PBF Energy Inc (PBF) 2012 Q4 法說會逐字稿

Good day ladies and gentlemen and welcome to the fourth quarter 2012 PBF Energy Inc. earnings conference call. My name is Lisa I will be your operator for today. At this time all participants are listen only mode. Later we will conduct an answer session.

(Operator Instructions)

I would now like to send the conference over to your host for today; PBF Energy CFO, Matt Lucey.

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 the website www.pbfenergy.com. Also attached to the earnings release are tables that provide additional financial information on our business.

Before we get started I'd like to direct your attention to the forward-looking statement disclaimer contained in the press release. In summary it says 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 operating performance and financial results, including adjusted Pro Forma net income, adjusted Pro Forma EPS, EBITDA earnings before interest taxes depression 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 is important to note we will emphasize adjusted Pro Forma net income and adjusted Pro Forma EPS in this earnings call, rather than GAAP earnings. Our GAAP net income and GAAP EPS reflects only 24% interest in PBF Energy Company LLC owned by PBF Inc. Also the fourth quarter and the full-year 2012 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 for PBF Energy company LLC on an after-tax basis.

With that I'll move on to discussing PBFs fourth quarter and full-year 2012 results. Today we 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-exchanged fully-diluted basis, as I have just described. Compared to a loss of $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 $5.07 per share on a fully-exchanged fully-diluted basis. Compared to $147 million or $1.51 per 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 211 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 costs.

In the fourth quarter D&A expense was $25 million in 2012, compared to $18 million last year. The increase mostly due to depreciation expenses related to the turnaround in Toledo, which happened in the first quarter of 2012. And corporate charges related to the implementation of our SAP operating system. Fourth quarter 2012 interest expense was $22 million, consistent with the fourth quarter of 2011. PBF Energy Inc. 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 of 2012.

Regarding cash flows in the fourth quarter capital spending was over $85 million, which includes turnaround 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 heavy 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 has approved a dividend of $0.30 for the fourth quarter of 2012. $0.30 dividend is 50% higher and a full quarter ahead of the scheduled announced in our IPO perspectives. The early dividend not only reflects the strong results from 2012 but also the positive outlook for PBF in 2013 as reflective of our commitment to return more cash to shareholders.

For modeling our first-quarter operations we expect the refinery through-put 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 2013 our operating costs 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 am now going to turn the call over to Tom Nimbley who will provide an operational overview of the Company.

Thank you Matt and good morning everybody. Our refining system 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 47,000 barrels a day and the East Coast ran at 314,000 barrels a day. Operating expenses on a system wide basis for the fourth quarter were at $4.74 per barrel. For the year operating costs were $4.36 a barrel with the fourth quarter being higher due to increased uses of natural gas and reduced through puts, 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 reduce 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 costs 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 costs and provide our refineries with the most cost advantage crude slate 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 into Toledo during December. These crudes are displacing higher cost pipeline delivery crudes with significant margin benefits. I might also add that we are also carefully monitoring developments in the Utica and are positioning 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 continue to be advantaged by favorable crude differentials and strong product pricing with the benchmarks Chicago, WTI 4-3-1 crack averaging $25.68 a barrel during the quarter. Our realized fourth quarter refining margin in the mid continent was $22.71 per 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 per 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 light 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 sourced into the East Coast improved by over a $1.50 a barrel. And the Brent TI discount improved by over $6 per 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 where the East Coast lost 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 with the significant increase in volumes of crude-by-rail that we expect to source into Delaware.

Before speaking about our crude-by-rail assets, I would like to touch briefly on the incident we had at our Toledo refinery on January 31st 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 18th, the refinery is essentially back to running at planned rates. The total duration of the outage was approximately 18 days.

Moving onto 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 a project to add 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 cost to allow us to source and transport the 80,000 barrels a day of heavy crude from Canada at that time.

I should mention that based on our experience to date with our new dual loop facility, where we've already achieved unloading rates of 70,000 barrels a day, we believe 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 advantage North American crudes to our East Coast refineries that we will see our feed stocks 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 so for handling ability to be able to source and process the heavier high sulfur crude. And now I would like to turn the call over to our executive chairman, Tom 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 turnaround in the second half of the year. And frankly all of 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 Brent marker 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 doubles.

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 in PBFs success is certainly evidenced by our boards decision to pay a dividend for the fourth quarter and in fact to pay dividend that is 50% higher than the dividend we indicated during our road show. We do continue to study maximizing our shareholder value, through the disposition of our traditional, and I emphasize traditional, MLP assets. Those are transportation assets, those are pipeline, those terminals etcetera. They do not include a refinery. We will have more to say about this at the time of our first-quarter earnings call. On that note, we'd be happy to take questions from anybody on the call.

(Operator Instructions)

Evan Calio, Morgan Stanley.

Good morning guys.

Good morning.

Question on the advantage crude runs, I was wondering if you could update us on what you ran in each region and give us where you are volume-wise today, TI, Bakken, CS? And interesting in your earlier comments, Tom, any kind of scoping of the upside potential in a more efficient rail offloading and I have a follow up, please?

Your question is so long it's impossible to consider a follow up. (laughter) Having said that, Evan, Tom why don't you take on that question.

Okay, if I understood the question, there are two parts of it, basically what are we basically running in our systems today? Breakdown of crudes -- and then what the prospects look for the Utica and other crude-by-rail and particularly in Toledo. Let's start with Toledo. Toledo continues to run effectively. It's a completely light sweet slate. It runs about 55,000 barrels a day of Canadian synthetic. As I said we are running 15,000 to 20,000 barrels a day of locally sourced crude, some of that is by truck other is by pipeline. The rest of the slate is WTI price barrels that come out of Patoka and other parts of the Midwest. We do see -- we continue to look for opportunities, and I did specifically reference the Utica because we do believe there's going to be opportunities to continue to source in lower priced crudes than what we are currently running today. How much of that will be dependant upon, obviously, how things develop in the region. The bigger changes are going to happen going forward in the East Coast. We are already seeing some of that. We started running Bakken in the 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 unit to allow it to run 100%. This is the small crude unit in Delaware.

You said Delaware as opposed to Paulsboro.

I am sorry. Paulsboro. It will 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 all of that 80,000 a day of heavy crude which is a combination of the WCS and some bitumen will be run in Delaware City. The 70,000 to 80,000 a day, as I said, we think will be able to exceed the unloading capability and we will be able to source in the volumes of crude from the Bakken at good numbers. We would split that between Paulsboro and Delaware City. For Delaware, it is 80,000 of Canadian heavies, 40,000 or so of Bakken, and the balance will be filled out by the most attractively priced waterborne crudes and 100,000 Maya, etcetera. 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'll run probably some the WCS in the summertime on that still, as well. The [lube still], which is the larger unit in Paulsboro, will continue to run 100,000 barrels a day of Arab light.

I want to add that Tom mentioned 80,000 barrels a day of heavy crude into the Delaware City refinery. The max we will be running in Delaware City in the year 2013, of Canadian heavy crudes, will 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 off that 80,000 barrel a day number into the start of 2014. You had a second part?

I do, I do. I will keep it short. ( laughter ) On the OpEx per barrel, if you could give us more color at each of the regions? In Del city, I know you made significant changes to how you operate that asset and reduce the OpEx. Wonder if you could update us where you were in the quarter and where you are now at Del City? I would appreciate that.

Tom?

Yes for the actual quarter 4Q of 2012, the breakout on a unit basis per barrel was Toledo was $4.67, Paulsboro was $4.82, Del City was $4.90. For the year we were actually lower than that. We were at $4.39 in Delaware, $4.09 in Paulsboro, $4.49 in Toledo. During the road show, we talked about the fact that we were at $4.39 in Delaware City. We expect to be able to achieve our target of about $4.00 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 deviser because of the throughput reductions associated with the storm.

That is great. Thank you. Welcome back.

Jeff Dietert, Simons and Company

Hello. It's Jeff Dietert with Simmons and Company. Good morning

Good morning Jeff.

You talked about the improvements on the East Coast in your feed stock costs relative to Brent, $1.50 improvement in 4Q relative to prior year. I believe by this point, you should have purchased most of your first-quarter crudes for Jan, Feb and March. Can you talk about what type of enhancement you are expecting, or what type of delivery price relative to Brent? What discount you may capture for the first quarter?

This is Tom O'Malley. I will go further with that, we're 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 very close or slightly above its maximum designed rate. We of course did not purchase more than that rate. So the average amount of Bakken in the refinery will be about 50,000 barrels a day. The discount on that will average $2.00 under Brent. We ran very different crudes in the first quarter of last year. And in the fourth quarter of last year we certainly did not have 50,000 barrels a day of Bakken. That was an important element. We are running in the first quarter a crude which we have not run in our ownership period of the Delaware City refinery, Maya crude oil. In the first quarter, I think we are running about 18,000 barrels a day in Maya and at Delaware City refinery and that crude is landing in the refinery at $8.00 or $9.00 under Brent. Last year at this time, the Maya differential probably would've landed in the refinery at $1.00 to $2.00 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 a $1.00 or $2.00 under Brent or in some cases even over. During the first quarter, and Tom correct me on this, I think it is probably averaging $7.00 to $8.00 under. So, the swing in the crude price for the Delaware City refinery, is really quite substantial. It is probably $5.00 or $6.00 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 to Brent during the first quarter. That, however, prices off an average tied to indexes on the Gulf Coast, so it is pricing as we speak. But certainly it is going to be better than it was in the first quarter of last year. I think that answers your question.

I would add one other thing. It is important when we take a look at a crude like Bakken, Tom is spot on, the M100 differentials are a little bit higher -- maybe $2.00 higher, so far this year. The point I was going to make, if you take Delaware City, Delaware does run about 40,000 barrels a day of a lighter crude. Sometimes we source that crude in from West Africa, it can land -- or Hibernia comes in. And that that will trade -- land in at a premium several dollars a barrel to Brent. If we land in Bakken $3.00 or $4.00 under, that is a discount in the crude cost. But the real fact is you're getting a higher quality crude. So we look at things on a relative value basis. If the crude spreads between Hibernia and Bakken -- the landed cost difference is $3.00 we would actually expect to see a margin benefit greater than that because Bakken is, in fact, a higher-quality crude for our system.

Thanks for that information. I had one longer-term question, there are a number of pipelines. Keystone and Inbridge, trying to get from Canada to the Gulf Coast with the transportation rates of $8.00 to $10.00 a barrel versus rail options at $17.00 to $20.00 per barrel. But those numbers really aren't comparable because of the dilutant 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? I think that would --

Let me take that question. Morgan Stanley, I guess a competitor I don't know of yours, came out with a report today which I have not read the whole thing. Rail is a long-term operation. We have to bifurcate it between sweet crude and sour crude. In the fourth quarter, sweet crude imports to the US Gulf Coast, if I recall correctly, 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. From, primarily, Corpus Christi of Eagle Ford crudes, up to the New York metropolitan area. I know PSX is taking material in. I believe the Philadelphia refinery is. If you look at that, and you look at pipeline Perez, and then, on the sweet side, you compare it to our cost of bringing a barrel from the Bakken and some Canadian sweets over $12.50. That is our cost. We do not have anything beyond that because we discharge at our refinery in our terminal. A 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 do not know. But if you're paying $6.00, $5.50 or $6.00, to move from Corpus Christi up to the US East Coast, in today's environment and you are paying pipeline tariff to get it to Corpus, loading charges et cetera et cetera. While I think it would only get worse. I think you are going to see more and more domestic crude moved by rail. That is the sweet crude side.

On the heavy crude side, we are convinced that this is a very, very long term trend. I suppose we've studied all of the reports that you indeed studied. That everything that we see says to us the movement of Canadian heavy crude by rail, particularly if you can get bitumen into the complex, and we can, then that is something that is around for the next decade. That is how we are playing that. We in fact, have ordered enough insulated and coiled rail cars to carry the 80,000 barrels a day. We are making investments and signing agreements in Canada to source that crude as we speak. So that's is 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 Excel will get built. I suppose that is only in the mind and the heart of our current president whether that happens. And his mind and heart does not seem to be there over the last weeks. We are confident, very long term, on the movement of heavy Canadian crudes to the US East Coast. The people who are selling these crudes, the very large companies up there, seem to have that same view, since a number of them have made very, very large orders of rail cars.

Thank you very much.

Paul Sankey, Deutsche Bank

Good morning everyone. Further to your statements that the rail is performing better than you had hoped or thought. Can you update us on the unit costs of moving the oil from Canada and the Bakken? I assume that those are lower now that you are outperforming expectations?

I do not think that is exactly correct. The biggest cost of moving the oil is the rail freight itself. 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 is 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 were 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. A much more complex facility, by the way, than the facility to discharge Bakken that met that 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 for further discharge. In fact going back in, and taking another 2000 rail cars. So it really goes to the crude. The enhanced profitability is 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, 100 cars, that would be about 71,000 to 72,000 barrels and we discharged it in 15 hours. Do we think we have more capacity on that facility? You bet we do. Did we buy crude for the first quarter that would allow us to run much more in the first quarter? No, we did not but are we in the market to buy a bit more in the second quarter? You bet we are, because we are pretty sure we can take that facility up to a higher rate. And of course, once again, when we do that, we displace higher-priced imported crudes and it adds to the profitability of the Company.

Right. Could you remind us of the freight costs?

All in, again Tom correct me, $12.50 on the Bakken, $17.50 on the Canadian heavy.

Excuse me, Tom, go ahead.

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. Those are the right numbers

I appreciate that. Thank you. My follow up would be, in the past at Deutsche Bank, we have talked about the concept of the zombie refinery. You know, the fact that these refineries we thought had shut down on the East Coast may come back. With the crude pricing that you're getting here, how worried are you that we see a resurgence in the utilization?

I hate to refer to anything in my industry as a zombie. I will leave that up to you. Look, there are three refineries that shut down on the US East Coast. The last shutdown was Hess' cat cracker in New Jersey. That unit was shut down during this period of less expensive domestic crudes. So I certainly do not think that is a candidate to come back. The next one that was shut down was Sunoco's Marcus Hook refinery. That refinery -- I do not think that refinery is coming back to be perfectly candid with you. We have actually bought some equipment from that refinery, including a very large pump recently. That refinery is being converted, as I understand it, and you probably could get more information from the current owners, to a facility that deals with some liquids coming out of Marcellus, so that refinery has another use. Eagle point, no way in my opinion. That was closed down I guess about three or four years ago. Those refineries won't be back.

I think more importantly, from the point of view of our Atlantic basin perspective, the two Caribbean refineries, St. Croix and Aruba, are down, really, for a whole series of complex reasons. But of course, one of the biggest ones is that they do not have access to treat natural gas. They are producing power by burning fuel oil, which is an impossible situation. The configuration is wrong, so you are 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, 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 from -- if you go back five years, six years, certainly Western Europe was a competitor and delivering a lot of product to the United States. But this market in the United States is gradually closing to Western European refineries because of the tremendous competitive advantage that US refiners have in terms of inexpensive natural gas, in terms of cheaper crude and feed stocks in to their refineries. It really is a sea change, it is a sea change that no one in the industry properly predicted. By the way, no one on Wall Street properly predicted.

Okay. We called it the diamond age, Tom. Thanks very much for your complete answer.

Faisal Khan, Citigroup.

Thank you and good morning. I just have one question. You mentioned that your 4-3-1 -- that your realized crack spread in the Toledo refinery was $22.00 or $23.00 a barrel which looks to be roughly a 90% capture rate versus your marker. Could you give us an idea -- it looks like if I look back in the past, in previous quarters, the capture rate was much lower. If you could give us an idea of how you were able to capture such a high component of the indicator margin?

Tom, why don't you take it?

I will thank you. One of the things you have to look at, and I will leave it to you to do it because I do not have the numbers right in front of me. Remember that is versus a benchmark 4-3-1 TI crack. We typically say that you should look at Toledo as having its landed crude costs in, on average, at about $2.00 premium to TI. But as you know there is volatility in that. What I would suggest, you look at one component would be what was the actual TI cost in the fourth quarter that may have been a contributor to a stronger crack. Even though we had high cost in December, we were advantaged in part of that quarter. The other thing I would tell you in Toledo indisputably, is we are benefiting from a very, very robust chemicals market right now. Stronger than what we've seen in past quarters, benzene pricing is $200 a barrel or was, and was strengthening across the fourth quarter. Even though it is not that much in terms of its overall margin of volume rather, 5% of the barrel as you start to see a $10, $20, $30 increase in the margin for those volumes that can add in. The other thing that I know that was also a factor in the fourth quarter relative to previous -- again, you have to look at it quarter by quarter is we had a very strong jet market as well.

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

I do not have those numbers in front of me. We can get that for you and get it back to you.

Sure. Thank you for the time. I appreciate it.

Edward Westlake, Credit Suisse.

Good morning everyone. I hope you can hear me.

We can.

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 which is blended with diluent, but pure bitumen do you think you can run at Del City longer term?

Tom, why don't you take that?

Yes, it's going to be a range, Ed, as you well know, we can run -- the short answer, I will be confident we can run 40,000 barrels a day of pure bitumen. We probably could run a little bit more than that, but then we'd have to back out more than 1 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 coker capacity itself and the second is the capacity of the vacuum portion of the crude unit. We can run, and when we say we are going to 100,000 barrels a day or 120,000 barrels a day of heavy crude, that would be a combination of Canadian, Maya, M100 or AMAK or some other waterborne crudes. We could run 40,000 a day of bitumen and 80,000 of everything else. If we wanted to run more of bitumen we would probably have to decrease the total volume of the heavies. Did that help you?

That is very, very helpful. Okay. Switching to a broader question. Obviously you've been very successful with rail to the East Coast. You mentioned a little bit about Utica. As you think about growing perhaps the more stable logistics parts of the business to serve the refineries. are there any investments that you're considering or looking at perhaps to process Utica? If you give us a scale of any capital that might have to go into those investments. I would appreciate it.

I think that is very early days to respond to that question. Utica, right now, is a big question mark. I think the industry is convinced that there is oil there. There is 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 infrastructure investments in terms of moving material by rail or by truck. And we are looking, particularly at Toledo, at all of the possibilities and we are 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 would be looking in the $10 million, $20 million, $30 million, $40 million category. Not in the $100 million, $200 million, $300 million dollar category.

We are very active right now in the Bakken. Loading facilities, given the plethora of facilities out there, it is wise to lease rather than invest any money. We are very active up in Canada. We are working with, really, all of the principal players up there to develop the possibility to load bitumen. The issue up there is, the [clear] for the most part comes down into the general rail loading area, [within the majority] into it. The facilities right now do not exist to take that out. So that, it is an area where really we have our arms wrapped around it. As soon as we have something concrete, you can be absolutely sure we will announce it. But there is no huge capital expenditure coming down the trail other than what we have already announced.

And then obviously we all waiting, hoping for segmental splits. Maybe East Coast and mid con. As you close out the year, would you be able to give a rough percentage contribution from Toledo that was EBITDA before SG&A, or something like that?

Why don't I shift that question over to Matt Lucey. With the caveat that when he gives you the number for last year, you 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 half of the year on the East Coast was not a positive, whatever the East Coast earned, it earned in the second half of the year. Therefore it is ongoing percent contribution should be much higher than the average for the amount. Matt, why don't you take the question?

Thanks. To answer you directly, the full-year EBITDA contribution from the East Coast was roughly 13%. We intend, going forward, as we're in 2013 to report the East Coast and the mid con separately. You will be able to see the performance of both the East Coast and mid con. Up until this point, with Del City in start up mode, it would've caused more confusion than created answers. For the full year 2012, Del City/Paulsboro were roughly 13% of EBITDA for the year.

Certainly. Adding to what Matt said, you should assume that in the second half of the year, the contribution percentage was the entire contribution came in the second half was higher. I am certainly not going to be comfortable with the number going forward from the East Coast of 12%, 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 a market that goes up and down. I believe, that the year 2013 in the mid continent will be a very prosperous year. It is certainly starting off that way. And all indications are, that results across our industry in the mid continent will be very good. Now we have that second leg of the East Coast, with this terrific rail infrastructure that we put in place. We see the East Coast as being a significant contributor to the Company's results.

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

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

Blake Fernandez with Howard Weil.

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

Well look. Obviously the giant export market is the US Gulf Coast. The US East Coast is deficient, to an amazing degree in its ability to produce its own products. I do not know what the latest statistics are but my guess would be we produce on the East Coast in the few remaining refineries, 25% to 30% of what the East Coast consumes. So we are going to be less of a export-driven market. What we see there, is that the imports which used to come out of the Caribbean, certainly St. Croix on a very regular basis was sending oil up to us. Venezuela was sending gasoline cargos. Now they seem to import them. Western Europe has a hard time. So our local demand is very strong. We do see times during the year when the [arb] opens on middle distillate, and we do move middle distillate out. Other products move out.

But the pressure, I think that's what the analytical community should focus on. Pressure used to come to product pricing in the mid continent and the US East Coast from the surplus production on the US Gulf Coast. That surplus on the US Gulf Coast is now moving out into export markets. The pressure in the mid continent that you would see coming at various times during the year, or on the East Coast where the guys down on the Gulf could not find another home and they'd be pushing more up colonial than the market wanted. Well, it is not there as frequently. Our market which you would expect to maintain the colonial pipeline premium, so colonial -- is about $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 of the US East Coast at $0.03 over the Gulf Coast. I expect that differential to widen.

That advantage that the East Coast has, in essence, reflects more colonial pipeline diff. Europe, it is just very hard for them to compete now. Their costs are just that much higher. So that -- 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.

Right. Great. Thanks for the answer. Secondly, a question on MLP. For one, 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? Secondly, I just wanted to confirm I think previously talked about roughly 100 million of EBITDA of MLP-able assets. I did not know if that changed at all with the increased rail capacity? Thanks.

I think first of all, I think my colleague Michael Gayda, the Company's President, is leading the effort. It is 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 true MLP assets to a 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 do not want to quantify it, it is certainly -- it is not another $100 million but it is certainly more than $10 million. So yes, it is creeping up. Since we are looking at other infrastructure things, the potential for even more is there. So it is something that you will hear more about from us when we have our first-quarter earnings call. I think will be far enough along at that point to give better direction -- better information to the market place.

That is great. Thank you very much.

Paul King, Barclays.

Hello guys. Good morning.

Good morning.

Matt, the first one, you say going forward, you are going to bring out the data. I assume you would not just giving the EBITDA but the unit margin and unit cost? Should we assume that in your 10K you will start to have those information breakout for the year or starting in the first quarter report?

It will be going forward, Paul. In terms of specifically what we are doing, we are evaluating our best presentation as we speak. But it will break out enough information so you can see the financial performance. In pad 1 and pad 2.

Paul, to get the most out of the East Coast system, we really have to look at these two refineries -- it is hard to say as one. They are about 20 miles apart, and barge movement is really pretty easy. The combination of equipment they have is extraordinary. It was never taken advantage of before, and we are starting to take advantage of it, and it's real money. 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 that, we will break down the East Coast from the mid continent.

Yes, that is fine. On the East Coast, since they are 20 miles apart, is there any possibility that you can build some pipeline, connect them and run them as a one entity? Or is that really not feasible?

I would only comment that it is difficult to build the pipeline through Nebraska. ( Laughter )

Okay.

Where the Buffalo roam or something like that. I think any pipelines between Del City and Paulsboro from your mouth to God's ear. 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.

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

Yes it does. As Matt alluded to it, the biggest turnaround component 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 to basically [rot] out the coke, we also shut down a hydrocracker. In this case it will just be to change out the catalyst. The other major turnaround, although you know is about half the size -- less than half the size of Delaware City's, is on the big [cured] unit in Paulsboro, which will also be in the fourth quarter. And collectively, that is somewhere between $60 million and $70 million is the total -- about $60 million is the total turnaround CapEx. That is included in the sustaining CapEx in the numbers that Matt gave you.

And also, Tom and we look at that, you have $50 million this year related to the well expansion. Should we assume on a sustainable going forward basis, your system, the (inaudible) CapEx is about $200 million to $225 million a year?

Yes. Basically that is the number. In that $200 million to $225 million we assume that we're going to have $20 million to $25 million of ongoing minor discretionary CapEx that is going to have a robust return. We actually say, including average turnarounds, probably somewhere around $180 million of sustaining CapEx including the 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, would be additive.

Okay. That is fair. On a sustainable basis, is there any reason the way that how you run the three refineries today, they should not be able to sustain on average for the year in the 90% plus utilization rate? Is there any particular way how you run your operation that we should assume that you cannot get there?

No. Basically the Toledo refinery, while we will look for some advantage crudes, we are not pressing the operating envelope in trying to change the crude slate around. That would impact us. That is 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. It will allow -- so we could run the Bakken at 50,000 or 55,000 barrels a day so we wouldn't have to have a decrease in utilization, but we've already spent those monies. So, we believe we should be able to run at very high capacity utilization, assuming the margins are there.

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 talked 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 rates. We are super cautious on the envelope. If we think a unit is -- call it burping if you want, the instructions within our Company are very, very straightforward. You know, you take no chances. The unit comes down. That is, I think that is the proper ethic. I think that is the ethic across the business. That affects your operating rate. Can we operate at a very high rate? You bet we can. But if there is the slightest question on any of those issues, then it is, our board our management is driven. Do not let anything bad happen. So it does reduce -- that is a industry wide thing. There should be some focus on that.

Two final questions. One, if we're going to ship our (inaudible) bitumen directly, without mixing or with the diluted. Is there any major modification that you need to make in the unloading facility as well as on the well? Whatever incremental costs there may be?

No.

It is the same?

No.

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 off this first phase of the rail facility 40,000 barrels a day. And we were using that initially to basically unload Bakken. Then we sourced in some heavy Canadians, we put them together on the rack. And that created some efficiency problems, because you had to switch between light and heavy. Now with the light facility, we will dedicate that to Bakken. We can dedicate 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 no additional capital, and we think that we will probably -- we expect to pick up some efficiency in unloading by doing it this way.

But Tom, by the time that the bitumen arrives in Del City will they be already frozen? If you do not have a really heated -- rail car? I thought you needed to make some modification in your loading facility for bitumen (inaudible)?

We have already done the modification in the phase 1 rack. We started that rack up, Paul, in September, I want to say? We could not unload heavy crude or 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, because they obviously have come in from Canada, we bring them into a heating area, and heat them up with steam so they get to a temperature that they can flow. Then we move into the rack to discharge it. So, we put those facilities in for this first 40,000 barrel a day rack and we have that capability now. The new rack that we are designing -- that we are building, that the board approved yesterday, will be designed in the same way. Those racks will be able to heat cars that come in and unload them whether they be bitumen or WCS.

Paul we should point out that we are in the process of a long-term leasing or buying. And have ordered and have complete delivery schedule for 3600 coiled and insulated cars. Go to the question of insulation, if you built a home 25 or 30 years ago, the insulation values would be much lower than if you built a home today. The absolute same thing applies to rail cars. Our rail fleet will be a company-controlled and/or owned, total fleet of new cars with much higher insulation value. And frankly, that is going to make a difference on how much steam we have to apply, how long we have to apply the steam, etcetera. There is a tremendous efficiency factor associated with these cars, which has some design features in them which are peculiar to our operations.

That is great. My final one, in the fourth quarter, Tom, can you tell us how much is the Bakken and the Canadian heavy that you run?

It is not that much.

The amount of Canadian heavy we ran in the fourth quarter was de minimus, 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 a learning curve as we were unloading them. I want to get somewhere around 20,000 or 25,000 of Bakken in the fourth quarter.

Thank you.

We have no further questions. I will now turn the presentation back over to Tom O'Malley for closing remarks.

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

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