,000 barrels a day lower. Can you discuss just how quickly you can shift away from rail volumes in that environment, given you’re replacing them with, I presume, water borne? And what was the cash cost as you think about the cost of not running rail, committed costs you may have there that factor into the economics of the decision not to rail? Thomas O’Malley: Well look, there are two different answers dependent upon the crude that you’re talking about. On the Bakken, there is really no significant downside if we decide to take in an imported barrel as opposed to Bakken. The majority, of course, coming in with Bakken, do not belong to our company, so we’re not suffering any debit on that side of the equation. On the heavy, it would of course be slightly different in the sense that as we build up the rail fleet, and certainly we won’t be at a level with the rail fleet where we can completely use our own cars probably until the fourth quarter of 2014, so we’re still using third party cars on the heavy side. At that point, if you laid up a car, there’d be a cost for that car, and the cost for each car is about $1,000 a month, maybe a little bit less on a lease…

Your next question comes from the line of Roger Read, representing Wells Fargo. Please proceed. Roger Read – Wells Fargo: Good morning. I guess two things I’d like to kind of understand a little bit. How quickly you can react in terms of moving by rail both up and down, so obviously harmed in the third quarter but volumes by rail were similar to the second quarter, so maybe you can give us an idea of when you might have ramped up or down during the quarter. And then obviously as you explained both in the press release and in the opening statements, we’ve seen differentials expand quite positively here in the fourth quarter. How quickly can you move to unit trains, either using them more frequently or taking advantage of manifest deliveries? Thomas O’Malley: You should think in terms of a week. Certainly we follow the market on a daily basis. If we see a trend changing, we really came into the month of July and by the month of July, of course, we were buying for August and September, and we said the numbers are too high and we in essence stopped buying aggressively. You probably could think of a day even, but these things, we see them develop over a week. The Bakken particularly is a marketplace where you can react in a very, very short term. On the Canadian side, it’s a little bit longer lead time in terms of those are cars that we generally provide in the Bakken. I suppose we are maybe supplying 30% of the cars we use, so we’re just buying them from the producers with rail cars attached. In Canada, it’s a different program, or at least it has been until now. So very, very fast in the Bakken, up in Canada I would guess a couple weeks. Tom, I don’t know if you would have a different reply?

No, not a different—something to add, more specific to—Bakken is effectively a unit train, so in terms of the mode of transport by rail, everything we get by Bakken comes in on unit trains and there is right now a very fast reaction time, there’s a lot of Bakken. The Canadian is still manifest, although as you are all aware, Bruderheim and other infrastructure sites are being built out, and we do expect to see some unit train movement starting certainly in the first quarter of next year. That is obviously an advantage to someone who is hauling it by rail effectively to drop our cost down by north of a dollar a barrel on that basis alone. The other thing I’d add is we talk about Bakken light-sweets and we talk about the heavy Canadians. We are in discussions with a Buckeye terminal in Hammond, Indiana where we’re actually going to be loading some light-sweets. It’s got less transit time into Delaware City, but importantly it will have the capability of actually moving some light-sour crudes, and this is something that’s very important to us on the east coast because Delaware City and Paulsboro have the ability to run a higher sulfur crude than Bakken, so these crudes are actually 36 degree API, 1.2% sulfur. They can’t be run in other facilities in the east coast because their true sweet-crude refineries will be able to bring them into Delaware, and we’re starting that operation in November and we’ll try to ramp it up some in December. Roger Read – Wells Fargo: Okay. And then my second and I guess generally unrelated question to that is as we look at what’s moved around in terms of working capital, cash flow and cash balances, obviously we expect better differentials and probably better margins here in the fourth quarter and first quarter than we saw in the third. But can you give us a little bit of an idea of maybe some of the future cash issues, if there is any pension payments or tax payments or anything else unusual that we should be thinking about here over the next three to six months. Thomas O’Malley: Matt, why don’t you answer that?

Sure. Roger, as you recall from our last conference call back in the second quarter, we spoke about a big working capital swing. We obviously saw that come back. I would quantify our current position as sort of normal operating levels, so I do not anticipate big swings going forward. That being said, it’s sort of a reality with $100 crude, if you’re bringing in a 500,000 barrel vessel, they don’t come in perfectly ratable. You can and will have swings, but I think to answer your question directly, we are where we should be so I don’t anticipate anything major in the future. Roger Read – Wells Fargo: Okay, so basically just operational issues at this point?

That’s correct. Roger Read – Wells Fargo: Okay, that’s it for me. Thank you.

Your next question comes from the line of Ed Westlake representing Credit Suisse. Please proceed. Ed Westlake – Credit Suisse: I’ve got a story for you guys. I was up in the farm belt and I got a Hertz car and it was a flex fuel vehicle, and it had a big sticker saying, no more than E15, and I was driving past gas stations saying, ethanol-free gasoline here. So that shows how much enthusiasm there is. Just a quick question, though, on core capture rates in the east coast in particular. Obviously we’ve had a long discussion around the crude discounts, and WCS and Bakken look like they need rail to get to market, so that’s good for you guys. But Tom, maybe just chat about how you think about how the east coast sort of refining assets are doing relative to your hopes for where that core capture rate should be. Thomas O’Malley: Tom Nimbley, why don’t you take that? He said Tom – we’ve got two of them. Ed Westlake – Credit Suisse: Sorry Tom.

Yes, little Tom will try to take care of this. The east coast, from an operational standpoint, we’re quite pleased with the way the east coast is run from basically the foundation of this business – safe, environmentally responsible, and reliable operations. From a yield standpoint, we’re still looking to see whether or not—what we can do to try to get a little bit higher C3-plus yield out of Delaware City. We’re actually doing some things during this downtime unrelated to the coker. There are some other facilities that have come offline that we scheduled to come down with the coker, that we’re making some improvements in. The biggest thing we see going forward that I think will be an improvement on that, and we’ve started, is we’ve effectively figured out how to make 100% ultra-low sulfur diesel at our Paulsboro facility, and typically that facility makes about 25,000 barrels a day of jet; but everything else was number two fuel oil, 2,000 part per million fuel oil. We completed— Thomas O’Malley: Heating oil.

Heating oil – I’m sorry. So we completed a project that Valero had bought some equipment for. We now have that facility capable of making 15 part per million ULSD or ultra-low sulfur heating oil; however, it does come with some economic debit on—we have to reject some material out of the distillate pool. We’re going to basically, after we restart Delaware City up, be able to move that material over to Delaware City and turn it into ultra-low sulfur diesel at Delaware City. So we’re going to see some improvements in what we’ve been able to do, but on the east coast and in fact in Toledo, the thing that’s going to drive the capture rate is going to be the landing cost of crude versus the benchmarks. Thomas O’Malley: Just let me add something to that. The big—Ed, of course as an engineer, has worked in refineries – I don’t know that all the other callers have. So the C3-plus is of course more easily defined for those of us who think in those terms as stuff that sells at a price greater than crude oil. That’s our goal and objective. I think the big swing you’re going to see going forward is we’re going to make less petroleum coke at the Delaware City refinery, and there that’s going to creep over into that C3-plus material. Whether that turns out to be a half percent or 1% is something we don’t really appreciate today, but in essence we’re squeezing the material a little more, we’re running it a bit more intelligently, and some of the changes that we’re making during this turnaround – and we are investing $25 million during this turnaround in rate of return projects at Delaware – I think that’s going to have a favorable effect. It certainly will result in the production of more ultra-low sulfur diesel also at Delaware. So there’s a lot of things going on inside the box where we are going to see some improvement, and for us the ability now to get out of the 2,000 part per million heating oil market and be in the ULSD market without making some massive investment was really a tribute to all the equipment and the smart people we have within the company.

One other comment I’d make, Ed, that goes along with what Tom was saying is right now, obviously, we’re also being some advantaged – we’ll see how long it lasts – the lower cost of crude means lower losses on coke products. So the price of coke doesn’t change, but the price of crude goes down, for every dollar you’re going to pick up perhaps $0.10 a barrel margin on a coking refinery. So if we see this trend continue, that should show up in a higher capture rate. Ed Westlake – Credit Suisse: Yes, I’ve got some specifics then on what you’ve said, and that’s all very helpful for thinking about capture rates improving going forward relative to this year. But just on ULSD at Paulsboro, how much heating oil fuel are you selling in thousands of barrels a day, or percentage of slate – whatever is easiest – just so we can think about what that change is going to do? Thomas O’Malley: We’re not selling any 2,000 part per million heating oil.

At Paulsboro. Thomas O’Malley: In essence, you can look at the upgrade between—if you compared it to last winter, the upgrade between—what were we selling, 25, 30,000 barrels a day heating oil?

Correct. Thomas O’Malley: That’s now all either jet or ULSD.

And at Delaware City, we still make some amount of heating oil, 2,000 part per million heating oil, about 10,000 barrels a day when the refinery is running. After we come back up, with the projects that we’re putting on, probably by first quarter, end of first quarter, we’ll be completely out of the 2,000 part per million heating oil business unless it is economic. I mean, there could be a case that it could come back. Ed Westlake – Credit Suisse: And then just a general comment on LPG yields – do you know roughly what your LPG yield is on the east coast and Toledo? Obviously LPGs are probably going to be trading lower than crude for a while.

Yes, and of course that’s a seasonal percentage. It’s going to go up as butanes come out of the gasoline pool in the summertime, and it’ll come down, and you’ll see pronounced shifts in the capture rate associated with that. It’s about 4%, 4.5% when butane is out of the gasoline pool on the east coast, a little bit more than than in Toledo, running a lighter crude slate than we see, and it drops off about a percent as you move into the wintertime season. Ed Westlake – Credit Suisse: Okay, I’ve probably taken up enough time, but that’s very helpful. Thanks very much for thinking about capture rates.

Your next question comes from the line of Robert Kessler representing Tudor Pickering Holt. Please proceed. Robert Kessler – Tudor Pickering Holt: Hi, good morning. I’m assuming at the current spread between Bakken and Brent, that you’re incentivized to not only maximize your own rail intake through your vertically integrated system but also look for others who might have availability. To that end, is that an accurate comment, and do you see other third party terminals coming up kind of online with expectations, and would you be looking to buy more cargoes there? Thomas O’Malley: Let me answer that question, first of all with regard to Delaware. We have enough capacity in the terminal in Delaware to service all of the needs of Delaware. We really can’t run more than 100,000 barrels a day of Bakken at Delaware, so that clears that. With regard to our refinery over at Paulsboro, we do take on an opportunistic basis barge delivered barrels of Bakken. These come out of other terminals on the east coast. Of course, I think everybody knows there’s a very large terminal up in Albany, New York, and we certainly have taken material in from there, and there are a couple other locations where it comes in. So that—we keep track of all that. We are expanding, as Tom indicated in his remarks, our ability to take in Bakken crude oil, up to about 125,000 barrels a day, so that to the degree we can source that crude oil and use it over at our Paulsboro refinery, it’s a much more economic move than taking it from third parties. There’s a very small cost involved in barging that material from Delaware over to Paulsboro, and our costs into Delaware are, we believe, lower than anybody else on the east coast. So we’re looking really to cover that corner of the business with our own facility, but that extra capacity won’t be up and running probably until April, May of this coming year.

I would add that we’re going to probably run—we can run 100,000. Probably with the Canadian differentials, when we start up the coker, we’ll probably run Delaware at around 90,000 barrels a day of Bakken. If we deliver 105, which is our capability, and with these economics we’re going to strive to do that, we do have this permit capability to trans-ship, as Tom mentioned, from Delaware over to Paulsboro. That’s a 45,000 barrel a day opportunity, so we’ll move every barrel, notionally 15,000 barrels a day, over to—or 20,000 barrels a day over to Paulsboro. We are also, however, periodically putting in barge cargoes to Paulsboro out of places like Albany if the prices are there, and as these differentials move out, they’re going to be there relative to some of the alternatives. Thomas O’Malley: Yes, I want to interject here that I think when looking at us as opposed to looking at the other east coast sweet refiners, you should recognize that we will bounce back and forth. I think two weeks ago, we had a Basra cargo – this is an Iraqi crude of 500,000 barrels offered to us. Tom, I think the number was—was it $11 under Brent or something like that?

$10.90 under Brent. Thomas O’Malley: $10.90 under Brent. Well, suddenly that became more interesting to us than moving Bakken at—which in the same time frame might have been $3 or $4 under Brent. So we—the advantage we have is that we can shift back and forth between a higher sulfur crude. If you’re a sweet refiner on the U.S. east coast, if you’re a COP Delta or a PES, and a Basra cargo appears, you can’t run it – it’s just that simple. So it is giving us added flexibility. So exact modeling is really for us a function of what offers the largest discount at that moment in time, and what does our LP say about the recovery.

One other thing – I mentioned these light-sour blends, distressed crudes, and I didn’t give you that we’re starting to procure and we intend to move in by rail. I didn’t give you any numbers on it, but if you look at the differentials right now, that crude, which is a 36 degree API crude so it’s quite a bit—you know, Bakken is 41, WCS is 21, so it’s a pretty high quality crude. But it’s trading right now at $24 under Brent, and— Thomas O’Malley: That’s on an FOB basis.

On an FOB basis, but we think we’re going to land in with less than sub-10 or maybe around $10, you’re getting—you have right now in this market the opportunity to get a pretty high quality crude at a very big discount, and again, that is an advantage of our facilities versus the other east coast facilities simply because we can handle the sulfur. Robert Kessler – Tudor Pickering Holt: And what basin is that coming from, that higher sulfur crude? Thomas O’Malley: It’s Canadian light-sour. Robert Kessler – Tudor Pickering Holt: Okay. Thomas O’Malley: I’d just throw one other thing, and again for the listeners, I think it’s interesting and it is symptomatic. We took—we have an isthmus cargo coming in. Back in the, I think it was Premcor days, we owned this refinery. I don’t recall that we ever had an isthmus cargo. How did this happen? What’s happened is the bathtub has filled up on the Gulf Coast. The Gulf Coast is starting to take in more sweet barrels – in essence, there are refineries down there that can run sour but they’re finding that the sweet economics are better, and they’re backing out some of the lighter sour crudes that they were previously taking in. We’re a beneficiary of that, and that goes back—and in my thinking about it as a shareholder of this company, I look at this sea change in the Atlantic basin from the guys over in Europe having a crude oil cost advantage to the change of, gee whiz, the guys in North America now have a real advantage. We’re going to be the exporters to over there, as opposed to them being the importers to the United States. It’s just—you know, we’re seeing things that we certainly wouldn’t have forecast as short a time ago as six weeks or eight weeks. The bathtub is really filling up, and I think North American refiners are in for a pretty good sprint. Now, when I say that, I do talk about the east coast, the Gulf Coast, and the midcontinent. My knowledge of AB32 on the west coast would preclude me from making an intelligent comment about that. Robert Kessler – Tudor Pickering Holt: Okay. Can I come back real quick to the bitumen comment around taking undiluted bitumen at a discount to WCS? Can you give us some magnitude on what level of discount you’re getting that for on a laid-in basis? Thomas O’Malley: Tom?

Yes, basically it depends on the bitumen, but just to give you—we run Peace River bitumen that we’re buying at notionally on average, I’d say, as much as an $8 differential lower than WCS, and maybe it costs us $4 for additional transportation, and there’s really not—hardly any quality debit because one of the things you do when you make WCS is you put effectively gasoline into WCS to blend it up to 21 degrees, and particularly in the summertime there’s not much value for that light straight (indiscernible) because you have a difficult time getting it into the gasoline pool. So we’re probably making an incremental $2 a barrel on—in the current market structure on the bitumen by taking that directly in with our coil and insulated cost. Robert Kessler – Tudor Pickering Holt: That’s great. Thanks for the detail.

Your next question comes from the line of Jeff Dietert representing Simmons. Please proceed. Jeff Dietert – Simmons: Good morning. I apologize if I missed this, but I only saw the refining gross margin for total company in the press release. Again, apologize if the east coast and Toledo is in there, but could you break those out individually?

Toledo gross margin was $6.97 a barrel. The east coast was $3.66 a barrel. Jeff Dietert – Simmons: Okay, thank you. Secondly, if you look at Canadian heavy differentials, and there is clearly good visibility to production growth there, the Keystone northern gateway, trans-mountain all struggling with environmental and political objections. Alternatively, the Keystone south and Seaway Twin lines will probably take more Canadian heavy to the Gulf Coast, and BP Whiting is shifting towards Canadian heavy with their crude unit. Could you talk about how all these factors influence the outlook for Canadian heavy discounts in 2014? Thomas O’Malley: Let me try and take that. I think first of all, the comment that a lot more Canadian heavy is going to move south may not be accurate. What we’re starting to see as we get down to the Gulf Coast is that the Gulf Coast is being filled up with additional U.S. domestic production, and we’re backing out now. We’ve already backed out on the Gulf Coast virtually every barrel of imported sweet crude. Now we’re starting to back out some of the medium gravity crudes. I don’t think there’s going to be a giant additional flow down to the south. My own comment with regard to the pipelines, particularly XL, the northern portion of it, if the Obama administration hasn’t made a positive decision on that pipeline at this point, well, I think you can be relatively sure that no positive decision will be taken prior to the next Congressional election, which is a year away, and then trying to get the thing in place with the environmental lobby still against you would add years to it. So we’re not particularly concerned about pipelines at this moment in time. I think it’s a function of how fast this…

With no further questions at this time, I would now like to turn the call back to Mr. Tom O’Malley for any closing remarks. Thomas O’Malley: We just want to thank everybody for attending the call, and we sincerely hope that the market gives us a better opportunity in the fourth quarter than it did in the third quarter. Thank you for attending.

Thank you, sir. Ladies and gentlemen, thank you for your participation in today’s conference. This concludes the presentation. You may now disconnect. Good day.