PBF Energy Inc (PBF) 2013 Q4 法說會逐字稿

Welcome to the PBF Energy fourth-quarter 2013 earnings conference call and webcast.

(Operator instructions)

It is now my pleasure to turn the floor the Matt Lucey, Chief Financial Officer. Sir, you may begin.

Thank you. Good morning, and welcome to our earnings call today. With me are Tom O'Malley, our Chairman, and Tom Nimbley, our CEO.

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

Before we get started, I would like to direct your attention to the forward-looking statement disclaimer contained in today's press release. In summary, it states that statements in the press release and on this call that express the Company's or management's expectations or predictions of the future are forward-looking statements intended to be covered by the Safe Harbor provisions under federal securities laws. There are many factors that could cause actual results to differ from our expectations, including those we described in our filing with the SEC.

As also noted in our press release, we will be using several non-GAAP measures while describing PBF's operating performance and financial results, as we believe these measures provide useful information about our operating performance and financial results, but they are non-GAAP measures and should be taken as such. It is important to note that we will emphasize adjusted pro forma earnings information.

Our GAAP net income or GAAP EPS reflect only the interest in PBF Energy Company LLC owned by PBF Inc. We think adjusted pro forma net income and adjusted pro forma EPS are more meaningful to you because it presents 100% of operations of PBF Energy Company LLC on an after-tax basis.

With that, I'll move on to discussing the fourth quarter and full year 2013. Today we reported fourth-quarter operating income of $142 million, and adjusted pro forma net income for the fourth quarter of $73.6 million, or $0.76 a share on a fully exchanged, fully diluted basis. This compares to operating income of $285 million and adjusted pro forma net income of $165.7 million or $1.70 per share for the fourth quarter of last year. EBITDA for the quarter was $174 million.

For 2013, PBF had a LIFO pool of approximately 14 million barrels of combined feed stocks and products. Our full year 2013 results include a LIFO charge of $24 million, which includes a fourth-quarter benefit of about $113 million. Tom Nimbley will comment further on our operations in a moment, but suffice to say we are pleased to have ended 2013 with a positive quarter on the back of strong cash flow from operations.

During the fourth quarter we began to see some of the benefits of widening crude differentials. Because of the lag involved, we expect some of the benefit from those wide differentials to be captured in the first quarter of 2014. It is important to note that spot prices we see in the market are not realized at the refinery for four to eight weeks, depending on the refinery, crude point of origin, and modes the transportation.

Results for the quarter would have been $70 million higher if pricing of our basis risk on Brent/TI and Brent/Mars were left to settle at the time of delivery as opposed to the time of purchase. The 10 million barrels we purchase each month for our East Coast system are, to a degree, bought from suppliers on a WTI pricing basis.

An example of this would be a purchase of Bakken made in September at a discount of $3 per barrel from WTI when the Brent/WTI differential was $8 per barrel, giving us a landed cost of the Bakken relatively flat to Brent. The Brent/WTI differential expanded over the quarter for an average of about $4 per barrel to $12 per barrel; thus we have lost an opportunity to capture a higher margin.

We have the opposite situation in the first quarter of 2014, where we covered our first quarter of Brent/WTI basis risk during the fourth quarter of 2013 at an average of about $12 per barrel, with the market now at a differential of $9. Therefore, the basis hedge provided gain in the first quarter. We believe this will even out over time, and feel that fixing the proper differential at the time of purchase is the correct practice.

Generally, we try to buy crude one quarter in advance. Therefore, the basis differential should be calculated at it on a lag basis. The second quarter supply, to a great degree, will be based on the first quarter of Brent/WTI differential.

We had approximately $14 million of RIN expenses in the fourth quarter, bringing our full year RIN expense to about $126 million. 2013 and 2014 ethanol RINs are currently pricing in the $0.50 range, which is below the 2013 full-year average of about $0.60 per RIN gallon, but remain above the 2012 prices, which is reflected of the continued uncertainty around the EPA's yet to be determined rulemaking for 2014.

For the fourth quarter of 2013, G&A expenses were $24 million compared to $42 million during last year's fourth quarter. The variance is almost entirely driven by a drop in bonus accrual. PBF only pays bonuses to senior management when the Company meets defined targets. Suffice to say we did not meet our full-year target for 2013.

D&A expense for the fourth quarter was $30 million as compared to $25 million for the year ago period. Fourth quarter of 2013 interest expense was $24 million compared to $22 million last year. PBF Energy's pro forma effective tax rate for 2013 was 37.6%, and going forward for modeling purposes, you should assume a normalized effective tax rate of 40.2%. As mentioned on last quarter's earnings call, the normalized effective tax rate increased during the year as a result of coming off the Morgan Stanley offtake agreement on the East Coast.

Under the new JN agreements, PBF is a benefit of being able to sell our products to the markets of choice and achieve the highest available netback to the Company. As a result of expanding the sale of our products into new markets and in additional states, we established a taxable presence in those states, and correspondingly our overall corporate tax rate has increased along with our expanded sales activities.

The new arrangement added about $20 million in pretax income to the second-half results. We expect in 2014 to see a $50 million improvement to pretax income, as we had the benefit of higher product realizations for the entire year.

Consistent with our guidance provided in January, cash from operations was approximately $150 million for the quarter, which primarily reflects earnings and normal working capital activity. During the quarter we spent $100 million on CapEx and $30 million on dividends.

On the Company's full-year 2013 capital program, net CapEx was approximately $315 million. For the year, our maintenance and turnaround capital spending was approximately $180 million, and about $100 million was spent on strategic projects, including rail infrastructure and a project on the East Coast to convert 100% of our heating oil production to either ultralow sulfur heating oil or ULSD. The balance of our CapEx was for smaller projects at the refineries and other corporate infrastructure.

At the end of December, cash was approximately $75 million. Our net debt-to-cap ratio was 30% (sic - see press release "28%"), and we had about $600 million in available liquidity.

Our Board has approved a quarterly dividend of $0.30 a share payable on March 14 to shareholders of record as of March 4. At this time, PBF's dividend policy remains unchanged, as reflective of both the Board and management's continued confidence in PBF's earnings power.

For 2014, we expect CapEx, net of rail cars, to be in the $250 million to $275 million range. We have two turnarounds currently scheduled for 2014.

At the end of the first quarter, we are going to do a [crebe] unit and move block turnaround at Paulsboro, which should last about three weeks. And in the fourth quarter, we are currently scheduled to perform Toledo's five-year turnaround, which is essentially a full plant outage lasting approximately 40 days. It's important to note that if the market conditions are favorable at that time, we can delay the work at Toledo for a short period.

For modeling our full-year and first-quarter operations, we expect refinery throughput volumes should fall within the following ranges for the full year. The MidCon should average 140,000 to 150,000 barrels a day, and the East Coast should average between 315,000 and 335,000 barrels per day. For the first quarter the refinery throughput volumes for the MidCon should average between 145,000 and 155,000 barrels of oil per day, and the East Coast should average between 300,000 and 310,000 barrels a day.

On the East Coast, we expect to receive approximately 80,000 to 90,000 barrels a day of light crude oil and 30,000 or 40,000 barrels a day of Canadian heavy during the first quarter. We expect our operating costs for the year to range between $4.50 and $4.75 a barrel.

It's important to note that natural gas purchases comprise a portion of our variable operating costs, and on an annual basis we consume about 37 million BTUs across all three of our refineries. In the first quarter, as a result of the weather, we have seen some fairly dramatic spikes in the price of natural gas, and while we do not expect these elevated prices to persist, they will increase our operating costs in the first quarter.

Before turning the call over to Tom, I would like to brief comment on the MLP and the secondary offering we made in January. As mentioned during the second- and third-quarter conference calls, on August 1, 2013, PBF Logistics LP submitted a Confidential Registration Statement with the SEC for a positive Initial Public Offering of its limited partnership units.

Work continues on the MLP. However, due to the confidential nature of the submission and the regulatory restrictions, we are not in a position to answer further questions at this time.

In January, our private equity partners Blackstone and First Reserve successfully sold an additional 15 million shares out of their existing holdings through an underwritten offering by Deutsche Bank Securities. After the effect of the sale, Blackstone and First Reserve collectively hold about 37 million shares.

It's important to note that following the offering, the combined holdings of Blackstone and First Reserve fell below 50% of the fully diluted, fully exchanged ownership threshold, and that PBF Energy is no longer deemed a controlled company.

I'm now going to turn the call over to Tom.

Thank you Matt, and good morning everybody.

Before discussing the fourth quarter results, I want to briefly comment on the Paulsboro refinery operations in the month of January. As we announced the January 7 the Paulsboro refinery experienced a complete loss of steam, primarily due to the instrumentation freeze-up in the boiler feed water system.

The loss of steam resulted in the unplanned shutdown of most of the refinery units. Plant personnel worked through the intense cold of the Polar Vortex, and we were able to return the plant to operations over the course of several days.

The extreme cold that we have seen in the Midwest, the East Coast, in fact the entire country, has provided for a challenging operating environment over the course of the first six weeks of the quarter. And with only a few exceptions, our teams at all of our refineries have performed admirably under very difficult conditions.

Regarding our fourth-quarter financial results, PBF had our best quarter of the year. As with previous quarters, the market was the biggest factor for all of our refineries. Throughput for our overall system was about 459,000 barrels a day, which as Matt mentioned, was in line with our guidance. The Mid-Continent averaged about 150,000 barrels per day, and the East Coast system ran 307,000 barrels a day.

For the quarter, operating cost on a system-wide basis averaged $5.01 a barrel, and for the year operating cost came in at $4.92 a barrel, which is slightly above our guidance for the year. Operating expenses were impacted by the fire at Toledo early in 2013, lower than expected throughput, and higher natural gas prices.

During the quarter, the Mid-Continent 4/3/1 crack spread averaged $10.28 a barrel, down from the third-quarter average of $14.97. And our margin at Toledo was $14.96 a barrel for the fourth quarter. The margin in Toledo is reflective of the weaker product cracks that I just mentioned, offset by improvements and more favorable crude differentials. Our landed cost of crude in the fourth quarter was $0.33 a barrel under WTI at the Toledo refinery.

Syncrude differentials improved during the quarter to, on average, $9.42 under WTI on an FOB basis. As Matt mentioned previously, it is very important to note that our landed cost can differ from the calendar quarter average for several reasons basically associated with the timing between the pricing of a deal and when it is ultimately run through the refinery. As a result, we expect to realize some of the benefit of the wide fourth-quarter differentials in the first quarter of 2014.

The Brent 2/1/1 East Coast crack averaged $9.08 a barrel, down from the third-quarter average of $13.15. The gross margin for our East Coast system was $7.05 a barrel. On the East Coast, our landed cost of crude was about $5.17 a barrel under Brent.

Our landed cost of crude on the East Coast reflects favorable price differentials for light domestic barrels, but was negatively impact by reduced deliveries of heavy crude oils into the Delaware City refinery due to the fluid coker turnaround that we executed during the fourth quarter. Even with the turnaround we were able to deliver over 95,000 barrels per day of Bakken crude oil and about 20,000 barrels a day of Canadian heavy crudes to Delaware.

In the first quarter we expect to bring in 80,000 to 90,000 barrels a day of light crude oil and approximately 30,000 to 40,000 barrels a day of Canadian heavy crudes. Our deliveries of light crude are slightly less than full capacity, as we have to make allowances for the construction underway to expand our light crude oil unloading capacity to 130,000 barrels a day.

In addition to our ongoing efforts to lower input costs through cost-advantage crudes, we are investing in several small capital projects on the East Coast which should improve the profitability of our distillate pool. Matt mentioned that we have now got the capability in the fourth quarter as a result of some investments of producing essentially on the East Coast 100% ULSD or ULHO heating oil.

However, that has come with some offsetting margin deterioration, because we have had to limit cat rates and to sell some light cycle oil. In the first quarter we're going to complete the project, which will effectively allow us to eliminate those constraints and increase the volume, and still make 100% of the premium distillate products.

One other point I think Matt mentioned, we have the flexibility to shift between ULSD, ULSHO, and candidly number 2000 part per million heating oil. There have been times, including in this quarter early on, where it was more favorable to make #2 oil than it was ULSD.

For the first quarter of 2014, we expect our landed crude costs, excluding any hedging or LIFO affects, to be about $1.50 a barrel under WTI for the Mid-Continent and $8.50 a barrel under Brent for the East Coast. Looking forward, we continue to see the benefits of increasing our ability to import greater quantities of the North American crude into our East Coast system.

To that end, we are continuing the expansion of our light and heavy crude oil rail unloading facilities. By July 1 of this year we expect to have two projects completed, which will give us the capacity to unload about 80,000 barrels a day of heavy crude, up from 40,000 today, and 120,000 to 130,000 barrels a day of light crude oil, up from 105,000 barrels a day. So, an install capacity equivalent to 210,000 barrels a day of crude oil delivered by rail.

While we are expanding our rail operations, we are doing so with a keen focus on safety. Those of us in the refining industry have grown up in a culture of safety, safety first. And as our rail operations have become an important extension of our business, we are now applying our safe safety practices and culture to our rail operations. If something is not right or unsafe, we will not do it.

To that end, as of April 1, 2014, PBF will only accept unit trains comprised solely of CPC 1232 railcars or the new DOT 111A cars for delivery of Bakken crude oil to our Delaware City refinery. We feel this is an important step to increasing the safety of our operations by using the safest cars available in our unit trains going to the refinery.

We continue to focus on the aspects of our business that we can control, and continue to demonstrate our ability to generate cash. We maintain that our strategy of sourcing low-cost feedstocks for our system by procuring additional volumes of North American crude, both light domestic and Canadian heavy, should prove profitable for our refineries.

At the same time, while we are positioned to take advantage of any favorable price dislocations for the North American barrels, we are also in a position to take advantage of any waterborne crude oils which become economically advantageous for us to run, and in fact we are doing that today. We are looking forward to a year of safe operations, which will ultimately lead, with the market's cooperation, to a good year.

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

Thank you very much, Tom.

I commented in the third quarter that I was unhappy with the results and the job that we did during that quarter. I will comment today that I'm happy with what we did during the fourth quarter. The turnaround of the coker on time and on budget was truly something that proves the Company can properly operate its equipment and run it on a first-class basis.

The year 2014 is going to be a very important one for the Company. I finally feel that we have turned the quarter on the East Coast. We have got to a point where I believe we can generate sustained profitability in a normalized market. We have made a number of changes. Of course, first and foremost is our ability to take delivery of very significant quantities of rail-delivered crude oil, both from the Bakken and from Canada on the East Coast.

Tom's comment on our approach to railcar movements in using now starting April 1 only the much safer updated, what the industry refers to as 111A cars is of great importance. 100% of our Bakken will be delivered in these cars. These cars are probably 95% controlled by us.

With regard to Canada, we will be going again to 100% of the new cars, starting somewhere between June 1 and June 30. We have a group of cars going off lease at that time. And that should allow us, again, a greater margin on safety, on delivering railcars to the Delaware City refinery.

The ultralow sulfa diesel ability that we now have is also of great importance, and should add to the profitability of the Company during the year 2014. The team achieved this without some huge investment. At the end of the day, we will report next quarter on exactly how much we spent, but it will be well under the $100 million mark.

We briefly mentioned the takeover of the Morgan Stanley product agreement, and Matt Lucey indicated to you that we expected an additional $50 million of operating earnings as a result of this. This isn't based on a hope and a dream, but rather on the statistical data that we have gathered over the past six months since we took this agreement over.

Our netback on products is significantly higher than it was when we had the Morgan Stanley agreement, and indeed I expect the $50 million number to be conservative. In spite of the incident at the Paulsboro refinery during the month of January in terms of losing operations there for approximately 10 days, I would expect the first quarter, provided we maintain a reasonable level of cracks, to be a much better quarter that the fourth quarter of the year, and that is absent any gain or charge on LIFO.

So things look good for PBF from my perspective. And our job really now is to get what the market will give us and to certainly operate our facilities in a safe and environmentally-sensitive manner.

On that note, I would be pleased to take questions and have the appropriate person answer them.

(Operator instructions)

Jeff Dietert, Simmons

Good morning. I was hoping you could talk a little bit about your heavy crude rail and loading capacity. It appears that you have been monitoring rail loading capacity in Canada, and you are trying to optimize the timing of your facility with loading capacity in Canada to bring crude in.

How confident are you in those Canadian facilities coming up? Are you working with a supplier in a particular loading facility to deliver to Del City? Could you talk about your strategy there?

Yes. Look, first of all, we are working with just about everybody up there and following very closely progress, or lack thereof, that they're making. Clearly this incredible winter has had an impact and has slowed things down there.

Our facility in Delaware at the present time can take in about 40,000 barrels a day, and that's what we're running at. We made a decision, and it's from a safety point of view, that we really don't want to expand beyond that number unless it's with the new style of railcars.

And we have significant deliveries of those railcars, the heavy railcars, during the second half of the year. As I mentioned, we will be using on the 40,000 barrel a day number -- our own cars, or new cars being supplied through third parties.

But it's really a combination of the loading facilities, the rate of delivery of the railcars to us, and the timing of our facility is not an issue. We basically can have that available if we wanted to started today, we could have it available in, I suppose, three months.

We've taken the delivery of all of the equipment. We will be putting it together, as we now see the schedule, probably starting in June or July, finish the thing up in September or October.

We're trying to get the ideal weather window also, and building that track. We have done all the civil work already, the earth movement.

But it's impossible for us to tell you how quickly these Canadian facilities will come on, but they are coming. And we are seeing progress, albeit slower than we hoped.

Jeff, this is Tom Nimbley. Just on that last point that Tom was making. Again, you used the right word, we monitor this very closely.

We're up there quite a bit. The Bruderheim facility, the connections facility, has actually started loading some unit trains.

It's a work in progress. The weather is very difficult. We have been at the terminal in Hardisty, which is probably in our view the next likely terminal to get to be able to move unit trains.

They're saying that could be May or June. We question that, just simply because, as Tom said, things seem to move slower in Canada.

We do think the loading capability infrastructure is going to be fleshed out. It could well be a couple of months later than what we hoped for six months ago. We'll see.

Good, and on your light crude capacity, I think your initial estimates of capacity were about 80,000 barrels a day and you're now running 95,000 barrels a day in 4Q and capacity 105,000. Could you talk about your success in getting more capacity out of that unit than you initially expected?

I think that's just good operations, and we managed to build a first-class facility there. You build these things and you hope you'll meet the capacity that you indicated.

We realize now that the facility can do more than we initially thought about. It was well engineered, well designed, and well constructed.

And we are adding additional discharge capacity there so that we will get that unit up to a point where we can do probably upwards of 130,000 barrels a day. But again, everything with time, everything carefully, obviously safety on the rails is of paramount importance. We do have the opinion, by the way, that it would be nice if the railroads would keep the trains on the tracks.

(Laughter). Finally, would you mind providing refinery gross margin for the East Coast and Toledo individually?

Would we mind? Matt?

Sure. For the quarter, the gross margin on the East Coast was $7.05 and for Toledo it was $14.96.

Thank you for your comments.

Evan Calio, Morgan Stanley.

Hello. Good morning, guys. It's another cold and snowy day here on the Northeast. I know that has been the story year to date, and then you guys discussed the operating impact.

And it's also contributing significantly to tighter Northeast diesel margins -- diesel market. Just any comments or outlook on the diesel markets? And also whether you believe the recent uptick in diesel imports is or will continue to support some of this recent RIN price movement?

I think first of all, as ever it was, one has to look at inventory levels to deal with any projections on either diesel pricing or gasoline pricing or propane or whatever. And certainly inventories provide you with a favorable picture.

They are lower than they have been. We are seeing significant -- I don't want to call it necessarily diesel consumption, because diesel and heating oil to some degree are interchangeable on a low sulfur basis.

So certainly we are seeing a good marketplace there. We continue to benefit from that. On the other side of the coin, we have a bit of a detriment on natural gas.

Propane, which we were probably selling during the summer at $1.20 a gallon is trading in the market today well over $3. So this is a seasonal thing that somehow conveniently we forgot over the last few years.

The winter is a time of highest oil consumption. It's not the summer, on a worldwide basis. With regard to imports, certainly we live in a relatively free marketplace, and when the [arb] opens you can expect imported product to come here at a greater rate.

And the arb has been open from a number of market areas. I see it certainly a tight middle distillate market for the balance of this quarter and probably stretching into the second quarter.

Great, thanks. Secondly, in Toledo, Syncrude was a big tailwind in the fourth quarter, and to be realized in parts of the first quarter where 35% to 40% of your runs are Syncrude there. If that advantage was reduced, if Syncrude traded closer at a premium to TI because it is a exportable light sweet crude, how could you source more local TI-linked crudes into Toledo? And if you could tell us what the tenor on the [Ambridge taker] pay is, and how that might factor into your potential slate modification?

Look, for the moment we are certainly taking all the Syncrude we can get. It's still trading at a discount, and we think there has been a change underway in the Mid-Continent with the conversion of a couple of the refineries there from sweet service to heavy service.

The availability of Syncrude to us is, we believe, a bit better than it has been in previous periods of time. Certainly we are an important outlet for the Syncrude, just as they are an important supplier for us.

So obviously if Syncrude trades at $2 premium as opposed to a $1 discount, that's an overall net negative to us. And trying to figure out what a particular pipeline or other transportation resource will do to Toledo is a task that we are perhaps not capable of evaluating properly.

But my perspective on the Mid-Continent is that we are succeeding in generating some other crudes into that refinery. I don't want to go into too much detail and offer my competitors some advantage on that, but you are aware we are trucking crude in.

We did now build additional crude oil storage at that refinery. So Toledo looks like a very strong card in our hand for this coming year, and I believe future years.

Evan, this is Tom Nimbley. I would just add one point, a little bit in the weeds, but Syncrude has a higher value to Toledo than any other crude. Obviously, that's going to be price dependent.

But mainly because it is a synthetic crude. It has no metals in the bottoms. It is -- that's all going into taking out what the upgrade is.

And because we crack 100% of the crude bottoms from the crude unit in the Toledo SEC, the cat cracker, that provides us yield advantages that are rather significant. So if it goes to $10 over we have to buy and substitute crudes, there's no doubt. But it is a very resilient margin crude.

Could you quantify that benefit? Is that $3 to $4 a barrel?

Why don't we not do that? Honestly, why don't we not do that. Look, the other part of that is, please tell me the middle distillate price, please tell me gasoline price, please tell me the alternatives that we have there.

Trying to model this thing perfectly off a 40% Syncrude intake is not the way to go. We've got to be flexible.

We are a merchant refiner. We've got to be able to buy what's cheapest and best coming into our refinery. And when the Syncrude diff gets to an inflated level or more importantly, when we're suddenly prorated, that's not a happy moment for us.

So we're looking for alternatives all the time, and frankly the hidden alternative which hasn't come to fruition yet, but I believe will, is the Utica. I think it will be there. And I think we will be taking crude oil within a year or two from Utica in reasonable quantities.

Great, guys. Thank you.

Roger Read, Wells Fargo.

Yes, good morning. To hit the Canadian thing a little bit more. As you look at it, deliveries of true WCS versus bitumen, and then there was the comment in the presentation, I believe it was slide 9, where you talk about shifting 1,000 coiled and insulated cars. Can you clarify what that means? Does that mean we should expect it to be less bitumen capacity that you can rail down and it'd be effectively WCS that's coming to the East Coast?

No, that doesn't mean that at all. We went up on the 1,000 cars. We, in essence, probably being run over by the luck wagon, no intelligence on our part, had ordered more cars than we would ultimately need.

The 1,000 cars that we switched over from heavy coiled and insulated cars to the light cars allows us to provide 100% of railcar capacity for our intake -- our expected intake. We have upped our expected intake of Bakken-quality crudes and some other Canadian crudes, which are not as light as Bakken, but some medium sours.

And given the situation with rail safety, we just made a decision within the Company that we would not use third-party cars if they weren't the new type of cars. And there aren't that many out there.

It's going to take some years to catch up. That is going to leave us with plus or certainly minus 3,000 heavy cars.

That should be sufficient to carry out what we need in terms of the quantity of crude oil coming into the refinery. Each car carries about 520 barrels of heavy crude oil, might be a little less on the bitumen, due to weight considerations.

So we can cover our needs there. That fleet of cars will give us the capacity to bring in about 80,000 barrels a day of Canadian heavies, and a good part of that WCS. But also, as much bitumen as we can use, provided we have a real price advantage on it.

Okay thanks. And then on the CapEx side, the $250 million to $275 million, the turnarounds at Paulsboro in Q1 and Toledo Q4 or Q1 of 2015, how does the $250 million to $275 million account for turnaround spending? Is that within $250 million to $275 million? Or is there additional spending beyond that we need to think about?

No, it's inclusive of the turnarounds.

Okay. So, obviously there's always some minor stuff, but no major expenses we need to think about beyond that?

Correct. I should point out, and I do this to my colleagues from time to time, I've been in the business a long time. And in my history I have never approved a project that had less than a 30% IRR.

And I believe the other people in the industry approach it the same way. The sad part about this industry from the approval process to the reality, I haven't seen the 30%.

So our Company is concentrating on the small projects, the infrastructure projects. We're not rushing out to build billion dollar units.

They haven't offered the return to the companies that have built them, and I don't think that they will also the return in the future. So we're concentrating on improving everything we have at the margin.

That means that we are not coming and stating we are spending some huge sum of money. What is the total turnaround cost, Matt, that you have? It is well over $100 million.

For 2014 for the two turnarounds that we referenced, the two big ones, Paulsboro in the first quarter and Toledo, it's $120 million.

So the balance of the spending divided between the three refineries really concentrates on infrastructure projects, the expansion of our rail capacity at the Delaware City refinery, the completion of the conversion to ultralow sulfur heating oil and diesel on the US East Coast, additional storage out in Toledo. That type of thing where the resilience of the return on the investment is less based on a projection of what the crack will be, but rather controlling costs and giving us greater flexibility and opportunity.

Okay, great. Thank you.

Blake Fernandez, Howard Weil.

Guys, good morning. I had a couple of housekeeping questions and then one broader macro question. I appreciate the gross margin regional breakdown. Is it fair to assume the LIFO benefit was split fairly proportionally between your capacity in each region?

For the quarter?

Yes.

For the quarter, well, the East Coast has a bigger throughput in the East Coast. But the MidCon actually had more LIFO income in the fourth quarter.

Okay. So it was weighted towards MidCon?

Yes.

Okay, and then Matt, I think you give us the guidance. I wanted to clarify for OpEx $450 million to $475 million. Is that a full year, or is that a first quarter guidance?

Full year.

Okay. Then your subsequent commentary around natural gas. It seemed like, obviously with the spike we are seeing, there could be some upward pressure. Is it fair to think 1Q toward the upper end, or even above that range?

I would say, obviously we're only halfway through the quarter, but the first month of the quarter we had extraordinary natural gas prices. We do not see it as something that is going to continue into the future, but clearly one-third of our first quarter was materially hit on operating costs because of natural gas.

Okay, fair enough. And then my broader question. One of the main macro themes we have been looking for is the potential to begin barging crude out of the Gulf Coast over to the East Coast. And I think you started alluding to this in your prepared remarks, but I was hoping you could offer any insight as far as what you may be seeing there, and if there are opportunities, what kind of capacity you may be able to see change there, in addition to what you're doing on the rail side?

I'm going to answer that question. Look, we move from the Gulf Coast Arab Light up to the refinery in Paulsboro on a consistent basis. We have done so over a period of time.

And the average cost per barrel of the actual movement is about $1.80. Barge or American flagship movement at today's rates would be $7 a barrel.

We're not quite sure how one can justify that. We're certainly not doing it, nor do we contemplate doing it.

We have not taken American flag barges for crude oil movement from the Gulf Coast, nor have we taken ships, nor do we intend to do so. That is, of course, one of the stinging issues on the question of crude oil export.

We, like most other people in business, are for free markets. But I'm not quite sure how it's a free market when the consumer on the East Coast will have to absorb an extra $5 a barrel in freight costs, which comes up to about $0.12 a gallon on every gallon that would be produced from that type of crude.

So I think as long as we have an American Flag Law, and as long as we have, you may remember President Bush in 2007 signed legislation that was termed the Energy and Security Act, I believe, and the security was we had to make sure that our country was not dependent on energy imports from third parties who generally don't like us. And as a result of that, we put in a mandate to use ethanol, 10% of the gasoline pool.

Well, if there is another security question, and you're going to export crude, please remove that mandate and remove the American Flag Law, and then we can move forward. Now there are, I believe, some of our competitors on the East Coast are moving crude up on barge and by ship. We don't quite understand the economics.

I would make this comment in that regard. We look at these economics all the time, as does the competition, and we cannot overcome the hurdle of the Jones Act effectively.

But we are in a little bit different situation than our competition, and in pad one in that we, because of our sour capability and the fact that we have coking, we look at, say, an Eagle Ford would have to compete against [Vasconi] or a medium sour crude.

Some of our competitors are going to look at that versus a waterborne, perhaps West African sweet crude, which has a different paradigm, if you will. So our flexibility to switch from sweet to sour, light to heavy usually drives us -- those waterborne movements out of the Gulf Coast have not been economic.

Understood. Okay. Thank you for your comments.

Cory Garcia, Raymond James.

Yes. Thank you, and good morning, fellas. Recognizing that weather has clearly been a factor for crude by rail in recent months, also hearing some broader chatter about the rails potentially slowing down their service a bit, maybe just a day or two for safety reasons. Do you guys have any updated color on that, or any cycle time update in your Delaware City from both the Bakken and out of Canada?

It has been a bit slower than we had expected, but I think you defined it correctly. It's a case of a couple of days more.

That means that your average number of turns on your railcars drops a bit, but it hasn't been significant. We frankly are of the opinion that the railroads should run the trains at a speed and in a passing mode and through heavily populated areas in a manner where we are not going to see derailments.

We are doing everything we can by providing the safest railcars available to deliver this crude, but if you don't keep the trains on the tracks, it's really a tough game. So look, the winter has slowed down everything.

Those of you in New York are trapped in New York. We're out here at the Credit Suisse conference, and there will lots of people who won't be coming back to New York today, or tomorrow, I suspect. So winter has affected everything.

But the negative impact that the winter has had on operations, on the natural gas price, on a number of things has been to some degree made up by much better metal distillate markets, much better propane markets, et cetera. So all in all, winter is just a fact of life and we are living with it.

One other comment that I would add, this thing is still evolving and will evolve for many years with the infrastructure. But we are now -- just recently have started moving unit trains into Delaware from a Buckeye-owned facility in Hammond, Indiana.

And that was a light sour blend so we could get mixed sweets from Canada. We have a lot of options there.

But the important thing is, that has less transit time. It's seven or eight days. So effectively for those trains, we actually can get three turns.

So there are some other things that are happening that are positive. But clearly, until the whole supply chain gets its act together on moving by rail, you're going to see pressure to slow things down, and we support that.

That's great. You actually read my mind. My next question revolves around that Buckeye facility. Any update on the sort of pricing you are seeing for those light sour barrels?

Again, I would like to just interject here. We are in a very competitive industry, and we don't like to talk about that, okay?

There's plenty of public data available, and let's just say that it's because of our configuration being able to handle sour crudes on the US East Coast, medium sours, we're really the only guys that can take it here. So good situation for us and beneficial to us, and to some degree we substitute a little bit for the Bakken, substitute a little bit for the Canadian.

And again, what the analytical community will have to understand when reviewing our operations is that we are constantly willing to make changes. We don't get into a situation where -- oh gee, well, we ran this stuff last month and it was nice and those guys are going to sell it to us again.

We are constantly out there beating the bushes trying to find something different. And our crude slate's going to move around.

You may find us in one or two months taking more isthmus or Maya crude. Suddenly there may be some very, very inexpensive N100 or Basra.

We really have to move around the chart, and that's what you should expect us to do. And when we move around that circle of availabilities, we do so only when we see better margins.

Completely understand. I guess that keeps it interesting for us. Thank you.

[Rakesh Inzani], Credit Suisse.

Thank you. First quick question is would you be able to give the working capital impact in the fourth quarter --

Could you speak up? There are those of us who can't hear you.

Can you possibly give the working capital impact number for the fourth quarter?

What I'd tell you is we ended the quarter at just around 14 million barrels. And so from an inventory standpoint, it was basically in line with where we were at the end of the third quarter.

The cost basis is, for our LIFO barrels came down a bit. But from a barrels perspective, it was relatively flat.

Also just also relative to what you've historically seen, are you seeing more product trying to get into the East Coast via the Gulf, by any chance? Is the pipeline still --

No, that is just the standard. You got colonial capacity. You use it, you move it up. You can't forget that the East Coast is only, I would guess today, 32%, 33% self-sufficient in the manufacture of oil products.

So we are always going to be taking product into the East Coast, either by pipeline or by import from offshore sources. That's just a given.

Relative to -- are you seeing a bigger push of maybe trying to get any of that excess product relative to what's historically -- has come in?

No. Colonial is full boom. That's it. And offshore supply, if anything, has dropped off of a bit.

Okay, thank you.

There are no further questions. I would like to turn the call back over to Mr. Tom O'Malley for any closing remarks.

Thank you very much for attending today's conference call. And we wish everybody good health on the East Coast during this storm, and take good care of yourselves. Thank you.

Thank you. This does conclude today's teleconference. Please disconnect your lines at this time, and have a wonderful day.