PBF Energy Inc (PBF) 2014 Q4 法說會逐字稿

Welcome to the PBF Energy fourth quarter 2014 earnings conference call and webcast. (Operator Instructions) It is now my pleasure to turn the floor over to Erik Young, Chief Financial Officer. Sir, you may begin.

Thank you. Good morning, everyone, and welcome to our fourth quarter earnings call. On the call with me today are Tom O'Malley, our Executive Chairman; Tom Nimbley, our CEO, and other members of our management team. A copy of today's earnings release, including supplemental financial and operating information, is available on our website, pbfenergy.com.

Before we get started, I'd like to direct your attention to the forward-looking statement disclaimer contained in today's press release. In summary, it outlines that statements contained 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 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 are useful but they are non-GAAP measures and should be taken as such. It is important to note that we will emphasize adjusted fully converted earnings information and results excluding special items.

Our GAAP net income, or GAAP EPS figures, reflect the percentage interest in PBF Energy Company, LLC, owned by PBF Energy Inc. which averaged approximately 90.1% during the fourth quarter. We think adjusted fully converted net income and EPS are two more meaningful metrics to you because they present 100% of the operations on an after-tax basis.

Before discussing our results, I'd like to take a moment to review the non-cash, lower of cost or market, or LCM, inventory adjustment that we recognized in the quarter. This GAAP adjustment is driven by the accounting requirement to carry inventory on our balance sheet at the lower of cost or market prices. The historical LIFO value of our inventory has been established in a relatively high-flat price environment since we acquired our three refineries in 2010 and 2011 and hydrocarbon prices until the second half of 2014 have been in a relatively stable band for the past few years.

With the rapid decline in hydrocarbon prices since the end of the third quarter 2014 we were required to adjust the book value of our inventory to reflect market prices as they were lower than our LIFO cost. This is what generated the $412.7 million after-tax, non-cash inventory adjustment in the quarter. It is important to note that we assess our inventory for the potential of an LCM adjustment on a quarterly basis and future movements, up or down, of hydrocarbon prices could have a non-cash positive or negative impact to our reported earnings.

For the purposes of today's call, the comments we make in regard to our results will exclude the impact of the non-cash LCM inventory adjustment. With that, I'll move on to discussing our fourth quarter results. Today we reported fourth quarter operating income, excluding LCM, of $208.6 million and adjusted fully converted net income for the fourth quarter of $104.8 million, or $1.13 per share on a fully exchanged, fully diluted basis.

This compares to operating income of $142.3 million and an adjusted fully converted net income of $73.6 million, or $0.76 per share for the fourth quarter of 2013. Excluding LCM, adjusted EBITDA for the quarter was $255.9 million and just north of $1 billion for the full year. This compares to adjusted EBITDA of $173.7 million for the fourth order of 2013, and $399.3 million in adjusted EBITDA for the full year 2013. Adjusted EBITDA for 2014 was more than double our 2013 results and our East Coast system generated more than 60% of our total refining EBITDA.

Our results for the quarter and for the year reflect our strong operational performance and highlight the improved crude optionality and flexibility we can now demonstrate with our coking refineries on the East Coast. Product margins were resilient for our East Coast system as New York Harbor Jet and ULSD traded at significant premiums, averaging almost $6 per barrel over heating oil in the quarter and we were able to capitalize on the strong margin environment.

Additionally, we realized improved margins on our lower value products as a result of the decline in crude prices. As we have mentioned on previous calls, we maintain a basis management program for the majority of our East Coast crude oil inputs. As an example of this hedging strategy, when we purchase crude on a WTI basis and sell the products in a Brent-based market we enter into a Brent-TI contract to establish the differential.

In the fourth quarter, we recognized a $44 million benefit as a result of the narrowing WTI-Brent and ASCI-Brent spreads. We had approximately $26.3 million of RINs expenses in the fourth quarter and $115.7 million for the year. As with others in our industry, we are awaiting the final rulemaking for the year behind us, as well as any guidance that can be provided by the EPA for the year ahead obligations.

For the fourth quarter, G&A expenses were $39.7 million as compared to $24.4 million a year ago with the primary differences relating to higher employee costs in 2014. Depreciation and amortization expense was $44.5 million versus $29.9 million in 2013. For the year, depreciation and amortization expense was $180.4 million versus $111.5 million in 2013. Included in the 2014 figures is a one-time charge of $28.5 million associated with the write-off of the abandoned hydrocracker project we mentioned on our last earnings call.

The remaining increase year over year is related to a number of assets that were placed in service during 2014. Fourth quarter interest expense was $22.9 million compared to $24.2 million last year. PBF's effective tax rate for the period was impacted by the LCM adjustment and other items and is not reflective of our future expected effective tax rate. Going forward, for modeling purposes, you should assume a normalized effective tax rate of approximately 40%.

At the end of December, our cash balance was approximately $632.8 million. PBF ended the year with liquidity of over $1 billion. Excluding the impact of LCM, our net debt to cap ratio was 23%. We received approximately $150 million in net proceeds from the sale of the Toledo storage facility to PBF Logistics in the form of $135 million in cash and $15 million in PBF Logistics common units.

For the year, PBF Energy received approximately $600 million in net cash proceeds through transactions with PBF Logistics including the May IPO. For the quarter, refining and corporate CapEx was approximately $174.5 million. Refining and corporate CapEx year for the year was approximately $357.8 million. At the end of the year, we had approximately $70 million of PBF-owned railcars.

For modeling our full year operations, we expect refinery throughput volumes should fall within the following ranges. The East Coast should average between 310,000 and 330,000 barrels per day and the Mid-continent should average between 150,000 and 160,000 barrels per day. For the first quarter of 2015, the refinery throughput volumes for the Mid-continent should average between 130,000 and 140,000 barrels per day. The East Coast should average between 320,000 and 340,000 barrels per day.

We expect our operating costs for the year to range between $4.50 per barrel and $4.75 per barrel. G&A expenses should be in the $100 million to $120 million range. Depreciation and amortization should be in the $180 million to $190 million range, and interest expense should be about $100 million to $110 million for the year. For 2015, we expect CapEx including turnarounds but net of railcar purchases to be approximately $175 million to $200 million. This is a reduction of about 30% to the CapEx guidance we provided in early January.

Tom Nimbley will provide additional color on our CapEx program later in the call. During the quarter, we continued to be active with our share repurchase program and have repurchased a total of 5.7 million shares. We have roughly half or approximately $155 million of the current repurchase authorization remaining. Combined with $115 million in dividends, PBF returned approximately $270 million in cash to our shareholders in 2014.

Our Board has approved a quarterly dividend of $0.30 per share payable on March 10 to shareholders of record as of February 23, 2015. At this time, PBF's dividend policy remains unchanged. In addition to the financial recap, I would like to comment on a few notable items that occurred during the fourth quarter. In December, we successfully completed our second asset drop-down consisting of the Toledo storage facility to PBF Logistics. This transaction provided PBF with additional resources to grow the Company and return value to our shareholders.

Finally, last week, Blackstone and First Reserve, our original private equity sponsors, sold the remaining stake in the Company and we are pleased to report that we are completely independent with all of our shares held by the public, management, and our Board members. I'm now going to turn the call over to Tom Nimbley for his comments.

Thank you, Erik, and good morning, everybody. Excluding the non-cash LCM adjustment Erik eloquently described, PBF had a good year, not without its challenges but very positive, nonetheless. We accomplished quite a lot in the last 12 months even during times when the market was not always a friend to refiners, whether that was due to narrower feedstock differentials or lower product margins.

We completed a number of revenue enhancing projects across all three of our refineries. We completed the build out of our East Coast rail system. We successfully launched PBF Logistics and we completed one of the largest turnarounds ever undertaken at our Toledo refinery. Probably our biggest success of the year, and it happened over the course of four quarters, was the emergence of the earnings potential of the East Coast. The East Coast contributed over 60% of our refining EBITDA for the year.

We understand that one year does not establish a trend but we view the performance of our East Coast system in 2014 as a direct result of the optionality that we have built into our system in terms of being able to source inland and waterborne crude oils. Because of our coking ability on the East Coast, we are able to run any type of barrel: light sweet, medium, heavy, or sour, and realize the benefit from converting the bottom of the barrel.

The ability to run virtually any type of barrel or mix of barrels gives us a tremendous advantage on the East Coast, as we are not locked into a single type of crude and can be flexible in buying the most economic mix of crude oils to run through our system. Before continuing on to the fourth quarter results, I would like to provide an update on the now completed turnaround in Toledo. As I said a moment ago, this was one of the largest maintenance events that I have seen in my 40-year career, and for the most part, we are pleased with how our team performed.

This plant-wide effort took a little longer than expected and we spent a little more than expected in completing the work. But the refinery is now in much better shape than it was. In the aggregate, we spent about $175 million over the course of about 41 days, about $40 million more than planned as a result of some additional discovery work seen during the turnaround and additional work incurred during startup.

It is important to note that the margin enhancement projects installed during this downtime account for approximately 45% of the total spend and are expected to provide full-year EBITDA benefits of about $75 million. During the turnaround, we also installed tie-ins for the completion of a chemical expansion project which we expect to put in service in July of 2015. After completion of this project, we expect to realize the full benefit of all of our return projects.

As Erik mentioned a moment ago, we have reduced our expected capital expenditures for 2015. This is primarily a result of the hydrogen plant project at our Delaware City refinery which we now expect to be funded by a third party. This is an attractive project, we will be going forward with it, but we will use a third party to fund it. We are also beginning work on our Tier 3 compliance projects, which I should point out, is stay in business CapEx.

However, in addition to lowering gasoline sulfur content to the required levels, our creative engineers have identified an opportunity to introduce a return element to our Tier 3 spending by increasing our chemicals yield on the East Coast. Returning to the fourth quarter operations, we cannot possibly discuss results without commenting on the impact of the rapid decline in commodity prices on our operations.

Perhaps the most significant market movement in the quarter was, of course, the overall decline in the flat price of crude oil. WTI averaged almost $74 a barrel in the fourth quarter versus $98 in the third quarter, an almost 25% decrease. Brent averaged $77 during the quarter versus $102 during the third quarter. WTI ended the quarter at about $53 per barrel, close to half of the third quarter average. Similarly, Brent finished the year at $55 a barrel, again, close to half of its third quarter average.

Most of this magnitude create both lasting and momentary opportunities in the products market. In particular, PBF's East Coast was able to take advantage of wide differentials in the quarter for distillates and the lower flat price increased our margin across the bottom of the barrel. Due to the lag in pricing in the asphalt business, PBF was able to realize a significant benefit in the fourth quarter on this traditionally lower margin business.

This should stabilize as crude prices reach some sort of equilibrium and could even go the other direction if commodity prices go back up. I should say, however, that overall, refiners, especially complex refiners, benefit from a low flat price environment. Our realized margin increases as the relative value of our low-margin products increase. During the quarter, throughput for our overall system was about 415,000 barrels per day with the Mid-continent averaging approximately 75,000 barrels per day and the East Coast system approximately 340,000 barrels per day.

For the quarter, operating cost on a system-wide basis averaged $5.26 per barrel, $4.66 per barrel on the East Coast, and $7.99 a barrel in Toledo. Toledo's operating costs, of course, were higher during this quarter due to the turnaround, but we expect them to come back into range now that the work is complete. We feel that the system-wide operating costs reflect our relatively stable operations but also reflect the benefit of our proximity to the Marcellus Shale and lower cost natural gas.

Results for our Toledo refinery are a bit skewed in the fourth quarter as a result of the turnaround and the specific market conditions during our period of operations. The Mid-continent 4-3-1 crack spread averaged $11.44 per barrel, a decrease to the 2014 third quarter average of $16.63. Our margin at Toledo was $8.70 per barrel for the fourth quarter versus $16.73 in the third quarter.

As a result of the turnaround, Toledo was only operational during the latter half of the quarter which also happen to coincide with the worst margin period. The 4-3-1 averaged $5.29 per barrel in December. Despite the turnaround and the late quarter market conditions, the Toledo refinery managed to contribute some marginal EBITDA in the quarter. The Brent 2-1-1 East Coast crack averaged $11.80 per barrel, down slightly versus the third quarter of $13.91, but still seasonally strong and very resilient given the move in flat prices.

The refining margin for our East Coast system was $13.19 per barrel versus a margin of $10.61 in the third quarter. Our margin on the East Coast was, again, favorably impacted by the continued decrease in the flat price of crude and by the sales of barrels in excess of production out of inventory. For the quarter, we processed approximately 82,000 barrels a day of light crude oil and about 49,000 barrels a day of heavy crude that Delaware City delivered by rail.

If you are watching the differentials, as we are, then you will have noticed that as the flat price of crude oil has declined some of the differentials have compressed. In our business this is all relative. We pursue the most economic barrels for our system and sometimes those barrels will be rail delivered and sometimes they will come in by water. It is our ability to be flexible in sourcing that allows us to maximize our use of advantaged crudes.

In the fourth quarter, we saw some very profitable opportunities in the medium-sour waterborne market. As you would expect, if we are seeing opportunities on the water that probably means we are curtailing our rail deliveries until those prices become more economic. As the markets remain tumultuous, we are relying on the sourcing flexibility that we have now built into our system to provide some resilience in our feedstock procurement.

Our rail delivered crudes are more resilient than the spot prices would indicate due to our supplier relationships, and our abilities to substitute in waterborne barrels for marginal rail-delivered barrels allows us to continue to shift to the most economic crude slates for our refineries. It is this ability to pursue the most economic raw materials that we believe provides us with a competitive advantage versus other PADD 1 refineries.

Before turning the call over to our Chairman, I wanted to highlight again the strong performance of our East Coast refineries in 2014. Our East Coast system, as we said, has contributed over 60% or about $700 million of refining EBITDA for the year. The performance of the East Coast shows at least over the course of the last year that the flexibility and complexity of our system works and can deliver strong results.

Lastly, we have talked a lot about acquisitions over the past year and I would like to comment on our approach. As a Company, we look at a large number of assets, both on the refining side and the logistics side, and we are participating in a number of processes. It is important to understand that these are processes that sometimes involve many parties and take time and the willingness to complete the deal on both sides.

When we are involved in these processes, we evaluate the assets using our own operating and market assumptions to determine a purchase price that would make an acquisition accretive to PBF. We have put forward a great deal of effort to create a strong Company and balance sheet and we will not jeopardize that work by overpaying for an asset. It is our intention to grow the Company through acquisitions, and we are confident that in time we will be successful on our terms. I would now like to turn the call over to our Executive Chairman, Tom O'Malley.

Thank you, Tom. I'm just going to comment on a few general points. The first being the price of oil and, perhaps, the motivation for the Saudis' action in not sponsoring some type of reduction in production. Our best info indicates that when the Saudis were evaluating this situation, they understood that the price north of $100 a barrel for most crude oils resulted in a decline in consumption of oil products.

Now I suppose if you are a country with 100 or 150 years of production capability and that's your principal export, that is bad news. While there might have been subsidiary reasons in terms of wanting to see lower supply, I think the main issue there was this price constrains the market in terms of consumption. So our own reading of what's going to happen in the marketplace is that we will see some recovery whether that's prompt or in three months or in six months, really, we can't forecast that, but certainly these lower crude oil prices and lower product prices resulting therefrom are increasing consumption.

Obviously, the lower crude oil prices are constraining production. The latest figures published, that came out this morning, I believe, indicated a very small growth in US production and indeed that growth is going to be reversed in my opinion in the months to come. Certainly, other productive areas, offshore deepwater, the Gulf of Mexico, is going to be very difficult at these numbers.

I would imagine that Brazil will have a hard time developing its reserves, and there certainly others places in the world where we're going to see a contraction. So ultimately, those old economic laws of Adam Smith, supply and demand, will come into play. In terms of the environment for particularly US refiners with heavy crude oil capacity it looks bright to me. Heavy refiners benefit from lower crude oil prices across the board, and certainly our industry in the US will benefit from an increase in consumption of oil products, and we believe that increase has already started.

As I look at the beginning of this year, and our industry, and I compare it to the beginning of last year, I think we're way in front of the curve. It looks like refining is well set up. We still have a price advantage in the United States on crude oil, reflected to some degree in the Brent-WTI differential, which I don't expect to reach heroic differentials out there of $8, $10 or $12 a barrel, but I think we will probably be resilient in the $4 to $6 range. That basically talks about crude somewhere in the $50 to $60 range for Brent.

The market seems to have shaken out a bit. We have seen some up and down over the past days, but that's not what we can focus on, and I suppose it's not something an investor should focus on. I'd like to finish with one comment, and it is a general comment, and it's about RINs. We indicated in our presentation that we spent about $115 million over the course of 2014 covering what we believed was our RINs obligation with the US government.

The action of the various agencies within the government reminds me a bit of the Keystone Cops. How can it be possible that an industry as large and important as ours does not yet have from the government something that they were obligated to give 15 months ago in terms of what do we have to buy to comply with your regulations.

If you look at this across the spectrum of our industry, this is once again a bit of a boondoggle, probably this year or in the year 2014 in excess of a $4 billion tax on the American public on energy products. That is a little sour grapes, but I don't mind winding up with that. And we would now be pleased to take whatever questions you have. Thank you.

(Operator Instructions)

Mohit Bhardwaj with Citi.

Thanks for taking my question. Tom, I just had a question on the CapEx guidance that you had provided.

It seems like a majority of the CapEx beyond the rail costs this year is the sustaining CapEx. And in your most recent presentation, you guys have talked about increasing EBITDA by at least $130 million through additional projects in 2015. If you could just talk through that, how the two numbers jive up?

Tom, you take that.

Yes, thanks for the question. The reality is, the shift from using, when we put our original CapEx forecast together, we had contemplated building the hydrogen unit at the Delaware City refinery ourselves. When we went through the economics on that, it is clearly more attractive to use third-party money to get that built and pay a tolling fee, and allow us to still get most, if not all, of the benefits of what that project would have done if we built it with our own money.

To put it in perspective, that project is expected to generate -- that project alone is expected to generate between $75 million and $95 million a year of EBITDA once it is complete. And the range there is, frankly, a function of what the flat price of crude is. Even though we have decreased our CapEx guidance, we would not expect to have a significant and, frankly, only a marginal impact on the return elements and the EBITDA contributions mainly because we're using somebody else's money to build the biggest investment.

The reason that range exists is one of the things the hydrogen plant us is basically, because we're short hydrogen in Delaware on the East Coast, it is a gas to liquids project. It actually increases volume swell in Delaware, we make more products than we buy, and if the price of crude is $60 it is worth something, if the price of crude is worth $100 it is worth more. Wouldn't expect to see much of an impact on EBITDA at all.

Great. And, Tom, if you could just tie in with the comments that you made regarding acquisition, is it like leaving more cash on the balance sheet if the opportunities arise as you are in multiple processes?

We are looking at a number of opportunities. We are going to protect the balance sheet, there's no doubt about that, but our balance sheet is strong. We have now basically gotten to the point where we have absorbed three refineries, we have built out our infrastructure in the back office and in Parsippany and have a vibrant commercial operation.

So we are in a position where we will pursue -- we are pursuing and we expect to do acquisitions, both for the parent Company and the Logistics Company, but we just simply will not buy something just to buy it. We are seeing different models show up, there are different players in the field that we are looking at or we're competing with and we're evaluating how to respond that. But we won't compromise our balance sheet.

But with the number of opportunities, and Tom may comment on this thing, there are a lot of assets that are on the market and more likely are going to come. And we feel very comfortable and confident that we will be able to get an accretive acquisition.

Let me just add a comment. The alternative we always have is buying our own shares. And when we evaluate the quality of the assets that we have within the Company and we look at the marketplace for assets that are being sold, it certainly has been a bit of a toss-up. We might be better off taking in additional shares from our Company.

So that is kind of how we evaluate everything going forward. Careful with the balance sheet, look at everything that is available in the marketplace, in North America, and try and figure out what the best way is to spend the shareholders' money.

Very clear, Tom. And one final one, if I may.

Tom, you guys usually provide some guidance on rail volumes. You were referring to this aspect before that you're probably getting more barrels -- the medium-sour barrels from offshore deliveries. If you could just give some numbers on that, that would be great.

Okay. Again, we cannot overemphasize the benefits that we see from having the complexity to handle any barrel basically that is being pretty much produced in the world. But right now the economics have shifted, as you are well aware.

If you take a look at heavy crudes out of Canada and the ARB is closed, not only to the East Coast by rail, but, frankly, the ARB is closed to the Gulf Coast in the United States by pipe. So we have switched over because we have much more economic options running medium and heavy-sour like [Meyer] and M100, et cetera.

That being said, we're still running a fair amount of heavy crude for the first quarter, we will see what the market does in the second quarter. As I just said, frankly, in April the ARB, based on today's prices, is not open. Bakken, we slowed down our Bakken purchases again because of economics, and it is very important that you all understand that one of the reasons we slowed down Bakken purchases by rail because we can run a South American sour crude that makes a lot more money for us.

The other refineries in the PADD 1, their option, because they're light sweet only, is to substitute Bakken for a West African barrel and that simply not as attractive. But we did slow down some Bakken, however, right now the Bakken is -- the ARB is starting to open up and we have done some deals.

Again, you should always keep in mind, don't look just at the index pricing, we have supplier relationships in the Bakken that will allow us to benefit from some better economics. And right now we're actually starting to see that ARB opened up. But it will be a function of what the actual prices are over the course of the next two months or three months.

Thank you.

Paul Sankey with Wolfe Research.

Hi, good morning, everyone. Could you just talk a little bit more about your CapEx in Q4? I'm not totally sure what's in that very big looking number. I think it is related to rail.

Could you talk a bit about who loses out from your optionality, that is to say, if you decide not to rail crude, but rather to bring it in waterborne, is it harming to your logistics side or is it someone else that loses out on the revenues that would be gone from the rail trade? Thanks.

Paul, it is Tom. I'll take the second question, Erik will take the CapEx piece of this.

We have take-or-pays with the Logistics Company, the parent Company is required to and does meet those take-or-pay commitments. So the Logistics Company will not be impacted by that. They will get the minimum buying commitment.

We, obviously, have costs associated with the rail unloading facility, whether it be on the light sweet, the loop track where we do the light, or the West rack where we do the heavies. And those costs are notionally $2, $2.20 to unload, but they are factored into the economic evaluation that we do.

And even with those costs, the spreads that we are seeing on a delivered basis for the heavier medium-sour crudes, waterborne crudes, make it clear that the best proposition for PBF, even having to adhere to those take-or-pays, is to switch over and run those waterborne crudes.

Are you public on what the take-or-pays are?

Erik will give you the actual --.

For the Logistics Company, absolutely, we have minimum volume commitments on the double loop track at Delaware City, as well as minimum volume commitments on the West Rack that is also located at Delaware City.

And it is 85,000 barrels a day on the double loop track, that is the sweet side, and 40,000 barrels a day on the West Rack on the heavy side.

And, Paul, with your question regarding CapEx, the gross CapEx for the quarter was $300 million. We did sell, included in that is approximately $126 million worth of CapEx related to rail car purchases. So if you remember, we are taking delivery of our railcar fleet over a period of time.

We will be finishing up railcar deliveries based on current estimates the first half of this year. So we spend $126 million of the $300 million on railcars, and then we subsequently did various sale/leasebacks throughout the quarter and generated net proceeds from those leases of $128 million. So the net CapEx is about $170 million to $175 million in total.

There will be a timing difference that we will see when we buy these railcars because we are packaging the railcars into, call it, between 200 and 500 cars at a time. And then ultimately go into the leasing market versus just flushing a railcar through the system and then leasing them in 10-railcar lots.

Paul, just to keep it simple, we spent $175 million during the quarter at Toledo. If you take the $125-million-odd of sale/leaseback on the railcars, you simplify the whole thing. And it's not much more than we forecasted with the exception that we had to spend more in Toledo than the original budget.

Okay, you've broken it down for me there. Thank you.

Manav Gupta with Morgan Stanley.

Congrats on the great East Coast routes, guys. My question is, are the East Coast assets now where you would have liked them to be when you IPO'd back in 2012? And do you see further scope of improvement in these assets? They are performing well, but is there further scope of improvement in any projects you could highlight which could further increase the capture on these East Coast assets?

Tom, I will just take that. We're satisfied with where the East Coast assets are. They are performing at the present time beyond our original model. Certainly, Tom has already outlined for you the addition of a hydrogen plant at the Delaware City refinery which will add to the EBITDA somewhere between $75 million and $100 million.

He also mentioned in his opening remarks an improvement in our chemical yield over at the Paulsboro refinery which, again, should add something to the EBITDA. But really as a general remark across the industry, and certainly as it refers to PBF, we always try to discover new projects. We don't have a great deal of new projects in the investment budget for the East Coast because we think the East Coast system now is very mature. But that doesn't mean that six months, nine months, a year from now we might not come up with a project.

In general, however, the philosophy within this Company is we don't want giant projects that come to fruition three years from the time that you indicate you are going forward. We're really focused on what can we improve in three months, in six months, in nine months, in a year. What is very resilient, for instance, a hydrogen plant. So that is the kind of thing we are after, but you should view it now as a very strong system, in fact, in my opinion, by far the strongest system on the US East Coast.

I have a follow-up and that is, any views on the USW strike? You are, obviously, not in the 11 refineries currently impacted by it, but just trying to understand, if the strike spreads to other refineries could you also be impacted in any way?

Tom, take that.

Okay, very good question. The short answer is, we will not be affected by a spread -- if the strike spreads.

Last year, not necessarily anticipating the strike that is underway right now, we had, we were preparing for the Toledo turnaround and we didn't want to be in a position where we would have to be spending a lot of our resources on strike preparation, which you would have to do because of the contract terminating at the time that it did.

So we actually settled with all three of our refineries early, and we gave basically what is called a me too. We settled all local issues with Paulsboro, Delaware City and Toledo. And when, and we hope it is soon, that the USW settles with the industry, whatever the wage settlement is, health benefits, et cetera, we will give a me too to our refineries. What we got for that, of course, is two things.

One, the USW, or all three refineries -- one of our refineries in Paulsboro is not USW -- but all three refineries cannot strike and we cannot lock out any of the employees at any of the three refineries. From that vantage point, we are insulated, we cannot be struck at this particular time. But, again, we hope that wisdom prevails here and Shell, who is the lead negotiator for the industry in this time around, is working hard and hopefully they will come to a sufficient, satisfactory resolution soon.

Last question, guys, you have been very strong advocates of not lifting the crude exports ban, while six months to eight months back everybody was talking about it, and it was kind of being said that this could happen very soon. Now it looks like it is -- it is not probably going to happen. So any views on it, and do you still see that as any kind of near-term risk?

This is Tom O'Malley. We view it as a non-issue, plain and simple. I viewed it, frankly, as a non-issue six months, nine months ago. We are getting ready for the eternal election cycle here in the United States, and there is nobody that is going to do anything in the political world that is going to raise the price of gasoline to the American consumer.

And if you remove the export ban you are going to raise the price of gasoline to the American consumer. And, frankly, one of the things the USW probably should be focused on and they certainly want and should maintain a strong employment level within the refining industry. And one way to do that is to certainly be totally opposed to the export of crude oil.

Thanks, guys, and congrats on the great quarter.

Ed Westlake with Credit Suisse.

Hello, sorry about that. Can you hear me?

Yes.

All right, I was on a closed line, apologies. A couple of questions then, New York -- congratulations on the 4Q numbers, very strong adjusted EBITDA. Just a sort of a structural change, obviously, there are some timing benefits.

But it does feel in the second half last year that the Northeast products market was stronger than perhaps even the Gulf. And I'm just wondering, do you think there's any structural changes? Obviously, since the great financial crisis we've had a lot of closures in the region.

The people who import into the region are perhaps from Europe higher cost. I'm just trying to get a sense of how you think the strategic environment shapes up in the East Coast relative to perhaps perceptions four years or five years ago?

Tom, I will take that. Look, first of all, the East Coast has historically been a premium market to the US Gulf Coast. If you look at average over the years you have $0.04 or $0.05 a gallon premium on the East Coast. It really reflects the Colonial Pipeline tariff. That is item number one.

Item number two, and I hate to say this because it does come a bit around to the Wall Street industry. Many of the players in the past were in essence financial institutions, for instance, Credit Suisse, Morgan Stanley, JPMorgan Chase, et cetera, et cetera. And to a great degree they have exited the oil trading market. And people have become a bit more dependent on domestic production.

When the ARB opens, there's not someone there at every moment instantaneously to take advantage of it. Certainly, we have seen some rationalization on the East Coast over the past years, that has played into it.

We've seen some rationalization in Europe, certainly, that has been a difficult environment to make a profit. And the traditional cross-Atlantic ARB going from Europe to the United States has to some degree closed in many cases. And indeed, it reversed, so that you will get the Gulf Coast frequently now exporting to some places in Europe and not pushing the product up here.

I think the other thing that has happened, the terrific competitiveness on a worldwide basis of the Gulf Coast refinery system has kind of moderated the previous, oh well, we will put in the Colonial Pipeline and send it up north, even if the NETPAC doesn't work particularly well. Now it seems we will load it on a ship and send it to Brazil, perhaps we will send it to Chile, perhaps will send it to wherever. That has changed.

I do see a long-term change in the profitability and resilience of the remaining East Coast refineries.

Ed, I would just add one thing to what Tom said just from a perspective standpoint. If you go back 1970s, PADD 1 always had the product advantage, their Colonial Pipeline tariff or waterborne transportation.

However, PADD 1 was disadvantaged in two key areas. One was cost of crude because pretty much it was bringing crude in from Europe and paying the freight, and on natural gas pricing because buying natural gas in the Gulf Coast and paying the freight.

Well, that last thing is now an advantage because we, frankly, have cheaper gas, or at least at a push with the Gulf Coast, and certainly versus Europe our crude situation has reversed. I do think there are some structural changes that have happened.

Yes, and I was trying to get on the product side because the other ones are out there, but this seems quite an important change. You have improved your assets, you've got the benefit of being a domestic refiner and then the motors that were on products seems to have improved. We will have to see how long it lasts.

Just on a second point, on the secondary products, and, obviously, you talked about it in your opening remarks in terms of that being a benefit. Is there any way to put a number on it on a dollar-per-barrel basis and how much you think of that dollar-per-barrel is sustainable going forward, aka, can you do my model for me? (laughter)

Tom?

You have to break it up. It's going to be a function of different things.

One thing we could say, and I would give you an example, but you're going to have to do your own model, but let's take a look at Delaware City. Delaware City produces 10% coke, sulfur and CO2 in their product stream. That is going to be a sustainable benefit when the price of crude drops.

If we are buying crude at $100, and those products that I just said, sell for on average of about $5. So at $100 you are losing $95 a barrel. And at $50, you are losing $45 a barrel on 10% of your volume. That is a sustainable effect of this lower flat price.

Similarly, both of our East Coast refineries, being coking refineries, actually have a net loss through the system of, call it, 1%. So if we buy 100 barrels of raw material to run through the front door, we sell 99 barrels out the back door. That loss at $100 a barrel is twice as much as it is at $50 a barrel, the debit associated with the buy and contracted. Those are sustainable things.

The asphalt pricing, propane pricing, things, other lower value products, they will tie back to crude and they will move around. And as I said in my comments, we did benefit from asphalt prices lagging. In fact, we had positive asphalt cracks in the fourth quarter versus Brent. That's not going to stay forever, and, in fact, it could turn a little bit if the price of crude starts going up.

Ed, it is Tom. I often have the same question. I have developed, using massive computer skills, a model, okay.

And Tom gave you the 10%. Take 10% of the crude price, multiply that 10% by 90%, so if you take $10 on $100 crude, you get $9. Now go down to $50, take 10% of $50, multiply it by nine and you get $4.50, and that is probably very close. That is probably within $0.25 or $0.30 up or down of the advantage that we are experiencing at the current time with our East Coast heavy crude oil refineries.

And the other East Coast refineries that don't coke are not experiencing that advantage. In essence, what it allows us to do is to recover a greater portion of the available crack. So perhaps instead of recovering 50% of a $15 crack, in this case we would recover 75% or 80% of a $15 crack. That is the nitty-gritty on it and that is my simple, as I said, massively calculated formula.

Thank you very much.

He expects you to pay him a fee at the end of this call.

(laughter) I'll send a check in the post. Thanks very much.

Thank you.

(Operator Instructions)

Roger Read with Wells Fargo.

Yes, good morning.

Good morning.

I would like to, I guess, come back to the question on the East Coast running the heavy crudes. Can you give us an idea, and I'm sorry if I missed this earlier, but the kind of volumes or the percentage of heavy you are able to run at Delaware City? And I presume at Paulsboro we're still looking at all light sweets?

Roger, this is Tom. Paulsboro is not a light sweet refinery, although we do run one still, when the ARB is open for Bakken, the sweet crude unit on Bakken. In fact, we're doing that now because we've been able to source some material in that was distressed cargoes. But the rest of Paulsboro runs medium-sours.

We have a lubes unit, obviously, in Paulsboro. The predominant sourcing of crudes to that still is Saudi crude in the form of Arab light or Arab medium. Right now we have good economics on Arab medium, Isthmus from Mexico, and Basra from Iraq.

That unit, or that facility runs a fair amount of what we call a medium-sours. It will not run things like Meyer or M100.

Delaware has the capability to run 100,000 barrels a day of heavy crude. We don't normally do that, or haven't done that in the past, because, frankly, Bakken has been attractive enough that we have been running 70,000, 80,000 barrels a day, even north of that in Delaware. But as these coconut economics improve, as we've talked about with the drop in the flat price of crude, we are actually heavying up our slate to take advantage of that for the reasons Tom just went through.

The debit of the coke products, coming out of the coke at a low value products has diminished some. We have not seen, at least at this moment, the crude differentials narrowing significantly, so those crudes are quite economic.

Just adding, just so you don't misunderstand. Both refineries can run 100% of their capacity as heavy crude oil, which we would kind of define as something down around a 28-degree gravity and down, and higher sulfur crude oil, that, let's say, on average would have 2% percent or more of sulfur in it.

So the great advantage of this system on the East Coast, as compared with some other refineries on the East Coast, is it's flexibility. And I may state that the somewhat uninformed comments of those who have favored the export of lighter crude oils because, quote, the industry can't process them is utter nonsense. The industry is incredibly flexible, and if you have that heavy capacity, you really can switch back and forth between a heavier barrel and a lighter barrel. So let's be sure you understand both refineries can run everything in the form of heavy, higher sulfur crude oils.

Sure, thanks for that. And then, what is the impact we should think about yield-wise between the switch from, let's say, the extreme of the all light versus the all heavy?

If you go from one end of the spectrum to the other end of the spectrum, you would see perhaps a 1% or 1.5% decrease in clean product, what I call clean product yield, which is basically gasoline distillate, and you would, obviously, produce a little bit more coke. You would produce a little bit more gas.

But, again, we factor that in, that clearly shows up in the model, and what you have to do, you don't make that shift unless you have an economic differential on the raw material that justifies it. But you certainly will if we go all the way to running both refineries on the East Coast with a heavier slate, see a decrease in gasoline and distillate production of the order of magnitude that I spoke to.

Okay. And then, a final question. You talked earlier, or were asked earlier about the M&A market, I was just wondering, focusing more on the refining side, specifically, we saw the Citgo assets more or less get taken off the market.

Are your seeing the market more target rich, less target rich in the refining area? And are we seeing any interest from the large integrated oils now that they're, let's say, a little more cash flow constrained being interested in selling off downstream assets?

I will just take that. It's a funny market, it's never more and it's never less. There's always something out there.

The Citgo thing was, perhaps, the reasons are very complex, we're not exactly sure. We think ultimately some of those assets will come back to the market.

It would seem to me, reading the reports published by institutions like your own, that the major oil companies will be re-evaluating their various assets. And we can certainly see a scenario where the majors will continue a process that, in my experience, started over 20 years ago, and that's to shed refining assets in the United States.

I think that's an ongoing process, and I, perhaps I'm optimistic from a refiner's point of view, but pretty much every year that I have been around the business since, I guess, the early 1990s in terms of Exxon selling Tosco, the Bayway Refinery, there have been sales of major company refining assets in North America. I think that continues.

Okay, thank you.

Doug Leggate with Bank of America Merrill Lynch.

Thanks, everybody. Good morning, Toms.

I wonder if I can go back to the issue of the heavy crude, I just wondered if you could opine a little bit as to what we appear to be seeing in terms of OPEC price policy, or Saudi price policy, if there is such a thing. It's really more the issue that the differentials have held up more in absolute terms than the traditional percentage relationship that, I guess, most of us assume in our models.

Are you seeing any evidence that this could be a new basis for higher expected heavy crude discounts on a more sustainable basis, or do you see it as transitory? If it's the former, how does that sit then with your view on the economics of the Bakken given the potential significant reduction in rig count in that area? I have got a quick follow-up, please.

Well, just quickly, Tom should take the Bakken. On the heavy side, we think that the ever-increasing amount of crude that's coming out of Iraq prospectively if there is a settlement with Iran. The maintenance of the Saudi production level, certainly, we see finally a better rent being paid for the use of these heavy refineries.

We see the coking economics as a more resilient improvement. There's nobody that can sit around and forecast forever for you, but we don't see a lot of new coke as being built, particularly here in North America. There has been a lot of additional heavy crude produced, so we think it is pretty resilient.

Tom, take the rest of that.

Yes, the question on the Bakken, I'd make two points. We absolutely expect Bakken to be the marginal crude in terms of it's going to move by rail, it's going to price to clear by rail, probably to the East Coast and then maybe to the West Coast. There is no more light crude coming into the Gulf Coast. If Bakken starts making its way down there, or light Canadians make it down there, I'm not sure exactly what they're displacing.

It would probably push out medium-sours and maybe even some heavies, that would work perhaps to our advantage. But we see Bakken still coming in and probably will have economics that will allow it to be processed in tandem with the heavy crudes that we're running.

One other point, though, is particularly, we have the capability in Delaware, and as by permit with the state of Delaware, to actually bring in Bakken and move, I think it is 45,000 barrels a day of Bakken, transship it. We are doing that today where we're transshipping it, bringing it in by rail into Delaware, unloading it, putting it in a tank and pumping it over the barge docks to Paulsboro.

Well, we can do that to some of the other refineries in the East Coast and take advantage of that to continue to monetize, or use the loop rack in a manner that is adding some value. That will likely be economic to the other East Coast refiners, and you could do a deal here, because, again, they cannot take advantage of, what you talked about Doug, is that there is a structural change and you never say always or never.

But it certainly, the world has got too much crude and that likely is going to continue. And the other East Coast refineries cannot run those crudes, so they are going to be dependent upon light sweet and that becomes an opportunity for us, as well.

Thanks, fellows. I know you've gone over the hour, so I'll just have one more, if I may, and then I'll leave it there.

It seems more strategic. A number of your peers have reported very strong earnings, as you guys did, but for certainly different reasons, namely the lag effect on their retail businesses. They have, obviously, had very, very high margins there.

I'm just curious, when you think strategically about acquisitions, as you have opined upon before, is there any desire or any, I guess, strategic need or objective to maybe move further downstream in the acquisition front, as opposed to just targeting refining and on MLP assets, and I'll leave it there? Thanks.

Let me go back, I guess, it is great to be run over by the luck wagon, and Gary Heminger Marathon, or MPC, certainly hit spectacular timing in terms of a fall in the crude price during the time he took over the Hess retail operation. Everybody in the retail business benefited from this tremendous lag. Gee whiz, even if the lag was 20 days or 21 days, given the rate of drop in the crude oil price that added enormously to the profitability of the assets.

But realistically speaking, we are not equipped to acquire retail at this point in our corporate life. We would prefer to focus at this point on refining, on MLP type assets. And I wouldn't ever want to say the Company will never do something.

But I think in the prospective year, two years, that you see in front of us, we will not be buying retail assets. We have better use for the funds. ' And if you get into now a somewhat rising price environment on crude oil, and I know there has been a bit of a yo-yo movement, we follow it by the minute, on the crude oil price, there is probably a bias to the upside on the crude oil price in the next eight months, 10 months, 12 months.

That being the case, that will have somewhat of a negative impact on retail margins. Long-term retail (inaudible) have continued to decline. It's really not selling gasoline anymore. It's running a very large convenience operation and, again, that's not for us.

Thanks for the answer, guys. Thanks very much, and, I guess, we'll see you in a couple weeks. Thank you.

And this does conclude the question-and-answer session. I'd like to turn the program back over to Tom O'Malley for any additional remarks.

The only remark is to thank everybody for attending. We appreciate your interest in the Company and we are always ready to try and explain how we operate to any investor. Thank you very much.

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