PBF Energy Inc. (PBF) Q1 2013 Earnings Report, Transcript and Summary

Good day ladies and gentlemen, and welcome to the First Quarter 2013 PBF Energy Incorporated Earnings Conference Call. My name is Shiquana, and I’ll be your coordinator for today. [Operator Instructions] I would now like to turn the presentation over to your host for today’s call Mr. Matt Lucey, PBF Energy CFO. Please proceed sir.

Thank you. Good afternoon and welcome to our earnings call. Today with me as always Tom O'Malley, our Executive Chairman, and Tom Nimbley our CEO, we also have a couple of other members of our senior management in the room with us here. If you have not received the earnings release and would like a copy you can find one on our website www.pbfenergy.com also attached to earnings release are tables that provide additional financial and operating information on our business. One housekeeping item, there was a minor typo, maybe it was virtual thinking in the press release. It says, “PBF also reached an agreement with Savage to transload Bakken crude oil at Savage’s Trenton” it should North Dakota rail facility, and in the release it said Trenton, New Jersey rail facility, it might have been virtual thinking update, to start producing in Bakken and New Jersey will be well positioned as anybody I guess. But it should be Trenton, North Dakota. Before we get started I would like to direct your attention to the forward-looking statement disclaimer contained in the press release. In summary, it states that statements in the press release and on this conference call that states 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 including adjusted pro-forma net income, adjusted pro-forma EPS, refining gross margin, EBITDA, and adjusted EBITDA. We believe these measures provide useful information about our operating performance and financial results, but they are non-GAAP measures and should be taken as such. It is important to note we will emphasize adjusted pro-forma net income and adjusted pro-forma EPS in this earnings call rather than GAAP earnings. Our GAAP net income and GAAP EPS reflects only 24% interest in PBF Energy Company LLC that is owned by PBF, Inc. We think adjusted pro forma net income and adjusted pro forma EPS is more meaningful to you because it presents a 100% of operations of PBF Energy Company LLC on an after-tax basis. With that I’ll move on to discussing PBF’s first quarter 2013 results. Today we reported Q1 operating income of $100 million versus an operating loss of a $164 million for the first quarter of 2012. Adjusted pro forma net income for the first quarter was $46.7 million or $0.48 a share on a fully exchanged, fully diluted basis, as compared to a loss of a $122.6 million or negative $1.26 per share for the first quarter 2012. Finally, our adjusted EBITDA for Q1 was a $109 million versus a loss of a $156 million for the year ago quarter, a $265 million improvement quarter to quarter. At the end of March cash was $404 million and our net debt to cap ratio was 16%, which compares to 54% at the end of the first quarter 2012, and 21% at the end of the year. Net debt declined by $120 million over the first quarter from year end to $323 million. Over the quarter the company generated $211 million in operating cash flow. Regardless of the improvement from last year the results fell below our expectations. The first quarter was adversely impacted by several items, first and foremost is the fire at the FCC Complex in Toledo. We calculate that unclaimed downtime at Toledo negatively impacted EBITDA by more than $80 million. The unit was down for 18 days but importantly feedstock and product inventory effects ran longer. The rising cost of compliance with renewable fuel standards was the second item. Rents cost for Q1 were $10 million more than what was budgeted going into the year. Adjusting for these two items by themselves adjusted EBITDA would have been over $200 million for the quarter. In addition to those hydrocarbon prices in our system rose on average $4.55 a barrel over the quarter resulting in a $65 million of LIFO expense. We’ve seen prices retreat in the first part of the second quarter and would expect to recoup a significant portion of the first quarter charge depending on prices in the balance of the second quarter. Now, specifically to the East Coast. The East Coast gross margin fell below our expectations. The reasons for the short fall over the first quarter include, the high flat price of crude which prevailed over the first quarter had a punitive effect on the gross margin for low value product such as coke, sulfur, and LPGs. We experienced slightly narrowed crude differentials, the weak lube crack over the first quarter lube demand is usually seasonally weak in the winter months. And as previously mentioned we experienced higher cost of rents. Importantly, so far in the second quarter we’ve seen the flat price of crude moderate, we continue to grow our North American crude exposure to the east coast and the lube crack has since widened. In regards to rents, we budgeted approximately $60 million for the entire year. Based on current market prices we would expect to spend approximately a $120 million on ethanol rents, and about $40 million for the balance of the requirement for 2013. We expect to recoup a significant portion of the cost of the rents in higher prices for transportation fuels because we believe that markets will adjust to a higher embedded cost of the rents in transportation fuels. For the first quarter of 2013, G&A expenses were $30 million compared to $14 million during the last year’s first quarter. The increase in ’13 relates primarily to increased headcount and personnel cost generally associated with being a public company and growing our commercial business as we reduce our reliance on other third parties. In the first quarter of 2013, G&A expense was $27 million, again compared to $21 million for the year ago quarter. The increase was mostly due to amortization expense related to the first quarter of 2012 turnaround in Toledo, and depreciation expense related to the implementation of our information systems. First quarter 2013 interest expense was $22 million. That was actually down $10 million from the first quarter of 2012 as a result of lower interest cost associated with the ABL Revolver and the Statoil agreement. And last year we wrote off the debt that was repaid from the proceeds of the senior secured notes offering. PBF Energy’s effective tax rate for the first quarter was approximately 39.5%, capital spending was approximately $59 million for the quarter. At the end of March we had approximately $610 million of available liquidity. Our board of directors has approved the quarterly dividend of $0.30 share payable on June 7, 2013, to shareholders of record as of May 21, 2013. The dividend for the quarter is reflective of both the Board and Management’s confidence in earnings power of PBF and our continuing commitment to returning cash to shareholders. From modeling our second quarter operations we expect the refinery throughput volumes to fall within the following ranges. The Mid-Continent should average a 158,000 to a 160,000 barrels a day and the East Coast should average between 320,000 and 330,000 barrels a day. Our run rates for the year will be impacted by previously announced turnarounds at Delaware City and Paulsboro which are 45 days and 15 days respectively. We expect our operating cost for the year to range between $4.30 and $4.40 per barrel which includes the impact of Toledo in the first quarter. I am now going to turn the call over to Tom Nimbley who will go over the operational overview of the company.

Thank you Matt, and good afternoon everybody. As Matt mentioned our first quarter results were negatively impacted by the unscheduled shutdown that occurred on the Toledo cat-cracking unit in late January. The refinery was essentially shutdown for 18 days as a result of this incident and in fact required additional time after restarting to achieve fully lined out operations. The overall EBITDA impact of the shutdown for the quarter was a loss of approximately $80 million. Throughput for our overall system was at 442,000 barrels a day with the Mid-Continent averaging 123,000 barrels a day, again impacted by the late January outage. The East-Coast system ran at 319,000 barrels day, the East Coast ran well although we did reduce throughput on the East Coast somewhat during March due to poor margins associated with narrowing crude differentials. Operating cost on a system-wide basis average $5.19 a barrel, the East Coast was slightly higher than forecasted at $4.89 a barrel due to higher natural gas prices, while Toledo’s cost were again negatively impacted by the outage, an average $5.97 over the quarter. The refining margin environment was strong in pad two during the quarter with 4-3-1 crack spread averaging over $26 a barrel resulting in the $19.50 a barrel gross margin that was achieved at Toledo in the first quarter. The Brent 2-1-1 East Coast crack average $12.79 a barrel over the quarter. But as I mentioned earlier the margin environment was negatively impacted in March due to a narrowing of the August sour crude index versus the Brent market price. The gross margin for our East Coast system averaged $5.14 a barrel. Margins throughout our system were also negatively impacted by approximately $10 million in higher than forecasted RIN’s cost. While we did not achieve the results we expected during the first quarter we continue to believe in our strategy of sourcing lower cost feedstocks for our system by procuring additional volumes of North American crude, those like domestic and Canadian heavy. During the first quarter we delivered approximately 17,000 barrels a day of Canadian heavy crude and 38,000 barrels a day of light sweet crude to Delaware City by rail. We started up the new 70,000 barrels per day double-loop facility at Delaware in early February and are now delivering volumes in excess of 70,000 barrels a day of Bakken to the refinery. We project second quarter deliveries of Bakken will double to more than 80,000 barrels a day and increase further to a 100,000 barrels a day by year end. On the heavy side deliveries will jump by 40% from 17,000 to 24,000 barrels a day in the second quarter and by another 9,000 barrels a day in the third quarter to 33,000 barrels day. The fourth quarter will continue to grow as we receive additional heavy crude rail cars and we expect to reach our desired capacity of 80,000 barrels a day by the end of the first quarter of 2014. Finally, facilities to transship Bakken crude from Delaware City to our Paulsboro refinery are now essentially in place and we expect to begin moving this crude to Paulsboro by barge at the end of May. Now, I would like to turn the call over to our Executive Chairman Tom O'Malley.

Thank you very much. Obviously I am not happy with the first quarter results. My unhappiness stems from factors that we can at least clearly identify. Toledo’s crack repair was both unexpected and expensive to say the least. But we were pleased that there were no injuries and minimal environmental impact. Toledo has been a very reliable refinery and we understand how important it is to our company. The plant is running well and we believe it will contribute in a substantial way for the balance of the year. The LIFO charts in the first quarter $65 million will probably be reversed in the month of April. While we can’t predict oil prices it looks to me that they are going to stabilize over the next few months around $100 Brent plus or minus a couple of dollars, and $90 WPI, again plus or minus a couple of dollars. Thus we wouldn’t be surprised if the $60 million recapture carries from April through the quarter. These level crude prices combined with full usage of our rail facilities and heavy rail car delivery as per the outline that Tom Nimbley gave you, should lead to much improved result on the East Coast starting in the second quarter. I want to spend a couple of minutes on RIN, because I think there is some misunderstanding as to how this crazy program functions and what is going to happen in terms of passing on the cost of the RIN’s program which the opinion is perhaps different than that expressed by our government. RINs or Renewable Identification Numbers have been an important subject in the refining space over the past few months. Our RINs requirement for the year is about 400 million individual RINs assuming the scheduled production numbers for transportation fuels that we have. We, at PBF, basically control the blending of about 50% of our first half 2013 requirement for RINs. And thus the cost of these RINs, that’s one-half, was to a great degree built into oil product prices. The balance of our transportation fuels was sold in bulk to other blenders, including importantly Morgan Stanley. And they, plus the bio fuel producers, we assume, pass on the cost to the public. I should comment here for educational purposes I suppose, that last year the differential between RBOB gasoline in New York and ethanol in New York, [inaudible] prices, was about $0.60 a gallon. That is ethanol was under RBOB. The differential year-to-date between those two numbers is $0.33 which would seem to imply that the ethanol producer is collecting part of that RIN’s value. And interestingly on May the 1st, and, you know, kind of a May Day thing, government running industries, the ethanol price is the same as the RBOB price, which would seem to indicate that the ethanol producer has now captured a very significant portion of the RIN’s price. But more succinctly the subsidization of the Food for Fuel Program continues as ever was. On July 1, 2013, our current arrangement with Morgan Stanley expires, and over the following six months we expect to increase the blending operation that we carry out to about 75% of our output of transportation fuels. We believe that that percentage is well above the refining industry average. We’ve also entered into the export market from our east coast system and intent to further reduce our RINs exposure using that avenue. As mentioned earlier, the company had an extra cost of $10 million over our budget of about $15 million in the first quarter, and we are probably going to have a similar impact in the second quarter. We do expect to lower that impact as we move forward into the second half of the year. Just another comment on it. We are not different than anybody else. RINs are an industry cost center. And from my view point a hidden tax on the public. Every manufacturer, and in this case we call the manufacturer a refiner, must pass on major costs. If we have 400 million units priced around today’s market, in fact slightly below today’s market of $0.70 per RIN, and that can either go to the ethanol producer or the blender, but really where it goes to is the public. Then that would equal $280 million a year in costs. Now, this exceeds our combined cost of electricity and natural gas which in our case for the three refineries would be about $155 million and interestingly it’s also greater than the salary, wages, and benefits of all three refineries of $220 million. So, again, I would ask the question how do you stay in business if you don’t pass this along. Clearly, a very rapid rise of enterprising in the first quarter. First, our company and I suppose others to absorb a part of this hidden tax. Surprise is over, and like every other manufacturing cost it must be passed on. I should spend a moment on the question of MLP which we mentioned in last quarter call. PBF has significant assets, would qualify for MLP treatment. This includes rail, marine, and truck terminals as well as pipeline in assets. As announced earlier, our board has authorized us to explore establishing an MLP for our logistic assets. The company continues to move forward on this important strategic alternative. Just summarizing, the first quarter was messy and disappointing. I believe the results going forward will be substantially better. We’ll now take your questions. Operator?

[Operator Instructions] The first question comes from the line of Evan Calio representing Morgan Stanley. Please proceed. Evan Calio – Morgan Stanley: Good afternoon. And thanks for the tutorial on RINs that’s helpful. My first question is on crude rail transportation. Can you guys discussed the cost impact of running a 50,000 barrels a day in the quarter where I know you are averaging closer to 100 in the next quarter, and how that might lower your land and rail cost on a per barrel basis, just trying to get that fixed cost element.

Evan, thanks for the question. Obviously we are basically – if we are looking at light domestic crude, we have an all in transportation cost of about $12 a barrel. We have deals that we have cut with some providers, we announced one recently that were effectively buying some of these crudes on a fixed differential, so Brent on a landed basis. The $12 a barrel was a real quote. But the way we look at the value of Bakken or Canadian or for that matter, any crude that we are contemplating bringing into our system of course is a relative value basis for the crudes that you are backing out and we obviously use the linear program to do that. And in the case of let’s just speak about Bakken. If we can get up to 80,000 barrels a day of Bakken on the margin, in fact the entire 80,000 barrels a day, because of the quality of the crude landing in with a $12 transportation cost will effectively give us an additional margin boost of $4 a barrel over the crudes that are being backed out, West African crudes, North Sea crudes that we are bringing in today will be backed out when we land in the Bakken. So $12 a barrel for the transportation cost but more importantly as we look at it in our system and what our LP is telling us, an improvement in gross margin of $4 a barrel. Evan Calio – Morgan Stanley: That’s great. But do you also see an increased margin benefit for higher utilization of your existing facility quarter to quarter?

Yeah, obviously that will be a function of the overall crack, you know, we are saying we are bringing in up to 80,000 barrels a day of Bakken, and if the crack we are back out more expensive crudes, less valuable crudes. If indeed we can go up further because the overall market has improved then we would see what you are suggesting. But the overall utilization would go up, it might be still bringing in some imported water borne crudes.

Yeah, I would Evan, just stick with the – the truth is fairly simple. The extra 50,000 barrels a day in the second quarter should on our model improve results by that $4 and it’s pretty simple calculation that you have got a couple hundred thousand dollars extra.

Evan, were you asking economies of scale on the rail? Evan Calio – Morgan Stanley: Yes.

Yeah. There will be some economy of scale. What we would absolutely say it is evident, the power of this dual loop facility that we have become kind of a destination of choice. Because when you look at it to your question, a producer, the railroad, and ourselves is trying to move the barrels, as many barrels as they possibly can. With our facility we are able to get two turns a month, so there will be a slight decrease as you ramp up the volume because your release course are being amortized over a greater volume. The rails will actually see us a beneficial destination, because they get mileage charge and they are going around faster and of course the producer is selling more oil. So there is an impact if we go from 55 to 80 with a slightly lower cost as we amortize those barrels at 80,000 barrels a day. Evan Calio – Morgan Stanley: That’s great. I have a second question also on East Coast profitability from the other side. Can you discuss to Brent spreads in the quarter? So in other words wider relative to historical, you know, if you are seeing some of that tighten up for cargoes that you will see in this quarter?

Evan, let me take that one. I really think kind of the Brent spread if we were to look at it on a quarterly basis we had a decline over the past months of $9 to $10 on average in Brent TI. And we’ve seen certainly some compression in – and we expect some compression in also sweet crude. I prefer not to say whether they are African or North Sea or coming from, say, North Africa. But as you get less demand for imported sweet crude in the United States, I think you are going to see a decline in the dips in essence where you have something like Forcados trading $4 or $5 over Brent or Bonny Light trading $3, in fact I suspect that you are going to see some of this imported sweet crude under real pressure. So the depths should come in. I hope that answers your question. Evan Calio – Morgan Stanley: It does, I appreciate it. Just one last one Tom. I know you mentioned differentials, have compressed and were actually seeing some seasonal effect of turnarounds. You mentioned government policy. But, has anything changed in your positive outlook for your assets going forward? And I’ll leave it at that, thanks.

No, it hasn’t. From my perspective, clearly, Toledo, you know, I comment sometimes, we got run over by the luck wagon, maybe it wasn’t brilliance in purchasing. But, anyhow, we bought Toledo at a very favorable number and the cracks in the Mid-Continent look very good, they are better than they were doing in the first quarter. Little high differential for some of the sweet crudes we bring there, but the refinery is running well and we look at that and obviously a terrific asset. On the East Coast our strategy has really been based on maturing this rail system, we have it in place, of course we were hesitant to buy on a colossal scale during the first quarter. We wanted to make sure it worked. We have absolutely no trouble discharging at the Delaware City refinery Bakken Crude. I believe the facility there can easily take a 100,000 barrels a day, that’s our light facility. On the heavy side the facility we have in place now can do 40,000 barrels a day. The second facility we are building will double that capacity by the start to mid fourth quarter this year. And the rail cars that we have on order will allow us to take advantage of those facilities. Just to give you and the other listeners a sense of what the rail cars mean, when we take delivery of these new cars and we are buying most of them, the cost of a new car is about $1000 a month. If you went out to lease cars today, unfortunately we do lease some cars today, you are paying somewhere between $2500 and $4000 a month, a car. Think of these cars as transporting 800 to 900 barrels a month and you get some sense of where we go as we take delivery of these cars. Your previous question with regards to the cost, that’s where the cost improvement will take place. And of course the margin, every time we bring in another barrel of Canadian heavy crude, we make enormous progress with regard to reducing our raw material cost. So that’s the game I don’t see that the game has changed, I think the East Coast is going to be a solid earner for the company on a long term basis the East Coast is after all the most product short portion of the United States.

Your next question comes from the line of Ed Westlake representing Credit Suisse. Please proceed. Edward G. Westlake – Credit Suisse Securities LLC: Hey I mean I got just on the cost itself $109 million of EBITDA, you are flagging the 80 at Toledo and probably we would have tried to put something for that, 10 for RIN, so you would probably catch growth, the short fall versus your sort of hopes for this year, anything else we should be aware of?

I don’t think so. You know the refineries, leaving aside the issue out in Toledo ran well. We do move them up and down a little bit depending on the margins that we see. But, I think the case is intact. We have strong hopes that the East Coast would be a substantial contributor to our EBITDA. Obviously Toledo has been, and I believe will be. I think there is no other magic there. We did get hit on the RINs, hard to put in exact number, we tried to put the most conservative number on there and not overstated at the $10 million level. And we certainly will have some damage this quarter on RINs. But then we start to in essence become the blender, and when you are the blender you do tend to do better, you get some portion I believe of it automatically. I think once you are the blender there is very little cost attached to us in essence. The ethanol producer is getting the lion share of this whole thing and that hidden tax and/or subsidy, whatever you want to call it, is passed on to the American public. Actually if the public could get simple understanding of this I think it has a similar result to the – result that we just had with regard to air traffic controllers. The numbers are staggering it’s billions and billions of dollars this year on the gasoline price which in essence again is a subsidy to the farmers. Let’s convert all the food to fuel that way we can drive and starve to death while we are driving. Edward G. Westlake – Credit Suisse Securities LLC: And yeah, I guess I should speak to the Wall Street Journal more aggressively, just…

I think you should. Edward G. Westlake – Credit Suisse Securities LLC: Just on the spreads though. I mean so you get the Bakken crude comes in and that gives you a $4 up but that’s helpful numbers. I mean obviously Maya is now $3 below Brent and Mars [ph] has pulled back a bit. But it feels like at least there is sort of some – we know these are sort of abnormal conditions. But it feels like the cokers will be suboptimal in the second quarter, is that a fair reflection.

I was going to answer that Tom. Yeah, I think it’s certainly causing economics a challenge with these narrower depths, there is no doubt about that. To answer your questions specifically we looked at Maya and we did run a little bit Maya. We are not running any Maya. You cannot purchase Maya at these differentials and coke and make any money. So without the 480,000 barrels a day of heavy Canadian crude we are actually running more M100 to balance the WCS that we have today. And frankly, landed in at the numbers where landed in M100 we are losing a little bit of money on the cokers. The WCS that we are bringing in even at today’s prices with the transportation cost, landing it into the refinery we actually make a little bit of money on WCS at $26 under Brent. So, but net it’s about a breakeven proposition right now the cokers. Edward G. Westlake – Credit Suisse Securities LLC: And then I mean the key is really I guess to get some pure bitumen. I mean any update in terms of being able to accesses that in terms of timing not just the WCS.

I think you are looking really at the second half of the year. We won’t be bringing that in. Until that time we certainly need our own real cars in that regard. We have things really programmed for the second quarter, I am hopeful that we start that program in the third quarter. Again, the issue frankly is not so much with us. The issue is in Canada and the loading facilities available to bring that material down. Edward G. Westlake – Credit Suisse Securities LLC: Okay. Very helpful thanks very much guys.

Your next question comes from the line of Roger Reed representing Wells Fargo. Please proceed. Roger Reed – Wells Fargo: Thanks good afternoon. I guess the question I would have is kind of hitting again on Q1 here along the East Coast, and it may be a little more in-depth on the rail side. Talks about efficiency as you get more barrels through obviously you get a better deal against your fixed cost. But I was wondering, were you able to deliver all in unit trains in Q1 what came in or are we looking at some manifest deliveries and so there is some additional improvements you know our ability to get closer to that $12 barrel all in number.

Yeah, let me answer that. Most of the Bakken that came in, came in on unit train situation. The Canadian really was manifest deliveries and the $12 number is Bakken you should look at the improvement there, really kind of looking at that $4 don’t look for a huge improvement in efficiencies whether we run 40,000 barrels a day through that rail system or 80,000, in essence is probably $0.50 a barrel that comes to us from running that higher rate through that particular rail facility. But the big difference is simply the substitution of the crude itself. With regard to the Canadian heavy we are now set up and in the process of arranging unit train movements of Canadian heavy. The Canadian right now if you took an all in cost you would probably be looking north of $17, because we are using some expensive leased cars, we are doing manifest loading and delivery, and so from that perspective it’s a fairly inefficient operation. As we look forward in the process we see $2 to $2.5 maybe $3 a barrel reduction in that cost, so that your Canadian cost coming in to the refinery will be somewhere down in the $14 range. And that is a very competitive range for us. And even in today’s differentials we would have a terrific return. So we make money on the Canadian we bring in today. Looking forward and I would tell you that you are working towards the end of the second quarter for that uptick on the Canadian side but really in the third quarter, because there in the third quarter we bump our throughput rate on Canadian heavy, hopefully up close to 40,000 barrels a day, we will be a bit under that. And in that period of time we should be starting to take unit trains in and there will be our trains. One of the very important things here is that the new cars that we are delivering have slightly higher capacity, incredibly better insulation than the older cars that have been used, and certainly a much better steaming system. So it allow us to discharge those cars faster and the whole unit train operation where we might today get one turn on a car in a month we expect without too much difficulty to get one and a half turns on a car. You know, there is money involved. You know, you are suddenly lower your costs again. So I think the Canadian side look to the third quarter for some real improvement. Roger Reed – Wells Fargo: Okay that’s helpful thanks. On the LIFO charge of $65 million, can you just enlighten us where that was recorded where it flowed through?

Yeah we do books on LIFO accounting. So it’s in our gross margin. We have just under 15 million barrels in our system. And when prices go up over the course of a quarter you are going to have LIFO expense, because you are expensing the more expensive barrels over the quarter. And conversely when prices go down over a quarter you have the opposite effect. The income as it relates to what would be FIFO earnings. So it’s in our gross margin, and as I said the full LIFO charge in the quarter was $65 million. Roger Reed – Wells Fargo: And was that predominantly East Coast or spread among the two.

Almost split entirely in half. Roger Reed – Wells Fargo: Okay. All right, thanks. And then….

Some of the Canadian barrels got a lot more expensive in second half of the year. So it’s almost split exactly in half. Roger Reed – Wells Fargo: And then the last question. I think this is for you Tom, as you think about the RINs issue and you have been around in this sector longer than probably most of it. What do you expect is the most likely solution? Does this have to go into ’14, become a crisis situation and then be dealt with, or is there is any optimism for something occurring in ’13?

I was the part of the delegation from AFPM our trade association and the API which went to Washington under their auspices. Represented about 85% of the US refining industry we met with representatives in their house and senate including the Chairpersons of the important committees we deal with, we met with the acting head of the EPA Bob Perciasepe, and we met with the relevant people at the White House. With regard to the House of Representatives I believe there is a reasonable chance, in fact a strong chance that legislation will be passed prior to the august recess reflecting some adjustments in the renewable fuels standards to somehow comply them with reality. With regard to the United States Senate I am not optimistic at all with regard to the EPA and it would be within their power to adjust things. They were given that authority by congress. They will not act without the sponsorship of the White House as best I can figure out. And with regard to the White House visit, it really is a lovely house and it’s right [inaudible] a lot of stuff, and they have a lot of authority, and I suspect much like the issue associated with air traffic controllers that until the public speaks out the White House won’t do anything, and the White House in essence seems to exert a very strong influence on the senate and a very strong influence on the EPA. So my rating on this thing is that, yes, we probably have to make the American public, that is we I say we, our government has to make the American public pay through the nose before anything is done. I have been going to Washington, as you say, longer than – I mean I remember Chuck O'Neil, I visited him. So I’ve been going longer than probably anybody on the call. I have never seen a government in Washington DC so at odds that the two parties really – you know, getting to the point where they won’t even look at each other not less talk to each other. So, I guess it’s going to be acquired, I hate to say it but that’s probably what’s going to happen.

Your next question comes from the line of Paul Sankey representing Deutsche Bank. Please proceed. Paul B. Sankey – Deutsche Bank Securities, Inc.: Hi guys good afternoon. Sobering stuff there Tom, the heavy and light spread is still very important to you. Could you talk about your perspective on that right now? That seems to have narrowed a lot and you know, I just wonder why – go ahead.

I think the narrowing of the light-heavy spread is temporary phenomenon. We are seeing already a widening of that number. I don’t pay much attention. I think we as a company made a bad move during the first quarter. We bought three cargos of Maya. And on the last two it was suffering and, you know, I had to whip out to try and punish those evil people that bought the stuff. But that’s become a little bit of an artificial number. As I see it coking and economics drives the game depending on who you are and what kind of coking situation you run. You are doing somewhere between I suppose 4% and 8% of petroleum coke out of your refinery. Petroleum coke in essence if you are very lucky sells for the equivalent of $5 a barrel. So if you are buying the crude at $85 or $90 a barrel you are losing a lot of money on it. And so what you do is you spare the coke, and I can tell you that over at our Paulsboro refinery we spare the coker and I could tell you at our Delaware City Refinery, to the degree we can run more light and spare the coker we will – and it almost has the automatic issue of, gee, now there is more heavy crude. I can also tell you and I think you can check this statistically that I believe the import of Saudi crudes for the first time dropped to 11 million barrels a day, and that was because I think a lot of people have said, sorry, we can’t take the crude at this type of pricing. I mean I can tell you from my perspective we are in business to make money, we are not in business to sit there and suffer. Unfortunately in our business there is always a lag, and we had that lag we are in much better shape right now. Paul B. Sankey – Deutsche Bank Securities, Inc.: Did you listen to the comments of Mr. Laney [inaudible].

I am not noted for holding back. Paul B. Sankey – Deutsche Bank Securities, Inc.: I just wondered what you thought of the latest [inaudible] Saudi policy regarding oil in the US and it seem there was…

Well, for the benefit of those that are on the call who aren’t aware of it, Saudi Aramco had a board of directors meeting in Houston, Texas, about a week ago, and at that event of course the oil minister is always privileged to get some commentary with regards to crude pricing. I thought the most important commentary and it has been a very consistent commentary in my history with the Saudi Arabian oil ministry and government, they view the United States as a key market and they want to supply to United States – there were very, very clear comments that it’s a long term relationship and they don’t intend to have it alter. So I take them as their word and, you know, I let them speak for themselves. But, it is my view that on a long term basis they have always been competitive in our market place and they got uncompetitive in the first quarter. Paul B. Sankey – Deutsche Bank Securities, Inc.: Yeah, thank you for that. Tom, in the past you said that with your experience that we’ve referenced, you never thought would be doing what we are doing with trains. I wondered what’s your perspective on the pipes and anything you want to add on keystone would be interesting. But also on the stills, and the stills of Billbaer [ph] which seems to be particularly nasty stuff. I guess ultimately that may benefit your strategy.

Well, I think with regards to the movement of light crude, both from the Southwest, obviously moving crude oil by ship out of Corpus Christi to Canada would seem to indicate that there is a surplus building uptown there and we would go up to the parking. If I recall my guide just told me that in the last month they are up 40,000 barrels a day and there really is no pipe at the present time to deal with that issue in the next couple of years. So I think we are going to see steady movement to sweet crude by rail. With regards to Canadian heavy crude obviously part of the equation revolves around Imperial/Exxon’s new production which is coming on stream now and it is my understanding that the Exxon Corporation has ordered one hell of a lot of heavy rail cars. So my guess is they are playing on a long term perspective, they don’t do anything short term. And XL, my guess on XL it is very hard for me to imagine that it can continue to be rejected. But I am not starting to think it continue to be rejected as long as the current administration is in place. With regard to Dilbit [ph], you know, I wouldn’t want to say that Dilbit is worse than anything else. I don’t believe that. I think much like any new activity the industry has to gear up to handle everything in a very safe and secure manner. We’ve done it in Delaware, frankly we don’t have any problems handing this stuff in Delaware without serious spills. Because we built the facilities that can cope with that, and I think you are going to see that the facilities are being upgraded across the area. I think the issue being able to like regimen is an economic driving force, not from the point of view of an oil spill, but [inaudible]. It allows us to bring material through the US East Coast, but we can easily handle on the US East Coast without – and at a very nice price differential. Because if somebody doesn’t have to put whatever went in, and we can take the material, we are going to have a huge margin. That's a great real item, and I think it’s going to be something that looms large for us, but I would hesitate to say, it’s going to add greatly to our profitability this year. I think you have to look at that a little bit more as a forward issue and we indeed are involved in building facilities or at least financing facilities in Canada to make that possible. Paul B. Sankey – Deutsche Bank Securities, Inc.: Okay. Very quickly one last one. You are kind of getting sucked downstream. From your point of view, your M&A strategies, still [inaudible] but you consider going at the terminals [inaudible] by gas station.

Yeah. Well we are already in terminal so to speak. We do lease terminal space in the Mid-Continent area on a rather substantial basis. We of course have a big rack at our own facility in Delaware which has been drastically under used. As a result I think a great degree of our arrangement with Morgan Stanley and we intend to have much more use out of that facility. And we are going out and leasing some space. We will probably take some steps in the New England area. I don’t know about the New York Harbor, a very expensive place and we don’t have a competitive advantage there, and of course we are expanding rack usage which is run by New Star in Paulsboro. So, yeah, we are going to be primarily a refiner, but we will definitely be expanding our presence in the terminal area which I find attractive because it’s very good MLP stuff. Operator next question.

Your next question comes from the line Robert Keffer representing Suvor Piccari [ph].

Hello gentlemen. I wanted to see if I could get better understanding of your Bakken crude processes. You referenced I think a fixed spread to Brent. And I wanted to see if we could clarify how much of Bakken are you buying on a fixed spread basis and say for what length of time. And is that fixed spread equal to or greater than that $12 a barrel transport cost you referenced. And I guess related to that you mentioned $4 barrel uplift, how much of that $4 barrel uplift is let’s call it a yield based improvement in the economics and how much of that is embedded extra transportation margin if that make sense.

Again, let me grab that, I hate to have a monologue here. But this is the area that I have made my career in. So I’ll talk about the issue in crude buying. We have longer term arrangements, we recently announced one where we are buying Bakken crude, Bakken crude is the purchase at the market. And, the market for Bakken is to a great degree being set by, I would say, Brent economics. Okay? It’s being set by rail economics. Bakken must move by rail, you can’t get the stuff out of there – I think we are moving – I mean we must be up at around 500,000 barrels a day by rail. So, we buy it sometimes on a WTI basis, and sometimes on a Brent basis. If we buy it on a TI basis, because our product sales are effectively coming off Brent pricing then we hedge it, in essence we put on a Brent TI hedge, so we convert that purchase to a Brent base purchase. And that’s our standard operating procedure. And what’s our goal and objective. Well, our goal and objective is to land the Bakken in our refinery at a discount to Brent. And, you know, we’ve succeeded in some case to land it at more than $3 a barrel discount to Brent, in other cases at around $2. The average that we are hoping for is a bit over $2 and that’s not a terribly optimistic projection because our cost to move the crude from Bakken to be discharged in our refinery is on average a little bit more than $2 less than our East Coast competitors. And the reason is very simple. The train comes into our refinery. The train doesn’t come in today way – it doesn’t come in to train – I don’t think at the present time it comes into Philadelphia Energy in a big way. And these refineries are unfortunately burdened with taking the crude into a third party terminal, and the real freight and car usage whether they are coming to Albany or down in Norfolk, Virginia or some other facility, you know, it goes through another two box to finally get them in the refinery. Again better lucky than smart, we were lucky when we bought the Delaware City refinery that it came with a large quantity of cornfields, soybean fields and in essence a surplus of about 4500 acres of land, and it was level. So we were able to put this thing. I think that answers your question.

Yeah, thanks. I think it’s very clear in terms of seeking to achieving that discount relative to Brent on a per barrel basis. At the same time, is the yield structure better on a Bakken barrel.

It depends on what you are looking at in a margin. Let me give you an example. Is the yield structure better on Bakken than West African Forcados. Today’s spreads, the answer to that would be no, just on a net basis Forcados would actually have maybe a dollar value, X the cost of landing in N. Just on a product side, dollar a barrel higher yield pattern, because it produces a lot additionally. At the same time it will cause significantly more – to land Forcados into an east coast refinery, $3, $4 a barrel, maybe north of that given the spreads between Forcados and Brent and then [inaudible] will be priced because you got to land it in. So when you come down, so maybe on – and in the absolute just the yield side you could get a crude like Forcados that is actually better than Bakken, you could also get a crude that is a push or lower. But when you adjust it for the fact that we are landing Bakken in at a significant discount to what the alternative crudes that we or Philadelphia or anybody who is running a west African crude the gross or the net margin impact of running these crudes is significant.

Yeah, just to add to that. Because I think it will enhance the answer a bit. This is a better crude than Forties, this is a better crude than Brent. It’s probably better yield than Saharan Blend. Maybe it’s about the same as Bunny Light from Nigeria or Qua Iboe from Nigeria. It’s better when we talk about them, they are FOB and this is delivered in our plant, well, then to deliver it in our plant is really the big issue. So, you know, every barrel of that stuff that we can back out it’s the happy moment for us.

Very clear, thank you for that. Last one from me if I could. On steering coke report, if you do delve back on your coke reutilization, is that to say you would replace the barrels with the lighter barrel, or would you actually reduce your throughput into the refinery in that scenario.

We might do both. You know, we do move – we’ve got a blessing over at our refinery in Paulsboro, and again I think this is something that anybody who is still on the call might want to think about for the moment. We don’t generally pave roads in the North East in January, February and March. We pave them during the paving season, which is beginning right now. And we are one of the biggest asphalt producers on the East Coast, and when we asphalt we really spare the coke. So we take that heavy end of the barrel which we might have been gaining, let’s say $5 or $6 a barrel, you know, the equivalent and we make asphalt and it now might be $80 or $85 a barrel, now we can’t do it for everything, but we can do it for quite a lot. So, one of the other uplifts one should look at with an East Coast Asphalt operation is that, yeah, we are switching over to asphalt mode and that’s a very profitable move.

I would add one other comment. Tom is spot on Paulsboro, that’s exactly what we are doing today making asphalt and using coke. On Delaware if we execute the plan that we talked about effectively 50-50, it’s Bakken and WCS. The Coke will be approaching Delaware at minimum rate, simply because there is very little residue in the Bakken. So, you effectively – and again that’s being driven by economics. So, we don’t necessarily have to cut the rates, we’ll actually be cutting the coke just because we are modifying the slate.

Your next question comes from the line Faisel Khan for Citigroup. Please proceed. Mohit Bhardwaj – Citigroup: I would like to congratulate you for taking the lead on RIN’s disclosure. My question is actually related to exports from the East Coast, and I was wondering if you could give us some guideline as to what level of exports and what you are aiming for in terms of the total capacity for exports?

Well, our exports really fall into two categories. We probably won’t be exporting gasoline. But we have exported some components and I think Tom can comment on that. The other thing that we’ve started to export is middle distillate. And, we moved out during the first quarter, if I recall correctly about 1.8 million barrels that would be – I guess often the 20,000 barrel a day category. We are less competitive than the gulf coast on moving light products to central and South America, I think that’s a little bit more economic move for your Gulf coast refineries. But certainly we are competitive in the middle distillate area. And I think you will see us on a fairly consistent basis moving out 20,000 to 25,000 barrels a day from the east coast and that would be weighted to the middle distillate pool. Tom, you may want to comment further.

Yeah, I would. On gasoline, Tom is right, we don’t export finished gasoline. Obviously pad one is an important market. But very often. However, we have a situation because of the capability of the Delaware City refinery. Delaware City actually produces a heavy rafame [ph] stream which has an Octane of 109. We will not see an Octane stream of that level in very many refineries in the United States. And because of that it is a premium product that we have routinely exported to South American or to other places because of the blending capability that you see and if we can’t sell it in the harbor, which usually we can’t because we produce so much of it, we export that material to capture the value in other parts of the world. Mohit Bhardwaj – Citigroup Global Markets Inc.: Thank you for that. The final one on the midstream MLP. You guys have given guidance close to $100 million in EBITDA. So if you could just update on that number and also provide a little timeline that will be great.

Well, with regard to updating on the number I don’t think there is really any update on the number. I think we haven’t done anything that would add to that number in a significant way. With regard to the timing that of course is something that will be up to the board of directors. They are anxious to realize the value for the share holders. On the other side of the coin these things are relatively complex from a property ownership point of view, separating the actual physical facilities in a way that, you know, really makes them independent. One of the very big income streams that has MLP value is the fleet of heavy rail cars, I shouldn’t say heavy rail cars, I should say rail cars capable of carrying heavy crude and the facilities associated with that at the discharge point, and perhaps also at the loading point. And that last caveat would be some addition to that $100 million number, there is nothing we can talk about today. I certainly don’t think that you are going to see substantive progress. From your point of view that is we actually announced we are doing something or we filed something in the second quarter but I would be surprised if indeed during the second quarter we hadn’t gotten our docks, I am sorry during the third quarter our docks aligned up and ready to swim forward and now exactly when and if we would launch an MLP is something that I can tell you my own feeling is instead of ready fire aim which use to be in some of my earlier military days. Ready-aim-fire is better thing, we are getting ready we should have those thing aimed in third quarter and I would expect to fire thereafter. Mohit Bhardwaj – Citigroup Global Markets Inc.: Thank you for your comments.

You have time for one final question. That question will come from the line of Cory Garcia representing Raymond James, please proceed. Cory Garcia – Raymond James: Good afternoon fellows and very much appreciate the color on specifically on crude by rail related cost advantages. One quick question I has on the marketing side of things and thinking about you fuel supply strategy going forward is there a target level for volumes are on percentage basis maybe. Now you guys have looked to enter into the sort of fix margins supply agreements with the producers themselves.

No. I think that’s not really the way the industry functions. Even though we are investigating on average twice a year by some member of congress thinking that there is some collusion – I’ve been in many other industries I have never seen an industry as competitive as this one. And nobody likes to allow the other guy anything fixed, everybody is trying to beat the other guy’s brains out. So we are you know we are in it. We think we have a good place. We understand we’ve got to pay the market for our raw materials principally crude oil, and we have to sell at the market, principally current expectation fuels to that market place. What I can say to you is we are trying to morph from an approximate 50% what I would call blender distributor as opposed to bulk supplier of oil products to a higher level of blended distributor as opposed to bulk, I would like to see us take that up to 75%of our total availability. And then if I can add on top of that some reasonable level of exploits, 5% to 8% I am in that bulk market which is frankly the worst market to be in. You know that’s going to be the least profitable place to place our barrels. We do want however longer-term relationship with our suppliers. We have one with the Saudis, we recently announce one with folks out in the Bakken, we have more coming in the future but they are all market related, they are not fix priced. I mean I’d love to find somebody to sell me something where they guarantees me I can make $5 a barrel or $10 a barrel, but I have yet to discover that person. Cory Garcia – Raymond James: Absolutely I appreciate the color.

I would now like to turn the call over to Tom O'Malley for closing remarks.

We would like to thank everybody for attending we are working really hard to do a better a job than we did in the first quarter and we better do a better job, so on that note I wish everybody a great day. Take care.

Thank you for your participation in today’s conference, this concludes the presentation. You may now disconnect.