PBF Energy Inc (PBF) 2013 Q1 法說會逐字稿

Good day, ladies and gentlemen and welcome to the first-quarter 2013 PBF Energy Incorporated earnings conference call. My name is Shaquana and I will be your coordinator for today. At this time all participants are in a listen only mode. We will facilitate a question-and-answer session towards the end of this conference.

(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, are Tom O'Malley, our Executive Chairman, and Tom Nimbley, our CEO. We also have a couple 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 our website www.pbfenergy.com. Also, attached to the earnings release are tables that provide additional financial and operating information on our business.

One housekeeping item, there was a minor typo, maybe was wishful 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 be North Dakota rail facility and in the release it said Trenton, New Jersey rail facility. It might have been wishful thinking if they start producing Bakken, New Jersey will be as well-positioned as anybody. It should be Trenton, North Dakota. 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 that statements in the press release and on this conference call that state the Company's or Managements 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 opening 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 that 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 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 $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 $122.6 million, or negative $1.26 per share for the first quarter 2012.

Finally, our adjusted EBITDA for Q1 was $109 million versus a loss of $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 that FCC complex in Toledo. We calculate the unplanned down time at Toledo negatively impacted EBITDA by more than $80 million. The unit was down for 18 days but importantly, feedstock and product inventory affects ran longer.

The rising cost of compliance with Renewable Fuel Standards was the second item. RINs 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 have 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 shortfall of the first quarter include the high flat price accrued which prevailed over the first quarter had a punitive effect on the gross margin for low value products such as coke, sulfur and LPGs. We experienced slightly narrowed crude differentials.

There was weak lube crack over the first quarter. Lube demand is usually seasonally weak in the winter months. And as previously mentioned, we experienced higher costs of RINs. Importantly, so far in the second quarter we have seen a 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 RINs, we budgeted approximately $60 million for the entire year. Based on current market prices, we would expect to spend approximately $120 million on ethanol RINs and about $40 million for the balance of the requirement for 2013. We expect to recoup a significant portion of the cost of the RINs in higher prices for transportation fuels because we believe that markets will adjust to a higher embedded cost of the RINs in transportation fuels.

For the first quarter of 2013, G&A expenses were $30 million compared to $14 million during last year's first quarter. The increase in '13 relates primarily to increased headcount and personnel costs 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, it D&A expense was $27 million, again compared to $21 million for the year ago quarter. The increase is mostly due to amortization expense related to the first-quarter 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 a quarterly dividend of $0.30 a 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 the earnings power of PBF and our continuing commitment to returning cash to shareholders.

For modeling our second-quarter operations, we expect the refinery throughput volumes to fall within the following ranges. The Mid-continent should average 150,000 to 160,000 barrels a day and the East Coast should average between 320,000 and 330,000 barrels a day. Our run rate 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'm 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 shut down 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 a day. The East Coast ran well, although we did reduce throughput on East Coast somewhat during March due to poor margins associated with narrowing crude differentials. Operating cost on a system wide basis averaged $5.19 a barrel. The East Coast was slightly higher than forecast at $4.89 a barrel due to higher natural gas prices, while Toledo's costs were again negatively impacted by the outage and average sales of $0.97 over the quarter.

The refining margin environment was strongly impaired due during the quarter with the 4-3-1 crack spread averaging over $26 barrel, resulting in the $19.50 per barrel gross margin that was achieved at Toledo in the first quarter. The Brent 2-1-1 East Coast crack averaged $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 RINs cost.

While we did not achieve results we expected during the first quarter, we continue to believe in our strategy of sourcing lower cost speed stocks for our system by procuring additional volumes of North American crude, both 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 barrel per day dual lube 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 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 per day. The fourth quarter will continue to grow as we receive additional heavy coiled railcars 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 tranship Bakken crude from Delaware City to our Paulsboro refinery are now essentially in place and we expect begin moving this crude to Paulsboro by barge at the end of May.

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

Thank you very much. Obviously I'm not happy with the first-quarter results. But my unhappiness stems from fact that we can at least clearly identify Toledo's cat cracker fire 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 charge in the first quarter of $65 million will probably be reversed in the month of April. While we cannot predict oil prices, it looks to me that they're going to stabilize over the next few months around $100 Brent, plus or minus $2, and $90 WTI, again, plus or minus $2. Thus, we would not be surprised if the $60 million recapture carries from April through the quarter. These lower crude prices, combined with full usage of our rail facilities and heavy railcar delivery, per the outline that Tom Nimbley gave you, should lead to a much improved result on the East Coast starting in the second quarter.

I want to spend a couple minutes on RINs because I think that there is some misunderstanding as to how this crazy program functions and what is going to happen in terms of passing on the costs of the RINs program, which 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 50%, 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 biofuel 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 (both our) 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 RINs value. And interestingly, on May 1 and kind of the Mayday 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 RINs price. Put more succinctly, the subsidization of the food for fuels 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 have also entered into the export market from our East Coast system and intend 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. We are probably going to have a similar impact in the second quarter. We do expect to lower than 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 viewpoint, the 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 RINs 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. This exceeds our combined costs of electricity and natural gas which, in our case for the three refineries, would be about $155 million and interestingly, it is also greater than the salary, wages and benefits of all three refineries of $220 million.

So again, I would ask the question that how do you stay in business if you don't pass this along? Clearly, a very rapid rise of RINs pricing in the first quarter forced our Company and I suppose others to absorb a part of this hidden tax. The surprise is over and like every other manufacturing cost, it must be passed on.

I should spend a moment on the question of the MLP which we mentioned in last quarter's call. PBF has significant assets that would qualify for MLP treatment. These include rail, green and truck terminals, as well as pipeline 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 will now take your questions. Operator?

Thank you. (Operator Instructions)

Evan Calio, Morgan Stanley

Afternoon guys and, Tom, thanks for the tutorial on RINS. That's helpful. My first question is on crude rail transportation. Can you guys discuss the cost impact of running at 50,000 barrels a day in the quarter where I know you are going to be averaging closer to 100 this next quarter? And how that might lower your land of rail costs on a per barrel basis? Just trying to get to a fixed cost element.

Yes, Evan, thanks for the question. Obviously, we have basically if we're 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 we're effectively buying some of these crudes on fixed differentials of rent on a landed basis. The $12 a barrel is a real cost. 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 of relative value basis to 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 to speak to 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 at $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 on our system and what our LP is telling us, an improvement in gross margin of $4 a barrel.

That's great. But do you also see an increased margin benefit from higher utilization of your existing facility quarter to quarter?

Yes. Obviously, that'll be a function of the overall crack. We're saying we are bringing in up to 80,000 barrels a day of Bakken and if we back out more expensive, less valuable crudes. If indeed we can go further because the overall market is improved then we would see what you are suggesting. But the overall utilization would go up. It might be still be bringing in some imported waterborne crudes.

Yes, I would just stick with the -- to keep it 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 a pretty simple calculation that you've got a couple of hundred thousand dollars extra a day.

Is that make sense. Evan were you asking economies of scale on the rail?

That also, yes.

There will be some economy of scale. What we would absolutely say, it is evident that the power of this dual lube 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 lease costs are being amortized over a greater volume. The rails will actually see this as a beneficial destination because they get mileage charge and they're going run 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.

That's great. Second question also on East Coast profitability. From the other side, can you discuss the African to Brent spreads in the quarter? I know that they were wider relative to historical, and if you're 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 have seen certainly some compression and we expect some compression in the offshore sweet crudes. I'd prefer not to say whether they're African on 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're going to see a decline in the dips in essence, where you have something like a [porcota] that is trading $4 or $5 over Brent or Bonny Light trading $3. In fact, I suspect that you're going to see some of this imported sweet crude under real pressure. So the dips should come in. I hope that answers your question.

It does. I appreciate it. Just maybe one last one, Tom. You mentioned the differentials that have compressed and cracks are seeing some seasonal affect of turnarounds. You mentioned government policy but has anything changed in your positive outlook for your assets going forward? I'll leave it at that, thanks.

No, it has not. From my perspective, clearly Toledo, I comment sometimes that 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're better than they were during in the first quarter. A little higher differential for some of the sweet crudes that we are bringing there but the refinery is running well and we look at that, obviously, as a terrific asked 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. But, we have absolutely no trouble discharging at the Delaware city refinery. Bakken crude, I believe the facility there can easily take 100,000 barrels a day, that is our light facility. And on the heavy side, the facility we have in place now can do 40,000 barrels a day and the second facility we are building will double that capacity by the start to mid-fourth quarter this year and the railcars 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 railcars mean, when we take delivery of these new cars that we are buying most of them, the cost of a new car is about $1,000 a month. If you went out to lease cars today, and unfortunately we do lease some cars today, you are paying somewhere between $2,500 and $4000 a month a car. Think of these cars as transporting 800 and 900 barrels a month and you get some sense of where we go as we take delivery of these cars. Your previous question with regard to the cost, that is where the big 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 is 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. So on to the next questions.

Ed Westlake, Credit Suisse.

Hi, just on the quarter itself, $109 million of EBITDA, you are flagging the 80 at Toledo and probably we would have tried to put some in for that, 10 for RIN. So you probably categorize the rest of the shortfall versus your sort of hopes for this year as crude dips? Or anything else we should be aware of?

I don't think so. The refinery, 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 in intact. We have strong hopes that the East Coast will be a substantial contributor to our EBITDA. Obviously, Toledo has been and I believe will be. So, there is no other magic there.

We did get hit on the RINS. Hard to put an exact number. We tried to put the most conservative number on there and not overstate it 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 a 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 almost very little cost attached to us in essence.

The ethanol producer is getting the lion's 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 a simple understanding of this, I think you would have a similar revolt to the revolt that we just had with regard to air traffic controllers. The numbers are staggering. It is 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're driving.

Yes, I should speak to the Wall Street Journal more aggressively.

I think you should.

Just on the spreads though, you get the Bakken crude comes in and that gives you a $4 uplift, that's helpful numbers. Obviously, Myer is now $3 below Brent and Miles has pulled back a little bit. But it feels like at least, and these are sort of -- we know these are set 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. I think certainly the coking economics are challenged with these narrower disks. There's no doubt about that. To answer your question specifically, we look at Myer and we did run a little bit of Myer, we're not running any Myer. You cannot purchase Myer at these differentials and coke it and make any money. So without the full 80,000 barrels a day of heavy Canadian crude, we are actually running more M100 to balance the barrels of WCS that we have today. And frankly, landed in at the numbers we're landing in M100 we're losing a little bit of money on the cokers. The WCS that we are bringing in, even with today's prices with the transportation costs, landing it into the refinery, actually make a little bit of money on the WCS at $26 under Brent. So net-net it is about a breakeven proposition right now on the cokers.

Then the key is really to get some pure bitumen. Any updates in terms of being able to access 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 railcars in that regard. We have things really programmed for the second quarter. I'm 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.

Okay. Very helpful. Thanks very much guys.

Roger Read, Wells Fargo.

Thanks. Good afternoon. The question I would have is kind of hitting again on Q1 here along the East Coast and maybe a little more in-depth on the rail side. You talked about efficiencies. You get more barrels through, obviously you get a better deal against your fixed costs. But I was wondering, were you able to deliver all in unit trains the Q1 what came in? Or, were we looking at some manifest deliveries and so there's some additional improvement and ability to get closer to that $12 barrel all in number for the rest of the year?

Let me answer that. Most of that 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 systems or 80,000. In essence, it 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 is a fairly inefficient operation. As we look forward in the process, we see to $2 to $2.50, maybe $3 a barrel reduction in that cost. So that your Canadian costs coming into 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 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 allows 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 1.5 turns on a car. And there is money involved. You're suddenly lowering your costs again. So I think the Canadian side looked to the third quarter for some real improvement.

Okay that's helpful, thanks. On the LIFO charge of the $65 million, can you just enlighten us where that was recorded, where it flowed through?

Matt?

Yes, we do our books on LIFO accounting so it is 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 will have the opposite effect and you will have the income as it relates to what would be the FIFO earnings. So it is in our gross margin and as I said, the full LIFO charge in the quarter was $65 million.

And was that predominately East Coast or spread among the two?

It was split, almost split entirely in half.

Okay. All right, thanks.

Some of the Canadian barrels got a lot more expensive in the second half of the year. So, it is almost split exactly in half.

Okay thanks. And then last question, I would think this is for you, Tom. As you think about the RINS issue and you have been around in the sector longer than probably most of us. 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 any optimism for something occurring in '13?

I was part of a delegation from the AFPM, our trade association, and the API, which went to Washington under their auspices. It represented about 85% of the US refining industry. We met with representatives in the 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 adjustment in the renewable fuels standards to somehow comply them with reality. With regard to the United States Senate, I'm 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 regards to the White House visit, it really is a lovely house. And it's very big and all of that 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 reading of this thing is that yes we probably have to make the American public, that is when 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 remember Tip O'Neill. 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 are getting to the point where they won't even look at each other, no less talk to each other. So there's going to be a crisis. I hate to say it, but that's probably what is going to happen.

Thank you.

Paul Sankey, Deutsche Bank

Hello, guys. Good afternoon. Sobering stuff there, Tom. The heavy light spread is still very important to you. Could you talk about your perspective on that right now, Tom? It seems to have narrowed a lot and I'm just wondering why.

Well I think the narrowing of the light heavy spread is a temporary phenomenon. We have seen already a widening of that number. I don't pay much attention to MIA. I think that we, we as a company, made a bad move during the first quarter. We bought three cargoes of MIA and on the last two, it was suffering and I had to whip out to try and punish those evil people that bought the stuff. But, that has become a little bit of an artificial number.

As I see it, coking economics drives the game, depending on who you are and what kind of coking situation you run. You're 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 coker. And I can tell you that over at our Paulsboro refinery we spare the coker. And I can tell you at our Delaware City refinery, to the degree we can run more light and spare the coker, we well. And it almost has the automatic issue of gee whiz, now there's more heavy crude.

I can also tell you and I think you can check this statistically, that I believe the import of [snorty] crudes for the first time dropped below a million barrels a day. And that was because I think a lot of people have said, sorry we cannot take the crude at this type of pricing. 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 have that lag and we are in much better shape right now.

Did you elicit some comments on the [EMEA] the last couple of days?

I'm not noted for holding back.

I just wondered what you thought of the latest pronouncements on Saudi policy regarding oil in the US?

Well for the benefit of those on the call who are unaware 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 give some commentary with regard 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 the United States. There were very clear comments that it's a long-term relationship and they don't intend to have it falter. So I take them at their word and 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.

Yes, thank you for that. Tom, in the past you have said that with your experience that we have referenced, you would have thought we'd be doing what we are doing with trains. I wonder what is your perspective on the pipes? Anything you want to add, obviously on keystone, would be interesting, but also on the spills and this spills of dilbit which seems to be particularly nasty stuff. Ultimately that may benefit your strategy?

Well, I think with regard 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 up down there. And with regard to the Bakken, if I recall my guy 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're going to see steady movement of suite crude by rail.

With regard to Canadian heavy crude, obviously part of the equation revolves around Imperial stroke 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 railcars. So my guess is that they are planning on a long-term perspective. They don't do anything short-term. And Xcel, my guess on Xcel it is very hard for me to imagine that it can continue to be rejected, but I'm now starting to think that it can continue to be rejected as long as the current administration is in place.

With regard to dilbit, I would not want to say that dilbit is worse than anything else. I don't believe that. I think that much like any new activity, the industry has to gear up to handle everything in a very safe and secure manner. We have done it in Delaware. Frankly, we don't have any problems handling 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 take bitumen is an economic driving force. Not from the point of view of an oil spill, but gee whiz, it allows us to bring material through the US East Coast that we can easily handle on the US East Coast without and at a very nice price differential. Because, if somebody does not have to put the dilbit in and we can take the neat material, we are going to have a huge margin advantage. That is a great rail item and I think it's going to be something that looms large for us but I would hesitate to say it is going to add greatly to our profitability this year. I think you have to look at that a little more as a forward issue and we indeed are involved in building facilities or least financing facilities in Canada to make that possible.

Okay. Very quick last one. Your kind of getting sucked downstream by this RINS thing. From the point of view of your M&A strategy, still focused on merchant refining, would you consider going into terminals, would you buy gas stations? I'll leave it there. Thanks.

Well we are already in terminals 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 facility in Delaware, which has been drastically under used as a result, I think to 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 more 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. But, of course, we are expanding the rack usage which is run by Newstar in Paulsboro. 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 is very good MLP stuff. Operator next question?

Thank you.

Robert Kessler, Tudor, Pickering.

Hello, gentlemen. Wanted to see if I could get a better understanding of your Bakken crude purchases. You referenced, I think, a fixed spread to Brent. And I wanted to see if we could clarify how much of your 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 related to that, you mentioned this $4 a barrel uplift. How much of that $4 a barrel uplift is a, let's call it a yield based improvement in the economics? And how much of that is an embedded extra transportation margin, if that makes sense?

Well, again let me grab that. I hate to have a monologue here, but this is an area that I have made my career in so I will talk about the issue of crude buying. We have longer-term arrangements. We recently announced one where we are buying Bakken crude. But Bakken crude is a purchase at the market. And the market for Bakken is to a great degree being set by, I would say, Brent economics. It is being set by rail economics. Bakken must move by rail. You cannot get the stuff out of there. I think we are moving -- 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 of Brent pricing, then we hedge it. In essence, we put on a Brent TI hedge so that we convert that purchase to a Brent-based purchase. That is our standard operating procedure. And what is our goal and objective? Our goal and objective is to land the Bakken in our refinery at a discount to Brent. And, we have succeeded in some cases 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 is not a terribly optimistic projection because our cost to move the crude from Bakken to 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 does not come into Bayway, it does not come into Trainer. 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 in through third-party terminal. And the rail freight and car usage, whether they're coming through Albany or down in Norfolk, Virginia or some other facility, it costs them another $2 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 corn fields, soybean fields and in essence a surplus of about 450,000 acres of land and most of it was level so we were able to put this in. I think that answers your questions.

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

Yes. There -- I will let Tom answer. He is a better chemical engineer.

It depends on what you are looking at in the margin. Let me give you an example. Is the yield structure better on Bakken than West African [percatos]? At today's spreads, the answer to that would be no. Just on a net basis, percatos would actually have maybe $1 value X the cost of landing it in. Just on a product side, $1 a barrel higher yield pattern because it produces a lot of distillate.

At the same time, it will cost significantly more to land percatos into an East Coast refinery, $3, $4 a barrel. Maybe North of that given the spreads between percatos and Brent and then their FOB prices you got to land it in. So when you come down -- maybe on the absolute just the yield side, you can get crude percatos that is actually better than Bakken. You could also get a crude that is a partial lower. But when adjust it for the fact that we are landing Bakken in at a significant discount to what the alternative crudes are 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. Yes, just to add to that, because I think it will enhance the answer a bit. This is a better crude than 40s. This is a better crude than Brent. It is probably a better yield than Saharan blend. Maybe it is about the same as Bonny Light from Nigeria or quibo from Nigeria. But those were -- it's better when we talk about them. Their FOB and this is delivered in our plant, then it is delivered in our plant is really the big issue. So every barrel of that stuff that we can back out is just a happy moment for us.

Very clear, thank you for that. Last quick one for me if I could. On sparing the coker point, if you do delve back your coker utilization, is that to say you would replace the barrels with the lighter barrel? Or, would actually reduce your throughput into the refinery in that scenario?

We might do both. We do move. We got up blessing over at our refinery in Paulsboro. Again, I think that this is something that anybody is still on the call might want to think about for the moment. We don't generally pave roads in the Northeast 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 produce asphalt, we really spare the coker. So, we take that heavy end of the barrel, which we might have been gaining, let's say $5 or $6 a barrel crude equivalent, and we make asphalt and it now might be at $80 or $85 a barrel. We cannot 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 we are switching coking over to asphalt mode and that is a very profitable move.

I would add one other comment. This is Tom Nimbley. Tom is spot on, on Paulsboro. That's exactly what we are doing today, making asphalt and reducing coking. On Delaware, if we execute the plan that we talked about and it is effectively a 50-50 mix of the Bakken and the WCS, the coker will get be approaching at Delaware minimum rates simply because there's very little residual 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 coker just because we are modifying the slate.

Thank you very much.

Faisel Khan, Citigroup

Hello. This is actually [Mohad Baradavagen] for Faisel Khan. I would like to congratulate you on taking the lead on the RINS disclosure. My question is actually relates 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 total capacity for exports?

Well, our exports really fall into two categories. We probably won't be exporting straight gasoline. But, we have exported some components and I think Tom can comment on that. The other thing that we have 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 up in the 20,000 barrel a day category. We're less competitive than the Gulf Coast on moving light products to Central and South America. I think that is 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.

Yes, I would. On gasoline, Tom is right, we don't export finished gasoline. Obviously Pad one is an import market very often. However, we have a situation because of the capability of the Delaware City refinery. Delaware city actually produces a reformate stream, heave reformate stream which has an octane of 109. You 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 America or to other places because of the blending capability that the receivers see. And, if we cannot sell it straight into 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.

Thank you for that. And the final one on the midstream MLP. You guys have given guidance of close to $100 million in EBITDA. If you could just update on that number, and also provide a little timeline. That would be great.

Well with regard to updating the number, I don't think there's really any update on the number. I think we have not 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 shareholders. On the other side of the coin, these things are relatively complex from property ownership point of view of separating the actual physical facilities in a way that really makes them independent. One of the very big income streams that has MLP value is the fleet of heavy railcars. I should not say heavy railcars, I should say railcars capable of carrying heavy crude. And the facility associated with that at the discharge point then perhaps also at the loading point and that last caveat would be some addition to that $100 million number but there's nothing that 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. I would be surprised if indeed during the second quarter we hadn't not gotten our ducks -- I'm sorry, during the third quarter, our ducks lined up and ready to swim forward. Now, exactly when and if we would launch an MLP is something that I cannot tell you. My own feeling is that instead of ready, fire, aim, which used to be in some of my earlier military days, it would be ready, aim, fire is a better thing. We are getting ready, we should have this thing aimed in the third quarter and I would expect to fire thereafter.

Thank you for your comments.

Cory Garcia, Raymond James.

Good afternoon and very much appreciate the color specific on the crude by rail laid in cost advantages. One quick question I have is more on the marketing side of things and thinking about your supply strategy going forward. Is there a target level for volumes or on a percentage basis maybe that you guys would look to enter into these fixed margin supply agreements with the producers themselves?

No. I think that is not really the way the industry functions. Even though we are investigated on average twice a year by some member of Congress thinking that there is some collusion, I have 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 guys brains out. So we are in it, we think we have a good place. We understand that we have got to pay the market for our raw materials, principally crude oil, and we have to sell at the market, principally transportation fuels to the marketplace.

What I can say to you is that we are trying to morph from an approximate 50%, what I would call, blender distributor as opposed to both 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 could add on top of that, some reasonable level of exports, 5% to 8%, in that boat market which is frankly the worst market to be in. That is going to be the worst profitable place to place our barrels. We do want, however, longer-term relationships with our suppliers. We have one with the Saudi's. We recently announced one with the folks out in the Bakken. We have more coming in the future but they are all market related. They are not fixed price. I would love to find somebody to sell me something where it guarantees me I could make $5 a barrel or $10 a barrel but I've yet to discover this person.

Absolutely, I appreciate the color.

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

We would like to thank everybody for attending. We're working really hard to do a better job than we did in the first quarter and we had 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 and have a great day.