PBF Energy's CEO Discusses Q3 2013 Results - Earnings Call Transcript

Oct.31.13 | About: PBF Energy (PBF)

PBF Energy (NYSE:PBF)

Q3 2013 Earnings Conference Call

October 31, 2013 8:30 am ET

Executives

Thomas O’Malley – Executive Chairman

Thomas Nimbley – Chief Executive Officer

Matthew Lucey – Senior Vice President, Chief Financial Officer

Analysts

Paul Sankey – Deutsche Bank

Evan Calio – Morgan Stanley

Roger Read – Wells Fargo

Ed Westlake – Credit Suisse

Robert Kessler – Tudor Pickering Holt

Jeff Dietert – Simmons

Operator

Good day ladies and gentlemen and welcome to the third quarter 2013 PBF Energy Incorporated earnings conference call. My name is Katina and I’ll be your coordinator for today. At this time, all participants are in a listen-only mode. Later we will facilitate a question and answer session. To pose a question at any time, please key star, one on your touchtone telephone. If at any time during this call you require assistance, please key star followed by zero and a coordinator will be happy to assist you. As a reminder, this conference is being recorded for replay purposes.

I would now like to turn the presentation over to your host for today’s call, Mr. Matt Lucey, PBF Energy’s Chief Financial Officer. Please proceed.

Matthew Lucey

Thank you. Good morning and welcome to our earnings call today. With me are Tom O’Malley, our Executive Chairman, and Tom Nimbley, our CEO. If you have not received the earnings release and would like a copy, you can find one on our website, pbfenergy.com. Also attached to the earnings release are tables that provide additional financial information and operating 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 states 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 the 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 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’s important to note that we will emphasize adjusted pro forma earnings information, our GAAP net income or loss or GAAP EPS reflect only the interest in PBF Energy Company LLC, owned by PBF Inc. We think adjusted pro forma net income or loss and adjusted pro forma EPS is more meaningful to you because it presents 100% of operations of PBF Energy Company LLC on an after-tax basis.

With that, I’ll move on to discussing PBF’s third quarter 2013 results. Today we report a third quarter operating loss of $55.6 million and adjusted pro forma net loss for the third quarter was $46.9 million or $0.48 a share on a fully exchanged, fully diluted basis. This compares to operating income of $220 million and adjusted pro forma net income of $113 million or $1.17 per share for the third quarter of last year. EBITDA for the quarter was a loss of $30.5 million.

As stated in the press release, a factor impacting our results is the changing value of our inventory as reported under the LIFO method of accounting. For 2013, PBF has a LIFO pool of approximately 14.4 million barrels of combined feedstocks and products. Third quarter reported results includes a LIFO charge of about $96 million, a significant number when compared to our overall results. As you will recall from previous quarters, in the first quarter we had a LIFO charge of $66 million and in the second quarter we had a LIFO benefit of about $25 million; therefore year-to-date we have taken a LIFO charge of approximately $137 million. Based on market prices through October, we expect to recouped a majority of the LIFO charge incurred in the third quarter.

Needless to say, the financial results fell below our expectations as our realized margins for both the east coast and midcon reflected the challenging market conditions faced by the refining industry in the quarter. Narrow crude oil differentials, the high flat price for feedstocks, and the high cost of RINs all negatively impacted our results. In particular, capture rates on the east coast were negatively impacted by the rising flat price of feedstocks as dated Brent increased by approximately $8 per barrel over the quarter, which exacerbated the impact on the sales of low value products such as petco, sulfur and LPGs. In addition, light-heavy spreads were narrow during the quarter. For example, the ASCI discount to dated Brent was less than $6 per barrel.

Importantly, we’ve seen significant improvements in crude differentials over the first month of the fourth quarter as ASCI is currently trading at approximately $14 under dated, almost an $8 per barrel improvement compared to the Q3 average. This is coupled with a drop of approximately $7 in the flat price of dated Brent.

In the mid-continent, our operations were again impacted by the high price of syncrude coupled with weaker product markets. While syncrude traded at an average of $0.81 per barrel under TI for the quarter, the plant’s landed cost of crude for the quarter was approximately $5.50 above TI, which is due to the timing lag of delivering crude in the midcon. Again, we’ve seen a marked improvement to crude differentials. As of yesterday, syncrude was trading at an $11 discount to TI on an FOB basis.

We had approximately $40 million in RIN expense in the third quarter, bringing our year-to-date RINs expense through the third quarter to $108 million. 2013 ethanol RINs are currently pricing in the $0.20 range, which is well below the third quarter average of about $0.85 per RIN gallon as the market is clearly anticipating the EPA to publish more favorable 2014 obligations.

For the third quarter 2013, G&A expenses were $31 million compared to $39 million during last year’s third quarter. Included in this year’s third quarter G&A expenses is a non-cash charge of approximately $8 million related to an increase in the tax receivable agreement liability as the company’s effective tax rate increased in the third quarter.

D&A expense for the third quarter was $27 million as compared to $24.5 million for the year-ago period. Third quarter 2013 interest expense was $26 million versus $27 million for the year-ago quarter. PBF Energy’s normalized effective tax rate increased from 39.5 to 39.9 as a result of coming off the Morgan Stanley offtake agreement on the east coast. As you will recall from our second quarter call, as of July 1, we exited the Morgan Stanley agreement and entered agreements with J. Aron, who will purchase and hold 100% of the in-tank product inventory on the east coast. Under the J. Aron agreements, PBF has the benefit of being able to sell our products to the markets of our choice and achieve the highest available netback to the company.

As a result of expanding the sale of our products into new markets and additional states, we have established a taxable presence in those states, and correspondingly our overall corporate tax rate has increased along with our increased sales activities. By taking out the Morgan Stanley offtake agreement on the east coast, the company took on approximately $175 million in incremental trade receivables as the company is now selling its products directly to the market. Even with the one-time requisite investment in working capital, the company was able to reduce its net debt for the quarter by approximately $68 million.

Cash from operations was $180 million for the quarter, which reflects reductions to crude oil inventories to normal operating levels, as well as returning crude payables to normal levels. During the quarter, we spent $85 million on CAPEX and $30 million on taxes and dividends. At the end of September, cash was $57 million, our net debt to cap ratio declined to 29%, and we had just under $600 million of available liquidity.

Our board of directors has approved a quarterly dividend of $0.30 a share payable on November 21 to shareholders of record as of November 15. At this time, PBF’s dividend policy remains unchanged and is reflective of both the board and management’s confidence in the earnings power of PBF.

On the company’s capital program, we expect 2013 expenditures to be approximately $250 million to $275 million for the full year. As we approach the end of the year, we have adjusted the capital program regarding the timing of certain projects, the inclusions of new projects, and identifying opportunities for 2014. As we discussed last year, the most significant changes relate to several initiatives on the east coast focused on increasing our ultra-low sulfur distillate. We deferred the crude and lube block turnaround at Paulsboro for the Q4 2013 to the end of the first quarter of 2014. This turnaround is expected to take 20 days and we pushed out the schedule for the completion of the heavy crude unloading rack and now expect completion by the end of the second quarter in 2014.

The delay in the heavy unloading rack project is driven by infrastructure delays in Canada and aligns the construction of the rack and the ensuing additional capacity with the anticipated delivery schedule of our own rail fleet. It’s important to note that our deliveries of Canadian heavy crude oil to our Delaware unloading facility are not expected to exceed 40,000 barrels per day, our current capacity, until the expansion is complete.

For modeling our fourth quarter operations, we expect the refinery throughput volumes to fall within the following ranges: the midcon should average 150 to 160,000 barrels a day and the east coast should average between 305 and 315,000 barrels a day. Our run rate for the year will be impacted by the previously announced ongoing turnaround at Dell City, which is scheduled to be complete within the next two weeks. On the east coast, market conditions permitting, we expect to receive approximately 85 to 90,000 barrels per day of Bakken crude oil and 20 to 25,000 barrels a day of Canadian heavy crude oil during the fourth quarter. We expect our operating cost for the year to range between $4.70 and $4.80 a barrel, which includes the impact of the Toledo fire in the first quarter, increased natural gas usage at a higher natural gas price, and reflects lower than planned throughput through the first nine months and the impact of the turnaround at Delaware in the fourth quarter. Tom will speak more on the turnaround in a moment.

Before turning the call over to Tom, I would like to make a brief comment on MLP. As mentioned during the second quarter conference call and announced in our second quarter earnings release, on August 1, PBF Logistics LP submitted a confidential registration statement with the SEC for a possible initial public offering of its limited partnership units. Work continues on the MLP; however, due to the confidential nature of the submission and regulatory restrictions, we are not in a position to answer further questions at this time.

I am now going to turn the call over to Tom Nimbley, who will go over the operational review of the company.

Thomas Nimbley

Thank you, Matt, and good morning everybody. Before discussing the third quarter results, I want to briefly mention the coker turnaround which is currently underway at our Delaware City refinery. The turnaround has been underway for about 30 days, and at this point we expect it to be complete on time, as Matt said, within the next two weeks. I would also like to highlight the fact that this turnaround comes on the heels of a record run of approximately 2.5 years for the Delaware City coker, and this run in many ways is indicative of the improved reliability of this asset.

Regarding our financial results, PBF had a disappointing third quarter. The market was the biggest negative for all of our refineries. Throughput for our overall system was about 446,000 barrels a day, which as Matt mentioned was in line with our guidance. The midcontinent averaged about 148,000 barrels a day and the east coast system 298,000 barrels a day. Throughputs across the system were lower than planned as we adjusted run rates due to high flat prices for feedstocks, narrow crude differentials which results in poorer coking economics, and weaker cracks, particularly in the midcontinent. Operating costs on a system-wide basis averaged $4.69 a barrel.

During the quarter, the midcontinent 431 crack spread averaged $14.97, down from the second quarter average of $29.26 per barrel, and our margin was $6.97 a barrel in Toledo for the third quarter. The Brent 211 east coast crack averaged $13.15 a barrel, down from the second quarter average of $14.67, and the gross margin for our east coast system was $3.66 a barrel. Our landed cost of crude in the midcontinent was approximately $5.64 a barrel over WTI, as Matt mentioned, principally as the result of the high cost for syncrude which comprises about 35 to 40% of our crude slate at the Toledo refinery. On the east coast, our landed cost of crude was about $4.15 a barrel under Brent, an improvement over the second quarter as a result of improved but still narrow crude oil differentials. The narrow crude oil differentials negatively impacted the economics for rail-delivered Bakken and WCS barrels, and consequently we did not fully utilize our 140,000 barrels per day of crude by rail unloading capacity.

During the third quarter, we delivered approximately 35,000 barrels a day of Canadian heavy crude and 60,000 barrels a day of light/sweet crude to Delaware City by rail. In the third quarter, the economics for Bakken did not warrant delivering greater quantities to the east coast, and consequently we adjusted our slate to bring in additional quantities of water-borne crudes. Having said that, in the fourth quarter we expect to bring in 85 to 90,000 barrels a day of Bakken as the economics have greatly improved over the last few weeks.

Looking forward, we continue to see the benefits of increasing our ability to import greater quantities of North American crude into our east coast system. To that end, we have identified a project to expand our light crude unloading capacity by adding additional discharge points to our existing dual lube track facility. This would increase our light crude unloading capacity from approximately 100,000 barrels a day today by another 20,000 barrels, bringing us to a total unloading capacity of 120,000 barrels a day. This project is expected to cost about $10 million, about half of which will be subsidized by our rail partners, and is expected to be complete in May of 2014.

As Matt mentioned, on the heavy side, again subject to the market, we expect our deliveries of Canadian heavy crude to be about 20 to 25,000 barrels a day in the fourth quarter. Deliveries are reduced and have been impacted by the ongoing coker turnaround at Delaware City. Without the coker, obviously our ability to profitably process WCS or other heavy Canadian crudes is reduced.

Heading into the fourth quarter, we expect our crude costs to come down, and for the midcontinent we expect our landed cost, excluding any LIFO or hedging events, to be about $2 a barrel under WTI, principally driven by the strong improvements in the syncrude differential. For the east coast, we expect our crude to be landed in at about a $4 a barrel discount to dated Brent, narrower than the third quarter again due to the reduced volumes of heavy crude being run at Delaware as a result of the turnaround.

As we mentioned last quarter, due to delays in the build-out of logistics infrastructure in Canada, we do not expect deliveries of Canadian heavy crude to reach 80,000 barrels a day until the second half of 2014 when we have our additional expected capacity in place. Depending on developments in Canada, PBF projects for doubling of our heavy crude unloading capacity could be advanced or further delayed, as needed.

We continue to focus on the aspects of our business that we can control and have demonstrated our ability to generate cash. We continue to believe in our strategy of sourcing low-cost feedstocks for our system by procuring additional volumes of North American crude, both light domestic and Canadian heavy. Our view is that the high prices and the volatility in the North American crude oil environment through the first nine months was primarily event-driven. Light crude oil demand in the midcontinent increased as a result of refinery start-ups, line fill for pipeline start-ups, and outages decreasing the availability of imported syncrude. While there still are some pipelines requiring line fill and there will likely be other temporary supply disruptions, we believe as these events are absorbed, the light crude market will improve, and in fact obviously is improving for refiners.

On the heavy side, differentials were negatively impacted by infrastructure constraints in Canada, floods and pipeline outages, and maintenance to production facilities. While we expect to continue to see near-term volatility in both the flat price of crudes and the differentials as the industry continues to adjust to growth in North American production and infrastructure changes, we believe that over the long term discounted North American crudes versus water-borne alternatives will provide PBF with a cost advantage.

While it is too early to speculate on the entire quarter, many of the crude differentials that are significant to PBF have widened on the first weeks of the fourth quarter. The WTI syncrude differential, which as Matt mentioned averaged a discount of $0.81 in the third quarter, has blown out to $10.42 through the first four weeks of October. Bakken versus Brent has gone from a discount of $9.25 to $20.42. WCS versus Brent has moved from $28.39 under to $40.38 under; and importantly, the ASCI differential, which has a major impact on Paulsboro’s profitability to Brent, has gone from an average of $5.92 under in the third quarter to a discount of $11.51 quarter-to-date. The crude picture is looking very good for the fourth quarter and looking forward into the first quarter of 2014.

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

Thomas O’Malley

Thank you very much, Tom. Trying to find something good to say about the third quarter in our industry in the United States or in PBF is something similar to putting lipstick on a pig. It just was an ugly quarter. There is no way to get around it. I’m certainly pleased that we managed to generate significant cash. Others in our industry—I believe PSX was affected the same way we were on the FIFO-LIFO question, but still a poor quarter, to put it mildly, and that’s the battle of the marketplace.

Tom has already outlined for you the differentials which we see improving on a very significant basis during the fourth quarter, and hopefully that will lead to better results for our company. We do have to recognize that the full month of October was affected by the turnaround that Tom talked about.

On that note, I’d be pleased to take whatever questions any of the listeners have.

Question and Answer Session

Operator

Thank you. [Operator instructions]

Your first question comes from the line of Paul Sankey, representing Deutsche Bank. Please proceed.

Paul Sankey – Deutsche Bank

My first question regards how you see the Atlantic basin market playing out, just in terms of the pain that’s being suffered in Europe. We’ve agreed in the past that we probably need to see shutdowns in Europe, which would ultimately, I guess, improve the market. Can you give us your latest thoughts on how that could play out? Thanks.

Thomas O’Malley

Sure. This is Tom O’Malley. I spoke at a conference yesterday in Las Vegas, the Opus event, and in essence that was the theme of the presentation, the Atlantic basin. And when looking at this, and this may be answer that’s a little bit longer than you like, but there we have it, if you looked through the 80s and 90s, you saw a period of time when North Sea production was at a very high level and where in essence European export refiners had an advantage based on what they viewed as domestic crude within the EEC, delivered in some cases directly by pipeline from the North Sea field and others on a one or two-day trip via shuttle tanker. They were a very big factor in the U.S. east coast marketplace and in essence they determined the price.

During my presentation yesterday, what I said and what I believe is that we’re going through a sea change here. We’re going through a flip of the coin and now we’re on top of things here in the Atlantic basin. We, in essence, can take in crude oil at a lower price than our European competitors can. They’re paying Brent plus; we’re paying Brent minus, and you can’t make that up. When crude oil was $20 a barrel and you had a 1% difference in the crude price, well, you could deal with that. Crude oil at $100 a barrel, 1% is $1, and certainly the differentials are wider than that.

So I see a very significant contraction in European refining and I think it’s going to come sooner than most people believe. Certainly if you look at the import data to the U.S. east coast, you’re seeing a decline, and I believe that’s going to continue. In fact, you are seeing exports from the United States to Europe.

Paul Sankey – Deutsche Bank

Thank you. Further to that, obviously it’s vital for you to get the cheaper crudes in. I’m afraid I slightly lost track – there was mention of a delay to one project. Could you just remind us of the schedule now of how your crude deliveries will change, particularly if—

Thomas O’Malley

Well, the item that we delayed was the second heavy unloading rack at the Delaware City refinery. We currently have a facility that discharges approximately 40,000 barrels a day. Looking up into Canada, the infrastructure projects up there have fallen behind schedule, and a couple of them that were due to come on-stream in the fourth and first quarter are pushed out to late in the second quarter; so basically, we said there’s no point building the facility if the oil is not there to be loaded up in Canada, so that is effectively for us about a five-month delay. We originally wanted to bring that facility on-stream in December-January of this year—December of this year, January of next. We’ve pushed that out now to be finished on June 15, and that will coincide with the delivery of rail cars to us, which is another very important factor. All of our rail cars are being delivered on the new 111As, and that’s important because we think the 111s, the existing fleet, may be outlawed – the railroads don’t want to handle them.

That was the facility that we delayed. Other than that, we’re exactly on schedule.

Thomas Nimbley

This is Tom Nimbley. I’d just add to get specific on one of the pieces of the question, we currently have the dual lube track completely done and we can do about 105,000 barrels a day of light-sweets or light-sours. I referenced this project that we were adding, which will be in addition to the dual lube track that will increase that from 105 to 125,000 barrels a day by May. As Tom mentioned, we have 40,000 barrels a day of capacity installed running today on the heavy side. That doubles to 80 right at the end of the second quarter.

Paul Sankey – Deutsche Bank

That’s very clear, thanks. And then you gave the Q4 guidance – I think I heard that. We don’t need to—I mean, you might repeat it, but there’s guidance for how much you’re taking in Q4, right?

Thomas Nimbley

Yes. Yes, we’re going to do 85 to 95,000 barrels a day of Bakken. We might exceed that a little bit, but that’s the number; and 25 to 35,000 barrels a day of WCS, Canadian. We are running 10 to 12,000 barrels a day of pure bitumen into the east coast system. There are economics that are better than WCS on that, simply because we get a bigger discount by buying the lower gravity bitumen that more than offsets the increased transportation cost, but 25 to 35,000 barrels a day because of the coker downtime at Delaware on the heavy side.

Paul Sankey – Deutsche Bank

Okay, great. And just to finish and round that out, then, so between the Q4 numbers and May-June, I guess we run forward with the Q4 numbers as your run rate?

Thomas Nimbley

Once we get the Delaware City up, we’re going to run 40,000 barrels a day. This is all obviously predicated on economics. Basically we’re going to run 40,000 barrels a day of WCS. We have very, very favorable economics right now until we get to the end of the second quarter, and then we’ll be able to double it.

I also did make the point—maybe I wasn’t as clear on it. One of the thing we’re going to be looking at is we delayed, as a number of us have mentioned, including Tom, the second 40,000 barrel a day facility until midyear next year because of timing it up or syncing it up with infrastructure being built out in Canada to allow the loading of heavy Canadian into rail, and the timing of our rail car fleet. We are starting to see some indications of producers having their own cars, or other people perhaps offering some deals on a delivered basis. We’re going to watch that close. If that looks like it’s going to happen, we might try to see if we can advance the rack itself by six weeks or so. We’ll make that call as market conditions play out.

Paul Sankey – Deutsche Bank

Thank you, guys.

Operator

Your next question comes from the line of Evan Calio, representing Morgan Stanley. Please proceed.

Evan Calio – Morgan Stanley

Hey, good morning guys. A question on rail, and I realize that as you said, all the crude differentials for you in particular are much better now than they were in the third quarter. But with the east coast rail yard closed for a significant portion in the quarter, I think it looks like your Bakken volumes were 10,000 barrels a day lower. Can you discuss just how quickly you can shift away from rail volumes in that environment, given you’re replacing them with, I presume, water borne? And what was the cash cost as you think about the cost of not running rail, committed costs you may have there that factor into the economics of the decision not to rail?

Thomas O’Malley

Well look, there are two different answers dependent upon the crude that you’re talking about. On the Bakken, there is really no significant downside if we decide to take in an imported barrel as opposed to Bakken. The majority, of course, coming in with Bakken, do not belong to our company, so we’re not suffering any debit on that side of the equation. On the heavy, it would of course be slightly different in the sense that as we build up the rail fleet, and certainly we won’t be at a level with the rail fleet where we can completely use our own cars probably until the fourth quarter of 2014, so we’re still using third party cars on the heavy side. At that point, if you laid up a car, there’d be a cost for that car, and the cost for each car is about $1,000 a month, maybe a little bit less on a lease basis. Each car moves on the heavy side about 700 barrels a month; on the light side, of course, far more.

We don’t see that as a problem, particularly with regard to this question of 111 and 111A cars. While the designation sounds so similar, the cars are completely different; and with the recent incidents in Canada which involved the old cars, there’s a tremendous movement now that some companies simply wouldn’t take the old cars, that we think in fact we’re going to be in a pretty terrific situation since our entire fleet will be these new cars.

Evan Calio – Morgan Stanley

Is there any timing element in the sense that it’s a shorter time period to delivery via rail versus maybe picking up those barrels on the water? Does that impact the time it takes to make the switch?

Thomas O’Malley

Well not really, because we are buying barrels at the present time for the month of December. We’ve bought our November Bakken barrels. We know what we’re taking in in the month of November, so as we go forward and we’re buying December and the December economics are better than November, and indeed by the way, we have bought right through the first quarter, not large quantities, but we know well in advance what we’re doing. And in terms of the water borne crudes, the typical crudes that we’d be replacing if we were replacing Bakken would be transit times of 15 to 20 days if we were buying them on a FOB basis. But most of these cargoes show up as unsold CIF arrivals, and there’s not much time in between.

Evan Calio – Morgan Stanley

Great. Lastly, just to switch topics here to a topic near and dear to you, but it appears you’ve been successful so far on, again, the crusade against RFS or RVO obligations, and we should see an RVO pretty soon if you read reports from the EPA – I guess a Halloween release could be appropriate. But can you give us any color on what you disclosed in the release today on your petition for partial waiver of the RFS, kind of what the time frame is there, and just to help us understand the basis there? I’ll leave it at that, thanks.

Thomas O’Malley

Well, one waiver was issued, I believe it was for the Krotz Springs refinery in Louisiana. That’s a refinery I owned back in the 1980s when I was with (indiscernible). It’s hard to understand on what basis the waiver was issued. How did it work? We’re not quite sure. We know that Delta Airlines now applied for a waiver for its Trainer refinery – again, that was a refinery we once owned. We’re not completely sure what the basis of that was, except that they said they bought a closed-down refinery and reopened it. Well, so did we in Delaware.

I think the basis that we see for these things and the complication inherent in the rule-making by the EPA and the Congress was we should in essence take a 20-gallon gas tank and put 12 gallons in it. Well, we can’t do that, and that’s part of our thing, and part of our thing is we don’t own a single retail outlet, therefore we can’t tell someone to sell 11, 12, 13, 14% ethanol, and there is no one on the east coast who has that ability. So we’ve applied for the waiver basically using the same arguments that have been used by our friends at the Krotz Springs refinery and our friends at Delta. I mean, if they are going to get waivers, why shouldn’t we get a waiver?

It’s a complicated story. The API and Delta have also established a lawsuit against the EPA, saying that what you’re asking the industry to do is impossible, and indeed that is at the crux at the argument. I suppose if there was a market for 15% ethanol, it wouldn’t be impossible; but RINs are a program where it’s a very simple bar graph. You have one bar on one side which gives you the maximum amount of ethanol you can put in gasoline in the United States and maintain the warranty on automobiles, and then on the other side you have a higher bar that says you have to put more in, and it simply doesn’t work. Now, if the federal government can’t figure out the economics on this, I must say I have difficulty understanding how they are going to do this healthcare thing.

So that’s the basis of it. Do we have a chance? I don’t see why we don’t, but predicting something in Washington is a fool’s game.

Evan Calio – Morgan Stanley

And what is the timing on that process? Are there any parameters to think about when you may have a decision there?

Thomas O’Malley

At the same time they decide to balance the budget in the United States.

Evan Calio – Morgan Stanley

Understood. Thank you.

Operator

Your next question comes from the line of Roger Read, representing Wells Fargo. Please proceed.

Roger Read – Wells Fargo

Good morning. I guess two things I’d like to kind of understand a little bit. How quickly you can react in terms of moving by rail both up and down, so obviously harmed in the third quarter but volumes by rail were similar to the second quarter, so maybe you can give us an idea of when you might have ramped up or down during the quarter. And then obviously as you explained both in the press release and in the opening statements, we’ve seen differentials expand quite positively here in the fourth quarter. How quickly can you move to unit trains, either using them more frequently or taking advantage of manifest deliveries?

Thomas O’Malley

You should think in terms of a week. Certainly we follow the market on a daily basis. If we see a trend changing, we really came into the month of July and by the month of July, of course, we were buying for August and September, and we said the numbers are too high and we in essence stopped buying aggressively. You probably could think of a day even, but these things, we see them develop over a week. The Bakken particularly is a marketplace where you can react in a very, very short term. On the Canadian side, it’s a little bit longer lead time in terms of those are cars that we generally provide in the Bakken. I suppose we are maybe supplying 30% of the cars we use, so we’re just buying them from the producers with rail cars attached. In Canada, it’s a different program, or at least it has been until now.

So very, very fast in the Bakken, up in Canada I would guess a couple weeks. Tom, I don’t know if you would have a different reply?

Thomas Nimbley

No, not a different—something to add, more specific to—Bakken is effectively a unit train, so in terms of the mode of transport by rail, everything we get by Bakken comes in on unit trains and there is right now a very fast reaction time, there’s a lot of Bakken.

The Canadian is still manifest, although as you are all aware, Bruderheim and other infrastructure sites are being built out, and we do expect to see some unit train movement starting certainly in the first quarter of next year. That is obviously an advantage to someone who is hauling it by rail effectively to drop our cost down by north of a dollar a barrel on that basis alone.

The other thing I’d add is we talk about Bakken light-sweets and we talk about the heavy Canadians. We are in discussions with a Buckeye terminal in Hammond, Indiana where we’re actually going to be loading some light-sweets. It’s got less transit time into Delaware City, but importantly it will have the capability of actually moving some light-sour crudes, and this is something that’s very important to us on the east coast because Delaware City and Paulsboro have the ability to run a higher sulfur crude than Bakken, so these crudes are actually 36 degree API, 1.2% sulfur. They can’t be run in other facilities in the east coast because their true sweet-crude refineries will be able to bring them into Delaware, and we’re starting that operation in November and we’ll try to ramp it up some in December.

Roger Read – Wells Fargo

Okay. And then my second and I guess generally unrelated question to that is as we look at what’s moved around in terms of working capital, cash flow and cash balances, obviously we expect better differentials and probably better margins here in the fourth quarter and first quarter than we saw in the third. But can you give us a little bit of an idea of maybe some of the future cash issues, if there is any pension payments or tax payments or anything else unusual that we should be thinking about here over the next three to six months.

Thomas O’Malley

Matt, why don’t you answer that?

Matthew Lucey

Sure. Roger, as you recall from our last conference call back in the second quarter, we spoke about a big working capital swing. We obviously saw that come back. I would quantify our current position as sort of normal operating levels, so I do not anticipate big swings going forward. That being said, it’s sort of a reality with $100 crude, if you’re bringing in a 500,000 barrel vessel, they don’t come in perfectly ratable. You can and will have swings, but I think to answer your question directly, we are where we should be so I don’t anticipate anything major in the future.

Roger Read – Wells Fargo

Okay, so basically just operational issues at this point?

Matthew Lucey

That’s correct.

Roger Read – Wells Fargo

Okay, that’s it for me. Thank you.

Operator

Your next question comes from the line of Ed Westlake representing Credit Suisse. Please proceed.

Ed Westlake – Credit Suisse

I’ve got a story for you guys. I was up in the farm belt and I got a Hertz car and it was a flex fuel vehicle, and it had a big sticker saying, no more than E15, and I was driving past gas stations saying, ethanol-free gasoline here. So that shows how much enthusiasm there is.

Just a quick question, though, on core capture rates in the east coast in particular. Obviously we’ve had a long discussion around the crude discounts, and WCS and Bakken look like they need rail to get to market, so that’s good for you guys. But Tom, maybe just chat about how you think about how the east coast sort of refining assets are doing relative to your hopes for where that core capture rate should be.

Thomas O’Malley

Tom Nimbley, why don’t you take that? He said Tom – we’ve got two of them.

Ed Westlake – Credit Suisse

Sorry Tom.

Thomas Nimbley

Yes, little Tom will try to take care of this. The east coast, from an operational standpoint, we’re quite pleased with the way the east coast is run from basically the foundation of this business – safe, environmentally responsible, and reliable operations. From a yield standpoint, we’re still looking to see whether or not—what we can do to try to get a little bit higher C3-plus yield out of Delaware City. We’re actually doing some things during this downtime unrelated to the coker. There are some other facilities that have come offline that we scheduled to come down with the coker, that we’re making some improvements in.

The biggest thing we see going forward that I think will be an improvement on that, and we’ve started, is we’ve effectively figured out how to make 100% ultra-low sulfur diesel at our Paulsboro facility, and typically that facility makes about 25,000 barrels a day of jet; but everything else was number two fuel oil, 2,000 part per million fuel oil. We completed—

Thomas O’Malley

Heating oil.

Thomas Nimbley

Heating oil – I’m sorry. So we completed a project that Valero had bought some equipment for. We now have that facility capable of making 15 part per million ULSD or ultra-low sulfur heating oil; however, it does come with some economic debit on—we have to reject some material out of the distillate pool. We’re going to basically, after we restart Delaware City up, be able to move that material over to Delaware City and turn it into ultra-low sulfur diesel at Delaware City.

So we’re going to see some improvements in what we’ve been able to do, but on the east coast and in fact in Toledo, the thing that’s going to drive the capture rate is going to be the landing cost of crude versus the benchmarks.

Thomas O’Malley

Just let me add something to that. The big—Ed, of course as an engineer, has worked in refineries – I don’t know that all the other callers have. So the C3-plus is of course more easily defined for those of us who think in those terms as stuff that sells at a price greater than crude oil. That’s our goal and objective. I think the big swing you’re going to see going forward is we’re going to make less petroleum coke at the Delaware City refinery, and there that’s going to creep over into that C3-plus material. Whether that turns out to be a half percent or 1% is something we don’t really appreciate today, but in essence we’re squeezing the material a little more, we’re running it a bit more intelligently, and some of the changes that we’re making during this turnaround – and we are investing $25 million during this turnaround in rate of return projects at Delaware – I think that’s going to have a favorable effect. It certainly will result in the production of more ultra-low sulfur diesel also at Delaware.

So there’s a lot of things going on inside the box where we are going to see some improvement, and for us the ability now to get out of the 2,000 part per million heating oil market and be in the ULSD market without making some massive investment was really a tribute to all the equipment and the smart people we have within the company.

Thomas Nimbley

One other comment I’d make, Ed, that goes along with what Tom was saying is right now, obviously, we’re also being some advantaged – we’ll see how long it lasts – the lower cost of crude means lower losses on coke products. So the price of coke doesn’t change, but the price of crude goes down, for every dollar you’re going to pick up perhaps $0.10 a barrel margin on a coking refinery. So if we see this trend continue, that should show up in a higher capture rate.

Ed Westlake – Credit Suisse

Yes, I’ve got some specifics then on what you’ve said, and that’s all very helpful for thinking about capture rates improving going forward relative to this year. But just on ULSD at Paulsboro, how much heating oil fuel are you selling in thousands of barrels a day, or percentage of slate – whatever is easiest – just so we can think about what that change is going to do?

Thomas O’Malley

We’re not selling any 2,000 part per million heating oil.

Thomas Nimbley

At Paulsboro.

Thomas O’Malley

In essence, you can look at the upgrade between—if you compared it to last winter, the upgrade between—what were we selling, 25, 30,000 barrels a day heating oil?

Thomas Nimbley

Correct.

Thomas O’Malley

That’s now all either jet or ULSD.

Thomas Nimbley

And at Delaware City, we still make some amount of heating oil, 2,000 part per million heating oil, about 10,000 barrels a day when the refinery is running. After we come back up, with the projects that we’re putting on, probably by first quarter, end of first quarter, we’ll be completely out of the 2,000 part per million heating oil business unless it is economic. I mean, there could be a case that it could come back.

Ed Westlake – Credit Suisse

And then just a general comment on LPG yields – do you know roughly what your LPG yield is on the east coast and Toledo? Obviously LPGs are probably going to be trading lower than crude for a while.

Thomas Nimbley

Yes, and of course that’s a seasonal percentage. It’s going to go up as butanes come out of the gasoline pool in the summertime, and it’ll come down, and you’ll see pronounced shifts in the capture rate associated with that. It’s about 4%, 4.5% when butane is out of the gasoline pool on the east coast, a little bit more than than in Toledo, running a lighter crude slate than we see, and it drops off about a percent as you move into the wintertime season.

Ed Westlake – Credit Suisse

Okay, I’ve probably taken up enough time, but that’s very helpful. Thanks very much for thinking about capture rates.

Operator

Your next question comes from the line of Robert Kessler representing Tudor Pickering Holt. Please proceed.

Robert Kessler – Tudor Pickering Holt

Hi, good morning. I’m assuming at the current spread between Bakken and Brent, that you’re incentivized to not only maximize your own rail intake through your vertically integrated system but also look for others who might have availability. To that end, is that an accurate comment, and do you see other third party terminals coming up kind of online with expectations, and would you be looking to buy more cargoes there?

Thomas O’Malley

Let me answer that question, first of all with regard to Delaware. We have enough capacity in the terminal in Delaware to service all of the needs of Delaware. We really can’t run more than 100,000 barrels a day of Bakken at Delaware, so that clears that.

With regard to our refinery over at Paulsboro, we do take on an opportunistic basis barge delivered barrels of Bakken. These come out of other terminals on the east coast. Of course, I think everybody knows there’s a very large terminal up in Albany, New York, and we certainly have taken material in from there, and there are a couple other locations where it comes in. So that—we keep track of all that.

We are expanding, as Tom indicated in his remarks, our ability to take in Bakken crude oil, up to about 125,000 barrels a day, so that to the degree we can source that crude oil and use it over at our Paulsboro refinery, it’s a much more economic move than taking it from third parties. There’s a very small cost involved in barging that material from Delaware over to Paulsboro, and our costs into Delaware are, we believe, lower than anybody else on the east coast. So we’re looking really to cover that corner of the business with our own facility, but that extra capacity won’t be up and running probably until April, May of this coming year.

Thomas Nimbley

I would add that we’re going to probably run—we can run 100,000. Probably with the Canadian differentials, when we start up the coker, we’ll probably run Delaware at around 90,000 barrels a day of Bakken. If we deliver 105, which is our capability, and with these economics we’re going to strive to do that, we do have this permit capability to trans-ship, as Tom mentioned, from Delaware over to Paulsboro. That’s a 45,000 barrel a day opportunity, so we’ll move every barrel, notionally 15,000 barrels a day, over to—or 20,000 barrels a day over to Paulsboro.

We are also, however, periodically putting in barge cargoes to Paulsboro out of places like Albany if the prices are there, and as these differentials move out, they’re going to be there relative to some of the alternatives.

Thomas O’Malley

Yes, I want to interject here that I think when looking at us as opposed to looking at the other east coast sweet refiners, you should recognize that we will bounce back and forth. I think two weeks ago, we had a Basra cargo – this is an Iraqi crude of 500,000 barrels offered to us. Tom, I think the number was—was it $11 under Brent or something like that?

Thomas Nimbley

$10.90 under Brent.

Thomas O’Malley

$10.90 under Brent. Well, suddenly that became more interesting to us than moving Bakken at—which in the same time frame might have been $3 or $4 under Brent. So we—the advantage we have is that we can shift back and forth between a higher sulfur crude. If you’re a sweet refiner on the U.S. east coast, if you’re a COP Delta or a PES, and a Basra cargo appears, you can’t run it – it’s just that simple. So it is giving us added flexibility.

So exact modeling is really for us a function of what offers the largest discount at that moment in time, and what does our LP say about the recovery.

Thomas Nimbley

One other thing – I mentioned these light-sour blends, distressed crudes, and I didn’t give you that we’re starting to procure and we intend to move in by rail. I didn’t give you any numbers on it, but if you look at the differentials right now, that crude, which is a 36 degree API crude so it’s quite a bit—you know, Bakken is 41, WCS is 21, so it’s a pretty high quality crude. But it’s trading right now at $24 under Brent, and—

Thomas O’Malley

That’s on an FOB basis.

Thomas Nimbley

On an FOB basis, but we think we’re going to land in with less than sub-10 or maybe around $10, you’re getting—you have right now in this market the opportunity to get a pretty high quality crude at a very big discount, and again, that is an advantage of our facilities versus the other east coast facilities simply because we can handle the sulfur.

Robert Kessler – Tudor Pickering Holt

And what basin is that coming from, that higher sulfur crude?

Thomas O’Malley

It’s Canadian light-sour.

Robert Kessler – Tudor Pickering Holt

Okay.

Thomas O’Malley

I’d just throw one other thing, and again for the listeners, I think it’s interesting and it is symptomatic. We took—we have an isthmus cargo coming in. Back in the, I think it was Premcor days, we owned this refinery. I don’t recall that we ever had an isthmus cargo. How did this happen? What’s happened is the bathtub has filled up on the Gulf Coast. The Gulf Coast is starting to take in more sweet barrels – in essence, there are refineries down there that can run sour but they’re finding that the sweet economics are better, and they’re backing out some of the lighter sour crudes that they were previously taking in. We’re a beneficiary of that, and that goes back—and in my thinking about it as a shareholder of this company, I look at this sea change in the Atlantic basin from the guys over in Europe having a crude oil cost advantage to the change of, gee whiz, the guys in North America now have a real advantage. We’re going to be the exporters to over there, as opposed to them being the importers to the United States. It’s just—you know, we’re seeing things that we certainly wouldn’t have forecast as short a time ago as six weeks or eight weeks.

The bathtub is really filling up, and I think North American refiners are in for a pretty good sprint. Now, when I say that, I do talk about the east coast, the Gulf Coast, and the midcontinent. My knowledge of AB32 on the west coast would preclude me from making an intelligent comment about that.

Robert Kessler – Tudor Pickering Holt

Okay. Can I come back real quick to the bitumen comment around taking undiluted bitumen at a discount to WCS? Can you give us some magnitude on what level of discount you’re getting that for on a laid-in basis?

Thomas O’Malley

Tom?

Thomas Nimbley

Yes, basically it depends on the bitumen, but just to give you—we run Peace River bitumen that we’re buying at notionally on average, I’d say, as much as an $8 differential lower than WCS, and maybe it costs us $4 for additional transportation, and there’s really not—hardly any quality debit because one of the things you do when you make WCS is you put effectively gasoline into WCS to blend it up to 21 degrees, and particularly in the summertime there’s not much value for that light straight (indiscernible) because you have a difficult time getting it into the gasoline pool.

So we’re probably making an incremental $2 a barrel on—in the current market structure on the bitumen by taking that directly in with our coil and insulated cost.

Robert Kessler – Tudor Pickering Holt

That’s great. Thanks for the detail.

Operator

Your next question comes from the line of Jeff Dietert representing Simmons. Please proceed.

Jeff Dietert – Simmons

Good morning. I apologize if I missed this, but I only saw the refining gross margin for total company in the press release. Again, apologize if the east coast and Toledo is in there, but could you break those out individually?

Thomas Nimbley

Toledo gross margin was $6.97 a barrel. The east coast was $3.66 a barrel.

Jeff Dietert – Simmons

Okay, thank you. Secondly, if you look at Canadian heavy differentials, and there is clearly good visibility to production growth there, the Keystone northern gateway, trans-mountain all struggling with environmental and political objections. Alternatively, the Keystone south and Seaway Twin lines will probably take more Canadian heavy to the Gulf Coast, and BP Whiting is shifting towards Canadian heavy with their crude unit. Could you talk about how all these factors influence the outlook for Canadian heavy discounts in 2014?

Thomas O’Malley

Let me try and take that. I think first of all, the comment that a lot more Canadian heavy is going to move south may not be accurate. What we’re starting to see as we get down to the Gulf Coast is that the Gulf Coast is being filled up with additional U.S. domestic production, and we’re backing out now. We’ve already backed out on the Gulf Coast virtually every barrel of imported sweet crude. Now we’re starting to back out some of the medium gravity crudes. I don’t think there’s going to be a giant additional flow down to the south. My own comment with regard to the pipelines, particularly XL, the northern portion of it, if the Obama administration hasn’t made a positive decision on that pipeline at this point, well, I think you can be relatively sure that no positive decision will be taken prior to the next Congressional election, which is a year away, and then trying to get the thing in place with the environmental lobby still against you would add years to it. So we’re not particularly concerned about pipelines at this moment in time.

I think it’s a function of how fast this additional Canadian production comes on. It’s frankly been a little bit slower than we thought it was. I think everybody is aware that Exxon giant project up there was delayed a little bit, but it’s all coming forward. So we see on average larger discounts in the coming year than we saw on average on 2013. Quantifying them is—I wish I was so smart. I don’t think we can quite get there, but we see a better situation for us in this coming year than we had in the past year.

Jeff Dietert – Simmons

So with pipeline challenges, it’s more comparison of the pace of Canadian production growth and the pace of rail loading capacity growth in Canada as far as a big influence on differentials?

Thomas O’Malley

Yes, I think the rail capacity we have our arms pretty well wrapped around. We are a reasonably large offtaker by rail already. The projects that are coming onstream should allow us to reach the goal of 85,000 barrels a day of Canadian heavy. We’ll have our discharge facility in position a little bit before midyear. We’ll have the rail cars, which is another huge issue, the modern rail cars to carry this crude. We’ll have sufficient in place certainly by the end of ’14 in our own fleet, and a very—probably enough to take the 80,000 barrels a day with the leased cars that we currently have, which will go off lease, thank God, because those cars, while the heavy cars that we’ve bought come in at a little bit less than $1,000 a month, the leased cars, some of which we’re using at the present time, are $2,000 to $3,000 a month. That makes a big difference, and that’s why we’re going to have better economics next year also with more of our own cars.

Jeff Dietert – Simmons

Thanks Tom.

Operator

With no further questions at this time, I would now like to turn the call back to Mr. Tom O’Malley for any closing remarks.

Thomas O’Malley

We just want to thank everybody for attending the call, and we sincerely hope that the market gives us a better opportunity in the fourth quarter than it did in the third quarter. Thank you for attending.

Operator

Thank you, sir. Ladies and gentlemen, thank you for your participation in today’s conference. This concludes the presentation. You may now disconnect. Good day.

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PBF Energy (PBF): Q3 EPS of -$0.48 misses by $0.36. Revenue of $4.85B beats by $0.33B. (PR)