PBF Energy's CEO Discusses Q4 2012 Results - Earnings Call Transcript

Feb.21.13 | About: PBF Energy (PBF)

PBF Energy Inc. (NYSE:PBF)

Q4 2012 Earnings Call

February 21, 2013 10:00 am ET

Executives

Matthew C. Lucey – Senior Vice President and Chief Financial Officer

Thomas J. Nimbley – Chief Executive Officer

Thomas D. O'Malley – Executive Chairman

Analysts

Evan Calio – Morgan Stanley

Jeff A. Dietert – Simmons & Co. International

Paul B. Sankey – Deutsche Bank Securities, Inc.

Faisel H. Khan – Citigroup Global Markets Inc.

Edward G. Westlake – Credit Suisse Securities LLC

Blake Fernandez – Howard Weil Inc.

Paul Cheng – Barclays Capital, Inc.

Operator

Good day ladies and gentlemen and welcome to the Fourth Quarter 2012 PBF Energy Inc. Earning Conference Call. My name is Lisa, and I’ll be your operator for today. At this time all participants are in listen-only-mode. Later we will conduct a question-and-answer session. (Operator Instructions) As a reminder this conference is being recorded for replay purposes.

I would now like to turn the conference over to your host for today, PBF Energy’s CFO, Matt Lucey. Please proceed.

Matthew C. Lucey

Thank you. Good morning and welcome to our earnings call today. With me are Tom O'Malley, our Chairman; and Tom Nimbley, our CEO, as well as several other members of our senior management team.

If you have not received the earnings release and would like a copy, you can find one on our website pbfenergy.com. Also attached to the earnings releases are tables that provide additional financial information on our business.

Before we get stated, I’d like to direct your attention to the forward-looking statements disclaimer contained in the press release.

In summary, it says that statements in the press release and on this conference call that states the Company’s or management’s expectations or predictions of the future are forward-looking statements, intended to be covered by the Safe Harbor provisions under Federal Securities laws. There are many factors that could cause actual results to differ from our expectations, including those we described in our filings with the SEC.

As also noted in our press release, we will be using several non-GAAP measures while describing PBF’s operating performance and financial results, including adjusted pro forma net income, adjusted pro forma EPS, EBITDA earnings before interest, taxes, depreciation and amortization, 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’s important to note that we’ll 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 owned by PBF, Inc.

Also the fourth quarter and the full year 2012, it represents only 14 days of operation after our IPO. We think adjusted pro forma net income and adjusted pro forma EPS is more meaningful to you because it presents 100% of the operations of PBF Energy Company LLC on and after tax basis. And with that I’ll move on to discussing PBF’s fourth quarter and full year 2012 results.

Today we’ve reported Q4 operating income of $285 million versus operating loss of $166 million for the fourth quarter of 2011. Adjusted pro forma net income for the fourth quarter was $166 million or $1.70 per share on a fully exchange, fully diluted basis, as I have just described compared to a loss of a $112 million or $1.15 per share for the fourth quarter of 2011. For the year ended December 31, 2012, operating income was $920 million compared to $306 million for the corresponding period in 2011.

Adjusted pro forma net income for the year was $493 million or $5.7 per share on a fully exchanged, fully diluted basis, compared to $147 million or $1.51 a share for the corresponding period in 2011. As Tom Nimbley will discuss in just a minute, the increase in operating income was primarily due to higher crack spreads and stronger crude differentials across the system.

The Brent, New York Harbor 2-1-1 crack spread was up approximately $4.50 from Q4 2011 and the WTI, Chicago 4-3-1 crack was up over $7.75 from the fourth quarter last year. Our fourth quarter refining margin was $13.04 per barrel, compared to just $1.61 per barrel in the fourth quarter of 2011. The company also benefited from lower operating expenses as energy and utility costs were down.

For the fourth quarter of 2012, G&A expenses were $42 million, compared to $15 million from last year. The increase in 2012 relates to one time IPO cost and higher personnel cost. In the fourth quarter, G&A expense was $25 million in 2012 compared to $18 million last year, they increased mostly due to depreciation expenses related to the turn around of Toledo, which happened in the first quarter of 2012 and corporate charges related to the implementation of our SAP.

Fourth quarter 2012 interest expense was $22 million consistent with the fourth quarter of 2011. PBF Energy, Inc’s effective tax rate in the fourth quarter was approximately 39.5%. Finally our adjusted EBITDA for Q4 was $311 million and $1.04 billion for the full year 2011.

Regarding cash flows in the fourth quarter, capital spending was just over $85 million which includes turn around in catalyst expenditures. That brings our full year capital spending to $223 million, consistent with what we present on the IPO road show. With respect to our balance sheet at the end of December, cash was $286 million and our net debt to cap ratio was 20% which compares to 40% at the end of 2011. At the end of December 2012, we had approximately $600 million of available liquidity.

With the recently announced $50 million heave crude unloading rack expansion at Delaware, we expect our 2013 capital spending to be approximately $250 million to $275 million.

Our 2013 estimate also includes spending to complete a 45 day turnaround of the Del City coker and some smaller scope work related to the hydrocracker at Del City in the fourth quarter.

Regarding other uses of cash, we announced today that our Board of Directors have approved the dividend of $0.30 for the fourth quarter of 2012, $0.30 dividend is 50% higher and a full quarter ahead of the scheduled announce in our IPO perspectives.

The early dividend reflects not only the strong results from 2012, but also the positive outlook for PBS in 2013 is reflective of our commitment to return more cash to shareholders.

For modeling our first quarter operations, we expect the refinery throughput volumes to fall within the following ranges. The Mid-Continent should average 120,000 to 130,000 barrels per day and East Coast average should be 330,000 to 340,000 per day.

For the first quarter of 2013, our operating cost per barrel will be impacted by Toledo refinery operations. However we expect our operating cost for the year to range between $4.20 and $4.30 per barrel.

I would now like to turn the call over to Tom Nimbley, who will provide an operational overview of the company.

Thomas J. Nimbley

Thank you, Matt and good morning everybody. Our refining systems ran well in the fourth quarter with overall rates at 461,000 barrels a day and importantly no significant unplanned downtimes. The Mid-Continent ran 147,000 barrels a day and East Coast ran at 314,000 barrels a day.

Operating expenses on a system-wide basis for the fourth quarter were at $4.74 a barrel. For the year, operating cost were $4.36 a barrel with the fourth quarter being higher due to increased usage of natural gas and reduced throughputs basically because of the impacts of super storm Sandy.

Our refineries made it through Sandy in good shape physically with no major repairs and very little flooding, but we did reduced rates in anticipation of the storm and were further reduced – in rates as a result of the aftermath of the storm for some period of time.

Operating cost discipline continues to be an area of focus and we have seen the benefits of the discipline in essentially all areas of operating costs. Across our refining system, we continue to strive to drive down operating cost and provide our refineries with the most cost advantage crudes available.

In Toledo we continue to expand our crude oil truck unloading rack and discharge in excess of over 10,000 barrels a day of locally sourced crudes in Toledo during December. These crudes are displacing higher cost pipeline delivered crudes with significant margin benefits.

I might also add that we are also carefully monitoring developments in the Utica and are position ourselves to be able to discharge crude and condensates from this region by rail or truck, when they become available. The refining margin environment in both pads 1 and 2 was very strong in the fourth quarter and our refineries were able to capture the benefit of strong margins by running reliably.

The Mid-Continent continued to be advantaged by favorable crude differentials and strong product pricing with the benchmark, Chicago WTI 431 crack averaging $25.68 a barrel during the quarter. Our realized fourth quarter refining margin in the Mid-Continent was $22.71 a barrel. Our east coast refinery benefited from a strong margin environment with the benchmark New York Harbor 2-1-1 Brent crack averaging $13.61 a barrel.

Our realized margins in the fourth quarter for our East Coast system was $8.53 a barrel. The increase in refining margin was due to wider discounts on medium sour, heavy sour and domestic white crude oil. For example, comparing the fourth quarter of 2011 to the fourth quarter of 2012, the Brent August sour crude index discount, which impacts a lot of the crude oils that we source into the East Coast improved by over $1.50 a barrel and the Brent TI discount improved by over $6 a barrel.

I want to highlight something about the performance of our East Coast refining system in 2012. Our East Coast system on a cash basis was profitable not only for the fourth quarter, but for the entire year. This is in spite of having had a bad, truly bad or poor first half of the year were the East Coast was money and importantly does not include any of the benefits from the crude by rail investments that we have and are continuing to make.

We believe that our East Coast system has turned the corner, showing its profitability in 2012 on a cash basis especially in the fourth quarter. In 2013, we expect this to continue as we continue to benefit from improved coking economics and would be significant increase in volumes accrued by rail that we expect to source into Delaware.

Before speaking about our crude by rail asset, I would like to touch briefly on the incident we had at our Toledo refinery on January 31 of this year. We experienced a drop in steam pressure, which caused a series of events ultimately leading to a small fire and the shutdown of the cat cracker in Toledo.

As a result of this shutdown, we reduced rates at the refineries other processing units as well. The team at Toledo was quickly able to assess the damage and implement a plan to restore the refinery to planned operations. As of last Monday, February 18, the refinery is essentially back to running at planned rates. The total duration of the outage was approximately 18 days.

Moving on to our East Coast rail system; as announced, two weeks ago, we have completed the dual-loop track light crude unloading facility at our Delaware City refinery and we now have the capability to unload 70,000 barrels a day of Bakken crude oil in addition to having the capacity to unload the 40,000 barrels a day of heavy crude oil, primarily WCS, which has already been installed.

Today, we announced that our Board has approved the project with 40,000 barrels a day additional heavy crude discharge capability at Delaware City. We expect this project to cost about $50 million and to be complete by the end of the fourth quarter. We also expect to have had taken delivery of sufficient coil and insulated rail cars to allow us to source and transport the 80,000 barrels a day of heavy crudes in Canada at that time.

I should mention that based on our experience to-date with our new dual-loop facility where we have already achieved unloading rates of 70,000 barrels a day; we believe we will be able to increase the discharge capability of this rack with essentially no additional capital investment.

We expect that as we bring these cost advantages to North American crudes to our East Coast refineries that we will see our feedstocks cost continue to decrease with subsequent improvements in our overall margins. We intend to run 100% of the heavy crude by rail barrels at Delaware and split the light barrels between Delaware and Paulsboro.

We believe our efforts to bring in these cost advantage crudes will result in a significant competitive advantage relative to our other pad 1 refiners, as we have the only refining capacity in the region with a sophisticated coking and self-handling ability to be able to source and process the heavier high sulfur crudes.

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

Thomas D. O'Malley

Tom, thank you very much. Certainly, we enjoyed a good year but I was not happy with the 2012 results on the East Coast. We did see, as Tom said, a real turn around in the second half of the year and frankly all the profitability on the East Coast was in the second half of the year. The availability of domestic and Canadian crudes at much better differentials through our brand markers, should lead to much better results on the East Coast in 2013 and even better than that in 2014, when our ability to take in and process Canadian heavy double.

Toledo was a great performer in 2012, and the start of 2013 leads me to believe that the Mid-Continent system will continue to be a strong earner. 2013 looks like a great year for our industry. Our belief and PBFs success is certainly evidenced by our Board’s decision to pay a dividend for the fourth quarter and in fact to pay a dividend that’s 50% higher than the dividend we indicated during our road show.

We do continue to study, maximizing our shareholder value through the disposition of all traditional, and I emphasized traditional MLP assets. Those are transportation assets, those are pipelines, so these are terminals et cetera, et cetera they do not include a refinery.

We’ll have more to save about this at the time our first quarter earnings call and on that note, we’d be happy to take questions from anybody on the call.

Question-and-Answer Session

Operator

(Operator Instruction) Your first question comes from the line of Evan Calio with Morgan Stanley. Please proceed.

Evan Calio – Morgan Stanley

Good morning guys.

Matthew C. Lucey

Good morning.

Evan Calio – Morgan Stanley

A question on the advantage crude runs, I was wondering if you could update us on what you ran in East region and maybe give us where you’re volume wise today, GI and CS and interesting on your earlier comments, Tom, are there any kind of scoping of the upside potential in a more efficient way of offloading. And I have a follow up please.

Thomas D. O'Malley

Well, your question is so long, it’s impossible to consider a follow-up. Having said that Evan, Tom why don’t you take on that question.

Thomas J. Nimbley

Okay, if I understood the question, there is two parts of it basically, what are we basically running in our systems today, breakdown of crudes and then what the prospect look for Utica and other crude by rail and particularly Toledo. Let’s start about Toledo, Toledo always continues to run effectively, completely light sleigh, it runs about 55,000 barrels a day of Canadian synthetic, the balance as I said, we’re running 15,000 to 20,000 barrels a day of locally sourced crude, some of that is by truck, other is by pipeline. And the rest of this late is WTI price barrels that come out of Toca and other parts of the Midwest.

We continue to look for opportunities and I did specifically reference the Utica because we do believe there is going to be opportunities to continue to source in lower price crudes than what we’re currently running today. How much of that will be dependent upon, obviously how things develop in the region.

The bigger changes are going to happen going forward in the East Coast. We’re already seeing some of that. We started running Bakken in East Coast in both Delaware and Paulsboro last year. We in fact advanced the turnaround on a crude unit in Delaware into 2012 and the reason we did that was to make some changes to the units who allow us to run 100%. This is the small crude unit in Delaware.

Evan Calio – Morgan Stanley

You said Delaware as opposed to Paulsboro.

Thomas J. Nimbley

I am sorry, at Paulsboro. They would allow us to run 100% Bakken on this small crude unit in Paulsboro. So we will be running as we say 150,000 barrels a day pipeline by rail effectively follow that 80 day of heavy crude, which is a combination of WCS and some bitumen. We’ll be running Delaware City, the 70 to 80 days, I said we think we are going to be able to exceed the unloading capability and we’re going to be able to source in the volumes of crude from the Bakken at good numbers. We would split that between Paulsboro and Delaware City. So for Delaware, it’s 80 of Canadian heavies, 40 or so of Bakken and the balance will be filled out by the most attractively priced waterborne crudes and 100 Maya et cetera.

In Paulsboro, we will run effectively 100% Bakken on the small unit for a good period of time. During the [asphalt] season, we will attempt, in fact we will run probably some WCS, in the summer time on that still as well. And the (inaudible) which is the larger unit at Paulsboro, we’ll continue to run 100,000 barrels a day of Arab lights.

Thomas D. O'Malley

Just I want to add to that. Tom mentioned 80,000 barrels a day of heavy crude into the Delaware City refinery. The max we’re going to be running in Delaware City in the year 2013 of Canadian heavy crude would be about 40,000 barrels a day, the new facility to discharge and perhaps more importantly the availability of rail cars under our large purchase program really puts all off that 80,000 barrels a day number into the start of 2014. You had a second part?

Evan Calio – Morgan Stanley

I do, I do, and I’ll keep it short. On the OpEx per barrel, if you could give us more color, in each of the region in Del City as I know you made significant changes to how you operate that asset and reduce the OpEx, why don’t you just update us where you were in the quarter, where you are now at Del City? I’d appreciate it.

Matthew C. Lucey

Tom?

Thomas J. Nimbley

Yes, for the actual quarter for Q2 12, the break out on a unit basis per barrel was Toledo was 467, Paulsboro is 482, Del City was 490. For the year, we were actually lower than that. We were 439 in Delaware, 409 in Paulsboro, 449 in Toledo. During the road show we talked about the fact that we were at 439 in Delaware City, we expect to be able to achieve our target of about $4 a barrel. We took a step back as I said in the fourth quarter, but that was not because of absolute cost, it was because we ran a lower device because of the throughput reductions associated with the storm.

Evan Calio – Morgan Stanley

That’s great. Well, thank you welcome back.

Operator

Your next question comes from the line of Jeff Dietert with Simmons and Company. Please proceed.

Jeff A. Dietert – Simmons & Co. International

It’s Jeff Dietrich with Simons and Company, good morning.

Matthew C. Lucey

Good morning, Jeff.

Jeff A. Dietert – Simmons & Co. International

You talked about the improvement on the East Coast in your feedstock cost relative to brand at $1.50 improvement in 4Q relative to prior year. And I believe by this point, you should have purchased most of your first quarter crudes through Jan, Feb and March. Can you talk about what type of enhancement you’re expecting or what type of delivery price relative to brand, what discount you might capture for the first quarter?

Thomas D. O'Malley

All right, this is Tom O'Malley, and I will go further with that. We are not going to disclose the exact number. You must understand in this particular case, we are running very different crudes. We expect to average during the first quarter about 50,000 barrels per day of Bakken. The unit that we put in the discharge facilities started up on April 7. It has right from the get go run at very close or slightly above the maximum desired rate. We of course did not purchase more than that rate. So the average amount in Bakken in the refinery will be about 50,000 barrels a day and the discount on that will average couple of dollars under Brent.

We ran very different crudes in the first quarter of last year. And in the fourth quarter of last year, we certainly didn’t have 50,000 barrels a day at Bakken, so that was an important element. We’re running in the first quarter, which we have not run in our ownership period of the Delaware City refinery. Maya crude oil in the first quarter, I think we’re running about 18,000 barrels a day at Maya, at the Delaware City refinery, and that crude is landing in the refinery at $89 under Brent.

Last year, at this time, the Maya differential probably would have landed in the refinery of $1 to $2 under Brent. We traditionally run a fair amount of M100, which is a material emanating out of Russia. Last year at this time the differentials on that were $1.2 under Brent or in some cases even over.

During the first quarter, Tom correct me on this I think it’s probably averaging $7 to $8. The swing in the crude price for the Delaware city refinery is really quite substantial. It's probably $5 or $6 a barrel on average better than it was in the first quarter. At the Paulsboro refinery the difference is not as great. We do run 100,000 barrels a day of Arab light through that refinery. That is arriving at a discount through Brent during the first quarter. That however prices well up an average tied to indexes on the Gulf Coast. So it is pricing as we speak. But certainly it’s going to be better than it was in the first quarter of last year. I think that answers your question.

Thomas J. Nimbley

I would add one other thing. It’s important when we take a look at the crude like Bakken, Tom, has spot on, actually the M100 differential is a little bit higher, maybe $2 higher than so far this year. But the point I was going to make is, if you take Delaware City, Delaware does run about 40,000 barrels a day of lighter crude. Sometimes we source that crude in West Africa. It can land or Hibernia comes in and that we’ll trade or land in at a premium several dollars above two Brent.

If we land in Bakken $3 or $4 under, that’s a discount in the crude cost. But the real fact is you are getting a high quality crude. So we look at things on a relative value basis. So if the crude spreads between Hibernia and Bakken, the Atlantic course difference is $3. We would actually expect to see a margin benefit greater than that, because Bakken is in fact a higher quality crude for our system.

Jeff A. Dietert – Simmons & Co. International

Thanks for that information. I had one longer term question. There are number of pipelines, keystone and in bridge trying to get from Canada to the Gulf Coast with transportation rates of $8 to $10 a barrel versus rail options of $17 to $20 a barrel, but those numbers really aren’t comparable because of the diluting required to move Canadian heavy by pipeline. Do you have any information that would help us with a more apples-to-apples comparison between pipeline and rail, it think that would…

Thomas J. Nimbley

Let me take that question. Morgan Stanley, I guess a competitor I don’t know came out with report today which I haven’t read the whole thing. Rail is a long-term operation. We have to bifurcate it obviously between sweet crude and sour crude.

In the fourth quarter, sweet crude imports to the US Gulf Coast at 5 O` clock were at or slightly under 500,000 barrels a day. Production from the Permian basin, other Mid-Continent areas over the next 12, 14, 16 months will probably back that import out. At the same moment in time, I think everybody is aware that we already have marine movement primarily Corpus Christi of Eagle Ford crudes up to the New York metropolitan area. I know PFX is taking material win, I believe the Philadelphia refinery is. But if you look at that and you look at pipeline tiers and then on the sweep side you compare it to our cost of bringing a barrel from the Bakken and some Canadian sweets over $12.5 and that is our cost. We don’t have anything beyond because we discharged at our refinery in our terminal competitive advantage.

It would seem to me that that differential leaving aside pipeline movement is going to be around for a while, exactly how long I don’t know, but if you obtain $6, $5.5 to $6 to move from Corpus Christi, up to US East Coast in today’s environment and you think pipelines Arab could get it to Corpus loading charges et cetera. Well, I think it’s only going to get worse. I think we’re going to see more and more domestic crude move by rail, that’s the sweet crude side.

On the heavy crude side we’re convinced that this is a very, very long-term trend. I suppose we have studied all the reports that you did study that everything we see shows to us the movement of Canadian heavy crude by rail particularly if we can get 30 million to the complex and we can. Then that's something that's around for the next decade. And that's how we are playing that. We in fact have ordered enough insulated and coiled railcars to carry the 80,000 barrels a day. And we are making investments and signing agreements in Canada to source that crude as we speak. So that’s a long-term perspective with regard to the pipeline movements of these crudes.

I am sure they will come although, I'm not sure that XL will get the oil price. I suppose that’s only in the mind and heart of our current president, whether that happens and his mind and heart doesn't seem to be there over the last weeks. So we’re confident very long-term on the movement of heavy Canadian crudes to the US East Coast, and the people who are selling these crudes, very large companies up there seem to have that same view since a number of them have made very, very large orders of railcars.

Jeff A. Dietert – Simmons & Co. International

Thank you very much.

Operator

Your next question comes from the line of Paul Sankey with Deutsche Bank. Please proceed.

Paul B. Sankey – Deutsche Bank Securities, Inc.

Hi, good morning everyone. Further to your statements that the rail is performing better than you had hoped or thought, could you just update on the unit costs of moving the oil from Canada and Bakken. I assume that those are low and now that you know you’re outperforming expectations?

Thomas J. Nimbley

I don't think that's exactly correct. The biggest cost of moving the oil is the real freight itself. And we have a very competitive rate, but it is not going to change much. We will get some break as the volumes grow, but it’s not going to be something that will fascinate Wall Street. I think the real big issue that is relatively new is our ability to take in about perhaps a little bit more than 80,000 barrels a day of Canadian heavy crudes.

When we where on our road show and during the presentations that we made, our indication was that we were really around that 40,000 to 45,000 barrel a day number. And we had put in place a discharge facility much more complex facility by the way then a facility could discharge Bakken. That netted 40,000 to 45,000 barrels a day.

As we ran these crudes, we started running them in the fourth quarter at relatively low rates. We realized that this terrifically complex plant that we have in Delaware City could take much more of this material. And thus we acted very quickly on putting together an enhanced project of further discharge and in fact going back in and taking another 2000 railcars. So it really goes to the crude, the enhanced profitability of the crude.

On the Bakken side, our 70,000 barrel a day discharge facility, we certainly think it can do quite a bit more. I believe it was yesterday that we took in a unit train of 100 cars that would be about 71,000 to 72,000 barrels and we discharged it in 15 hours. So do we think we have more capacity on that facility, you bet we do? And did we buy crudes in the first quarter that would allow us to run much more in the first quarter, no. We did not, but we – we’re in the market to buy a bit more in the second quarter, you bet we are because we are pretty sure that we can take that facility up to higher rate. And of course once again when we do that we at this place, higher price imported crudes and it adds to the profitability of the company.

Paul B. Sankey – Deutsche Bank Securities, Inc.

Right, could you just remind us the freight costs of the crude oil?

Thomas D. O'Malley

Look oil in, again Tom correct me, $12.5 on the Bakken, $17.5 on the Canadian heavy.

Thomas J. Nimbley

Yeah. Excuse me.

Matthew C. Lucey

As you can say, we do think at least in the near-term when we enter into some contracts with the railroads that we will see an improvement in that not material, it will come down a little bit, but those are the right numbers.

Paul B. Sankey – Deutsche Bank Securities, Inc.

I appreciate that. Thank you and then just my second follow-up would be in the past at Deutsche Bank we talked about the concept of the zombie refinery, the fact that these refineries that we thought had shut down on the East Coast may come back with the crude pricing that you're getting here and already – we see your researches and utilization in pad one.

Matthew C. Lucey

I hate to refer to anything in my industry as a zombie, but I’ll leave that up to you. Look there are three refineries that shut down on the U.S. East Coast, the last shut down was (inaudible) cracker in New Jersey, and that unit was shut down during this period of less expensive domestic crude. So I certainly don’t think that there’s a candidate to come back. The next one that we shut down was Sunoco’s Marcus Hook refinery, that refinery – I don’t think that refinery is coming back to be perfectly candid with you. We have actually bought some equipment from that refinery including very large pump recently, so that refinery is being converted as I understand it and you probably get more information from the current owners to that facility that deals with some liquids coming out of Marcellus, so you know that refinery has another years, Eagle Point no way in my opinion that was closed down, I guess about three or four years ago, so those refineries won’t be back.

I think more importantly from the point of view of our Atlantic Basin perspective the two Caribbean refineries (inaudible) are down really for whole series of complex reasons, but of course one of the biggest points is they don't have access to cheap natural gas, they're producing power by burning fuel oil, which is an impossible situation, and the configuration is wrong. You're not going to see them back. But then going to a place that I am familiar with, sadly familiar I must say going to Western Europe, the combination of the very strong Euro, the very, very high price of natural gas, the higher personnel operating costs, and the non-availability of the types of crude oil that we’re getting here in North America has changed the calculation, if you go back five years, six years certainly, Western Europe was a competitive, and delivering a lot of product to the United States. What this market in the United States is gradually close to Western European refineries because of the tremendous competitive advantage that U.S. refineries have in terms of inexpensive natural gas in terms of cheaper crude and feed stocks into the refinery. So it really is a sea change and it’s a sea change that no one in the industry probably predicted, by the way no one on Wall Street probably predicted.

Paul B. Sankey – Deutsche Bank Securities, Inc.

Okay. We call it the diamond edge. Tom, yeah sure thanks very much for your complete answer. Thank you.

Operator

Your next question comes from the line of Faisel Khan with Citigroup. Please proceed.

Faisel H. Khan – Citigroup Global Markets Inc.

Thanks, good morning. I just have one question. You mentioned that your 431 was to your realized crack spread in the Toledo refineries, about $22 or $23 a barrel, which looks to be roughly a 90% capture rate versus your marker. Can you just give us an idea of, it looks like, if I look back in the past and previous quarters, the capture rate was much lower. I think it was an idea of how you’re able to capture such a high component of the indicator margin?

Matthew C. Lucey

Tom, will you take that?

Thomas J. Nimbley

Yeah, I will. Thank you. One of the things you have to look at and I’ll leave it to you to do, because I don’t have the numbers right in front of me. Remember that is versus a benchmark 431 TI crack. We typically said that you should look at Toledo as having its landed crude costs in on average at about two dollars premium to TI. But as you know, there is volatility in that. So you’d have to look at, what I would suggest you to look at one component would be what was the actual TI cost in the fourth quarter that may have been a contributor to the stronger crackers, even though we had the high cost in December, we were advantaged in part of that quarter. The other thing that I will tell you in Toledo indisputably is we are benefiting from very; very robust chemicals market right now, stronger than what we’ve seen in past quarters, benzene pricing is $200 a barrel or was strengthened across the fourth quarter. And even though it’s not that much in terms of its overall margin volume rather, 5% a barrel as you would start to see it, $10, $20, $30 increase in margin for those volumes and add in. The other thing that I know also was a factor in the fourth quarter relative to previous again, you have to look it quarter by quarter as we had a very strong jet market as well.

Faisel H. Khan – Citigroup Global Markets Inc.

Okay, thanks. So if I am looking at the capture rate in the fourth quarter, how does that compare to the previous three quarters for last year?

Matthew C. Lucey

I don't have those numbers in front of me. Faisel, we can get that for you and get it back to you.

Faisel H. Khan – Citigroup Global Markets Inc.

Sure, okay. Thanks for the time. I appreciate it.

Operator

Your next question comes from the line of Edward Westlake with Credit Suisse. Please proceed.

Edward G. Westlake – Credit Suisse Securities LLC

Hi good morning everyone. I hope you can hear me.

Thomas J. Nimbley

We can.

Edward G. Westlake – Credit Suisse Securities LLC

Great. So the first question is still sticking on the rail. Just in terms of any refining restrictions at Del City, how much actual pure bitumen not WCS that you splendid with diligence, but pure bitumen do you think you can run at Del City longer term?

Matthew C. Lucey

Tom, want to take that?

Thomas J. Nimbley

Yeah, it is going to be a range Ed, as you well know. We can run probably, the short answer is we are confident that we can run 40,000 barrels a day of pure bitumen. We probably get around a little bit more than that, but then we have to back out, more than one barrel of WCS or heavy crude in order to accommodate it.

So the limitations in Delaware are going to be two. One is, the fluid coke capacity itself and the second is the capacity of the vacuum portion of the crude unit. We can run and when we say we're going to run 100,000 barrels a day or 120,000 barrels a day of heavy crude that would be combination of Canadian, Maya and 100 or some waterborne crudes. We could run 40 a day of bitumen and 80 of everything else if we wanted to run more bitumen, we would probably have to decrease the total volume of heavy. Did that help you?

Edward G. Westlake – Credit Suisse Securities LLC

Yeah, that's very, very helpful. And then switching to a broader question, obviously you have been very successful with rail to the East Coast. You'd mentioned a little bit about Utica, as you think about growing perhaps the more stable logistics parts of business to serve the refineries, maybe are there any investments that you’re considering or looking at some perhaps the process Utica and if you can give us a scale of any capital and why I have to go into those investments? I appreciate it may still be better?

Thomas J. Nimbley

I think that’s very early days to respond to that question, Utica right now is a big question mark. I think the industry is convinced that there’s oil there, they certainly condensate in a substantial way, we can take in some amount of condensate without any significant investment over at our refinery.

I think what we have demonstrated is that we are willing to step up to the plate, and put in place our infrastructure investments in terms of moving material by rail or by truck and we are looking particularly at Toledo at all the possibilities and we are kind of actively engaged in the marketplace.

I think if you saw a number come out at some point in the future in terms of infrastructure investments in Toledo, you’d be looking in the $10 million, $20 million, $30 million, $40 million category, not in the $100 million, $200 million, $300 million category. We are very active right now in the Bakken and loading facilities given the flora facilities out there it was to lease rather than invest any money. We are very active up in Canada, we’re working with really all of the principal players up there to develop the possibility to lower taken in the issue up there as and clear it for the most part comes shown into the general rail loading area with any majority into it and the facilities right now don’t exist to take that out, so it’s an area where really we have our own track around it. As soon as we have something concrete, you can be absolutely sure we will announce it, but there is now huge capital expenditure coming down the trail other than what we’ve already announced.

Edward G. Westlake – Credit Suisse Securities LLC

And then just on the – obviously, we are all waiting hoping for some segmental splits, say maybe East Coast and Midcon, as you close out the year, I mean would you be able to give a rough percentage contribution from Toledo that was say EBITDA before SG&A or something like that?

Thomas J. Nimbley

Why don’t I shift that question over Matt Lucey. It’s a caveat that when he gives you the number for last year, you could should understand that the percentage and we want him to give a percentage is for the whole year, but the true reality is the first day of the year on East-Coast was not a positive and whatever the East Coast earned in the second half of the year and therefore its ongoing percentage contributions should be much higher than the average for the year. Matt, why don’t you take the question?

Matthew C. Lucey

Thanks Tom. To answer directly, the full year EBITDA contribution from the East Coast was roughly 13%. We intend going forward as we’re in 2013 to the East Coast and the Mid-Cont separately, so you’ll be able to see the performance of both the East Coast and Mid-Cont up until this point with Del City in startup mode, it would have caused more confusion than created answer, but so for the full year 2012 Del City, Paulsboro were roughly 13% of EBITDA for the year.

Thomas J. Nimbley

Yeah, I know so just adding to what Matt said as you should assume that in the second half of the year, the contribution percentage was to target contribution came and certainly have, well tier and I am certainly not going to be comfortable with the number going forward from the East Coast of 12% or 13% or 20% or anything like that.

I think the East Coast is set up to become a very substantial contributor and an opinion one can only have an opinion this is more of because up and down, I believe that the year 2013 in the Mid-Continent will be a very prosperous year, It’s certainly starting off that way and all indications are that results in the quarter of our industry in the Mid-Continent will be very good and now we have that kind of second leg in East Coast with this terrific rail infrastructure that we put in place. We see these scales just being significant contributor to the company’s results.

Matthew C. Lucey

And Tom, just for the fourth quarter, we were over 30% contribution from the East Coast, speaking directly of the fourth quarter. So you see the improvement and it should continue.

Edward G. Westlake – Credit Suisse Securities LLC

That was my follow-on. Thanks, I will cede the floor. I feel I have asked a lot of questions already. Thank you.

Operator

Your next question comes from the line of with Blake Fernandez with Howard Weil. Please proceed.

Blake Fernandez – Howard Weil Inc.

Good morning guys. Thanks for taking the question. You have already somewhat addressed the dynamics of the East Coast with regard to closures and then some of the inefficiencies in Europe, but I was hoping maybe you could address the changing export opportunities you may see and then maybe also in the capacity limitations you may have over there with regard to increasing that into the future?

Thomas J. Nimbley

Well, look obviously the giant export market is the U.S. Gulf Coat. The U.S. (inaudible) is efficient to an amazing degree and its ability to produce sound products. I don’t know what the latest statistics are, but my guess would be we produce on the East Coast and the few remaining refineries, 25% to 30% to what East Coast consumes.

So we are going to be less of an export driven market. What we see there is that the imports which used to come out of the Caribbean, SunCor, on a very regular basis was sending oil up to us. Venezuela was sending gas linked cargos and how they seem to import them. Western Europe has a lot of time. So our local demand is very strong.

We will see times during the year when the arm opens on middle distillate and we do move middle distillate out of either products, move out, but the pressure and I think that’s what for the analytical community should focus on. Pressure used to come to product pricing in the Mid Continent and the U.S. East Coast from the surplus production on the U.S. Gulf Coast, that surplus on the U.S. Gulf Coast is now moving out into export markets. And so the pressure in the Mid Continent that you would see coming at various times during the year on the East Coast where the guys stand on the Gulf couldn’t try in another home and they would be pushing more of colonial in the market, one that it’s not there as frequently.

So our market, which you would expect to maintain the colonial pipeline premium, so colonial might or may not it’s $0.05 a gallon to get it up into the Northeast, the Delaware and New York Harbor area probably traded on average over the past couple of years, the U.S. East Coast to $0.03 over the Gulf Coast. I expect that differential to widen. So that advantage that East Coast has in essence reflects more colonial pipeline there.

Europe, it is just very hard for them to compete now their costs are just that much higher, so that’s – we will export from the East Coast, but I think the East Coast will probably absorb the vast majority of what we produce up there.

Blake Fernandez – Howard Weil Inc.

Right, great, okay. Well, thanks for the answers. Secondly, just a question on MLP, I just wanted to confirm the wording in the press release was a little bit confusing to me, I just wanted to confirm you are still in the evaluation process, and then secondly I just wanted to confirm I think previously you had talked about roughly $100 million of EBITDA MLP of assets, I didn’t know if that changed at all with the increased rail capacity? Thanks.

Matthew C. Lucey

Well, I think first of all, we are – my colleague, Mike Gayda, the Company’s President is waiting the effort. It’s obviously something that requires significant preparation. Our Board of Directors instructed us to seriously consider that, and it really points at how can we enhance shareholder value. Certainly an MLP or in essence the sale of two MLP assets to third party has the potential to enhance the value of our shares, so we are pursuing it.

With regard to the $100 million, I think it is fair to say that the additional assets that we are looking at raises that number somewhat. I don’t want to quantify it, but it’s certainly – it’s not another $100 million, but it’s certainly more than $10 million, so. . .

Thomas J. Nimbley

Yes it’s creeping up, and since we are looking at other infrastructure things the potential for even more is there, so it’s something that you will here more about from us, when we have our first quarter earnings call, I think we’ll be far enough for long at that point to give better direction, better information to the market place.

Blake Fernandez – Howard Weil Inc.

That’s great, thank you very much.

Operator

Your next question comes from the line of Paul Cheng with Barclays Capital. Please proceed.

Paul Cheng – Barclays Capital, Inc.

Hey guys good morning.

Thomas J. Nimbley

Good morning, Paul.

Matthew C. Lucey

Good morning, Paul.

Paul Cheng – Barclays Capital, Inc.

Matt the first one that, when you are saying that going forward you are going to putout a data, I presume you were also not just giving that EBITDA but unit margin, unit costs and should we assume that in your 10-K, you will start to have those information that go for the year or there is nothing in the first quarter report?

Matthew C. Lucey

It can be going forward, Paul and in terms of specifically, what we are doing we’re evaluating our best presentation as we speak, but it will break out enough information so you can see the financial performance in pad one and in pad two.

Paul Cheng – Barclays Capital, Inc.

Okay.

Thomas J. Nimbley

I do want so Paul look, to get the most out of the East Coast assessment, we really have to look at these two refineries as yes, it’s hard so say as one, but they are about 20 miles apart, and barge movement is really pretty easy, and the combination of equipment they have is extraordinary, and it was never taken advantage of before, and we are starting to take advantage of it, and it’s real money, and so I’m going to be very hesitant to say break the East Coast down further than the East Coast. So as long as you get, breakdown the East Coast from the Mid-Continent.

Paul Cheng – Barclays Capital, Inc.

Yeah, that’s fine. And on the East Coast, since they’re 20 miles apart, is there any possibility that you can build some pipeline connect them and wind them as a virtual as a one we really one entity, or that we need not piece of a…

Matthew C. Lucey

I would only talk about that, that it’s difficult to build the pipeline through Nebraska.

Paul Cheng – Barclays Capital, Inc.

Okay.

Matthew C. Lucey

Where the buffalo roam, it’s something like that.

Paul Cheng – Barclays Capital, Inc.

Yeah, that’s right.

Matthew C. Lucey

I think getting pipelines between Del City and Paulsboro, and your mouth to God’s hear, we would love to do it, but I think if we guided the market to the expectation, that that was going to happen, we’d be setting ourselves up for an incredibly diverse shareholder lawsuits.

Paul Cheng – Barclays Capital, Inc.

Understand, Tom on the 2013 CapEx $250 million to $275 million, is that including turnaround.

Thomas J. Nimbley

Yes it does.

Paul Cheng – Barclays Capital, Inc.

Okay.

Thomas J. Nimbley

We have one as Matt alluded to it, but the biggest turnaround components that we have in 2013 is going to be in the fourth quarter. that would be the Fluid Coker at Delaware City and when we shut down that Fluid Coker, which is about every 30 months basically

Paul Cheng – Barclays Capital, Inc.

Sure

Thomas J. Nimbley

Ride out the coke, we also shut down hydrocracker in this case, it will just be to change out the catalyst.

The other major turnaround although, it’s about half the size, less than half the size of Delaware City is on the big [crude] unit in Paulsboro, which will also be in the fourth quarter, and collectively that’s somewhere between $16 million, $17 million is the total, about $16 million is the total turnaround CapEx, but that is included in the sustaining CapEx that and the numbers that Matt you gave you.

Paul Cheng – Barclays Capital, Inc.

And also that I mean Tom, when we are looking at that, you have $50 million this year related to the well expansion, so should we assume on the sustainable going forward basis your system, the all four required CapEx is probably in the $200 million to $225 million a year?

Thomas J. Nimbley

Yes. Basically, that’s the number. In that $200 million to $225 million, we assume that we are going to have $20 million to $25 million of ongoing minor discretionary CapEx that’s going to have a robust return, but we actually say including average turnarounds probably somewhere around $180 million of sustaining CapEx including turnarounds and $20 million to $30 million of discretionary projects, and that does not include any major investment like the rail facilities, which would obviously if we choose to do that the additive.

Paul Cheng – Barclays Capital, Inc.

Okay, that’s fair. And on sustainable basis, you say any reason the way to hold your run your (inaudible), they should not be able to substring on average for the year or the 90% plus utilization range? Is there any particular way that how would you run your operations that we should assume that you cannot get there?

Thomas J. Nimbley

No. Basically, the Toledo refinery while we look for some advantage of crudes, we are not pressing any operating envelope in terms of trying to change the crudes weight around. That would impact us and that’s the same case for the East Coast system, I will mention – I actually mentioned before that we advanced the turnaround, and did modifications on the 60,000 barrel a day unit in Paulsboro, and moved that into 2012, so it allows me, so we could run need Bakken at 55,000 barrels a day. So we wouldn’t have to have a decrease in utilization, but we have already spend those money. So we believe we should be able to run at very high capacity utilization, and assume the margins there.

Matthew C. Lucey

Just I want to comment on that on a general industry basis. The industry ran at high rates last year. The industry is different than the European industry. This is a much more complex refining system, and everybody that I talk to in the industry is focused on environmental and safety compliance, and 10, 15 years ago people pushed the envelope. I think you have to be a little bit realistic about it, when you talk about 90% run rate. We are super cautious on the envelope, and if we think a unit is call it (inaudible) the instructions within our company are very, very straight forward. You take no chances. The unit comes down and that is I think that’s the proper ethic. I think that is the ethic across the business, and that affects your operating rate. Can we operate at a very high rate? You bet we can. But if there is a slightest question on any of those issues, then it’s our Board, our management is driven, don’t let anything bad happen, so it does reduce the – and that’s an industry wide thing and you should – there should be some focus on that.

Paul Cheng – Barclays Capital, Inc.

So two final questions, one on the, if we’re going to shift a well in Richmond directly without mixing oil data with the (inaudible), is there any major modification, you need to make in the unloading facility as well as on the well count.

Matthew C. Lucey

No.

Paul Cheng – Barclays Capital, Inc.

What are the incremental costs here maybe?

Matthew C. Lucey

No.

Paul Cheng – Barclays Capital, Inc.

Is the same?

Matthew C. Lucey

Just no.

Thomas J. Nimbley

In fact I would say that one of the advantages that we think, we’re going to get by not only the dual loop track, which we just started up. Let me back up, we started up this first phase of the royal facility 40,000 barrels a day, and we were using that initially to basically unload Bakken, and then we would stop when we sourced in some heavy Canadians, we put them together on a rack. And that created some efficiency problems because we had a switch between light and heavy. Now with the light facility, we will dedicate that to Bakken, we can dedicate the existing at the first phase rack to Canadian crudes, and then when we do this next phase we actually can dedicate bitumen to one rack, WCS to another rack, and then the Bakken to the third rack, so there will be no additional capital, and we think that we’ll probably – we expect to pick up some efficiency in unloading by doing it this way.

Paul Cheng – Barclays Capital, Inc.

But Tom, by the time that the bitumen arrive in Delaware City would it be already frozen, if you do not have a really hit well car and I thought there you need mix some modification in your unloading facility for bitumen directly.

Thomas J. Nimbley

We’ve already done the modification in the Phase I rack, and that modification that’s why we started that rack up Paul in September I want to say, but we couldn’t unload heavy crude oil bitumen. We couldn’t even unload the WCS at that time because we needed to put in the steam facilities, and we actually bring these cars into a separate spot and then we because they obviously have come in from Canada, we bring him into a heating area , and heat them up with steam so that they get to a temperature that they can flow, and then we move them to the rack to discharge it, so we put those facilities in for this first 40,000 validate rack, and we have that capability now the new rack that we’re designing that we’re building that with board approved yesterday will be designed in it same way, so those racks will be able to heat cars that come in and unload them whether they would be bitumen or WCS.

Matthew C. Lucey

Yeah. I should Paul, we should also point out that we’re in the process of long-term leasing or buying, and have the complete delivery schedule for 3600 coiled and insulated cars, go to the question of insulation, if we built a home 25 to 30 years ago, the insulation values would be much lower, and if you built a home today. Well the absolutely same thing applies to railcars, or rail fleet, will be a company controlled, and/or owned total fleet of new cars, with much higher insulation value, and frankly that’s going to make a difference on how much steam we have to apply, how long we have to apply the steam et cetera, et cetera, so those are tremendous efficiency factors associated with these cars, which have some design features in them, which are peculiar to our operations.

Paul Cheng – Barclays Capital, Inc.

That’s great. And a final one, in the fourth quarter, Tom can you tell us that how much is the Bakken and the Canadian heavy feed that you won?

Matthew C. Lucey

It’s not that much.

Thomas J. Nimbley

The amount of Canadian heavy we ran in the fourth quarter was de minimis to be honest because we didn’t get these heated facilities up until the first part of December, and candidly we struggled a little bit on the learning curve, as we’re unloading, and I want to get somewhere around $20,000 to $25,000 barrel a day at Bakken in the fourth quarter.

Paul Cheng – Barclays Capital, Inc.

Thank you.

Operator

We have no further questions; I will now turn the presentation back over to Mr. Tom Nimbley for closing remarks.

Thomas J. Nimbley

We appreciate everybody attending the call. We appreciate the questions and we hope we’ve answered everything in a reasonable manner, and we wish everybody a wonderful day. Take care.

Operator

Ladies and gentlemen that concludes today’s conference. Thank you for your participation. You may now disconnect. Have a great day.

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!