PBF Energy Inc (PBF) 2015 Q4 法說會逐字稿

Good day, everyone, and welcome to the PBF Energy fourth-quarter and full-year 2015 earnings conference call and webcast.

(Operator instructions)

It is now my pleasure to turn the floor over to Mr. Colin Murray, Investor Relations. Please go ahead.

Thank you, Keith. Good morning and welcome to our fourth-quarter earnings call. With me today are Tom O'Malley, our Executive Chairman; Tom Nimbley, our CEO; Erik Young, our CFO and several other members of our Management Team.

A copy of today's earnings release, including supplemental financial and operating information, is available on our website. Before getting started, I would 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 metrics 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. We think adjusted fully converted net income and EPS are meaningful metrics to you because they present 100% of the operations on an after-tax basis.

During the fourth quarter of 2015, average hydride carbon prices decreased and for PBF, this generated a non-cash lower of cost to market or LCM after-tax charge of approximately $209 million. In our comments today, we will exclude this and other special items from our discussion of our quarterly results.

I will now turn the call over to Tom Nimbley.

Good morning, everyone, and thank you for joining us on today's call. Excluding special items, PBF generated approximately $1 billion of EBITDA in 2015. We strengthened our balance sheet and raised approximately $850 million in the capital markets, to fund our strategic initiatives including the acquisition of Chalmette and the pending acquisition of Torrance.

Following these two acquisitions, we will have established PBF Energy as the fourth largest independent refiner in the US Going into 2016, we are focused on successfully integrating our new and future assets, improving operational reliability and investing in margin improvement projects across all of our facilities, all while maintaining capital discipline and a strong balance sheet.

We took over Chalmette on November 1. The transition and integration was seamless and the employees at Chalmette are a welcomed and valuable addition to the PBF family. Since joining our refining system, Chalmette has performed well and contributed approximately $55 million or over 20% of our total adjusted refining EBITDA for the fourth quarter.

As expected, we have identified several opportunities to enhance the earnings power of Chalmette through commercial optimization and quick hit high-return projects. We have earmarked $50 million of capital in 2016 to continue to identify and implement projects at Chalmette and to assess the potential for restarting some of the idle units.

We are still in the early stages of evaluating the condition of the idle units, the potential cost and timeline to restart them and ultimately, the impact to our margin and yield. As with Chalmette, our other refineries performed well during the fourth quarter and the East Coast continues to deliver strong results.

Overall, refiners and consumers have benefited from the current low crude price environment. While we expect that flat prices will eventually rise, they may remain at current levels for some period of time. We continue to use our crude sourcing flexibility, which has improved with the addition of Chalmette, to take advantage of opportunities to provide our refineries with the most economic crude slates.

Going into 2016, we believe the outlook for clean products candidly is mixed. Year-over-year, clean product demand is up approximately 2% and average vehicle miles traveled is up over 3% versus 2014. Baring a major economic shock, we expect that demand will remain strong for gasoline this year. [Distillate] is a bit more of a concern and the current inventory overhang may take longer to resolve itself given the mild winter.

As you are most likely aware, during the blizzard that occurred in the Northeast in January, we incurred a total loss of power at Delaware City which resulted in the shutdown of the refinery. The refinery was restrained with the exception of the fluid coker after 10 days. As the coker was essentially at end-of-run conditions, we decided to advance the 40 day turnaround that was scheduled to begin in the second half of March.

We expect the net impact of the additional downtime associated with the blizzard to be a loss of approximately $20 million. We expect the turn-around to be substantially complete by the end of the first quarter. Lastly, I would like to provide a brief update on the Torrance acquisition.

Our expectation for closing the transaction remains consistent with our initial announcement which is to close during the second quarter. As we have mentioned previously, the acquisition will only close once ExxonMobil has proven the refinery to be fully operational. With that, I will turn the call over to Erik Young.

Thanks, Don. Today, we reported fourth-quarter operating income of approximately $168 million and adjusted fully converted net income for the fourth quarter of $71 million or $0.70 per share on a fully exchanged, fully diluted basis. This compares to operating income of approximately $209 million and adjusted fully converted income of approximately $105 million or $1.13 per share for the fourth quarter of 2014.

Adjusted EBITDA for the quarter was $225 million as compared to adjusted EBITDA of $255 million for the year ago quarter. For the year, we reported operating income of approximately $787 million and adjusted fully converted net income of approximately $402 million or $4.27 per share, again, on a fully exchanged, fully diluted basis. This compares to operating income of approximately $838 million and adjusted fully converted net income of approximately $434 million or $4.50 per share for the full year 2014.

Adjusted EBITDA for 2015 was approximately $998 million as compared to adjusted EBITDA of $1 billion for the year ago period. As Colin mentioned a moment ago, these figures exclude the non-cash LTM expense plus a small benefit associated with the accounting treatment for the tax receivable agreement as applicable. For the fourth quarter, G&A expenses were approximately $55 million as compared to $40 million a year ago.

The increase is largely attributable to higher employee expenses and additional acquisition-related costs including staff augmentation. Depreciation and amortization expense was approximately $53 million versus $45 million in 2014. The increase in depreciation is primarily related to the amortization of the Toledo turnaround which took place in the fourth quarter of 2014.

Fourth quarter interest expense was approximately $29 million compared to $23 million last year. PBF's reported effective tax rate for the quarter was approximately 35% which includes the impact of the change in the TRA liability. Our year to date effective tax rate is approximately 37.3% and for modeling purposes, you should continue to assume a normalized rate of 40%.

PBF ended the year with liquidity of approximately $1.6 billion and consolidated net debt-to-cap of 22%. Expenditures incurred during the year related to refining and corporate CapEx were approximately $217 million, excluding railcar purchase and sales but including expenditures for Chalmette. Our Board has approved a quarterly dividend of $0.30 per share, payable on March 8 to shareholders of record as of February 22, 2016.

In early January, we provided preliminary guidance for 2016. As a result of the unplanned downtime at Delaware following the blizzard, combined with the acceleration of the coker turnaround, throughput guidance on the East Coast was reduced for the first quarter to 280,000 to 300,000 barrels per day.

We believe accelerating the turnaround positions the East Coast well for the second quarter as Delaware should be up and running at a point when margins should be better than they are today. The reduced East Coast throughput in the first quarter has an impact on the full year throughput expectations which are now 320,000 to 340,000 barrels per day, calculated using our new East Coast figure for the first quarter, and 340,000 barrels per day for the remainder of the year.

We also expect to see an increase in operating expenses per barrel for the East Coast as a result of the downtime. All of our other guidance remains unchanged. Also of note today, PBF Logistics announced a distribution increase to $0.41 per unit, a 5% increase from the last quarter.

As a reminder, PBF Energy owns 53.7% of the units of PBF Logistics and 100% of the GP and incentive distribution rights, and we continue to benefit from participation in the second level of the IDR splits. Last week, PBF Logistics announced that it had entered into a agreement to require four East Coast terminals from Plains All American.

We view this as a timely transaction for PBF Logistics as it adds third-party revenue to the partnership and demonstrates our disciplined approach to sourcing and executing transactions at attractive acquisition multiples in a challenging market. In addition to adding unaffiliated third-party customers and doubling the storage capacity of the partnership, most importantly, the terminals are expected to provide PBF Energy with the opportunity of optimize product distribution and realize synergies with our East Coast system.

As a result of our successful capital markets transactions during the fourth quarter of 2015 where we raised $850 million of debt and equity, we believe that we are well positioned to finance the Torrance acquisition. Given the current market environment, we believe it is important to be diligent in managing the balance sheet to put ourselves in a position of maximum flexibility for 2016 and beyond.

I am now going to turn the call over to Tom O'Malley for his closing comments.

Thank you very much. Certainly we are pleased with the fourth quarter operation.

I really only have two comments. The first, that our operation of Chalmette and the due diligence that we continue to carry out on Torrance indicates to me that our initial expectation on both refineries was low. Both refineries have substantial upside from our initial calculations.

The second thing -- and I think we should comment on it, as we follow with on a day-to-day basis -- crude markets. Obviously, we continue to see them under pressure. We don't believe that it is going to go too much lower than the current level of $26, $27 for WTI and perhaps a $1 or $2 above the Brent, but we do believe it is going to take 6 to 18 months to get a sustained improvement in this pricing.

For any heavy refiner, low oil prices are a benefit. We make products such as petroleum coke and sulfa that really aren't related too much to the actual price of the feedstock that we use. This has been quite a benefit for us and we are pleased that it will continue for some period of time.

On that note, we would be pleased to take any questions you have.

(Operator instructions)

Evan Calio, Morgan Stanley.

Good morning, guys. I need to pick up on your last comment. On the heavy side, you mentioned, but can you comment on how you are seeing a broader crude slate options across your system?

Like differentials re-emerging with storage capacity issues and looming mid-con turnaround on the heavy side, but the base had some recent operating issues? Just any color on how you are seeing options changing real-time preserve margins in these current markets?

The light heavy differential in RV was going to continue to expand. You do have storage issues there, but I don't think they are going to be an overwhelming factor. When you look at these differentials, I think the important thing, always, to focus on is not the absolute level of the differential but rather, what the differential is relative to the price of crude on a percentage basis.

So that is kind of the way we always look at it if we see a good percentage differential. And certainly, today, the differentials are very good from our perspective. If you looked at, for instance, Mars versus WTI, today, you are a little bit over $3.00, or in essence, about 12%.

If you look at it against Brent, the differential is well over $6.00. If you looked at WTS, well that is trading pretty much even with WTI but of course well under Brent in this marketplace. If you go out to the West Coast and you looked at your current river crude, you would see that it is trading at over $7.00 under WTI.

So we think it is a good environment on heavy crude and of course, part of that is the emergence of additional production from Iran. There really is no light production coming out of Iran. The average slate is going to look like our medium. From our point of view as a heavy crude oil refinery, we like where we are.

Right. Maybe if I sustain with the macro, recession and micro risks are looming larger. Having operating through several economic downturns, can you discuss your portfolio or thoughts and maybe CapEx flexibility if markets remain a little weaker?

I think, obviously, if you are an investor in the New York stock market and you are looking at it this morning, you are not feeling particularly well. The last time I looked, the Dow futures were down 280 points.

Obviously, we are undergoing some adjustment here. Exactly why -- I suppose, a combination of factors, uncertainty on the political situation. Certainly, still a mess in the Middle East. Relatively slow growth. We don't see a recession coming. When we look at consumption patterns in our industry, we see relatively slow growth.

I think the market got ahead of itself and there is no sector, if you think about this, seems to be pushing to the upside. Certainly, the energy sector almost universally with some exception in the refining business has had a very tough time. The EMP business is a disaster. The midstream is a disaster. You go to the financial sector, certainly, everybody has been under pressure.

Pharmaceuticals, obviously, are afraid of Bernie Sanders eventually being elected. It will be a rush if he is elected to exit doors of the United States. So I -- we are buttoning the operation up. Certainly, Tom Nimbley, Erik --

I will stop you there, Tom. To Evan's question specific to CapEx for the Company, Tom is saying we are watching what you're watching. And our main priority is to keep the balance beat strong and we are taking defensive steps in case in fact we are wrong in our opinion, although I share Tom's opinion that we probably will not have a recession but we could be wrong.

We have about, in the guidance we've given you, $475 million to $500 million system-wide in CapEx, $200 million of that is turnaround. $200 million of it is capacity maintenance, tier 3, health safety environmental and there's about $80 million to $100 million of discretionary. The discretionary is all on the table. We can cut that back.

And in addition there's some of the tier 3 investment that we have an option on. In other words, we can continue to use and buy credits that are available in the marketplace which would allow us to push back the physical investment to come into compliance from January 1 of 2017 to beyond.

So look at it in terms of somewhere around $80 million to $100 million probably of stuff that we could just say we're not going to do because we're concerned about what is going on in the economy.

Great. I appreciate it, guys.

Roger Read, Wells Fargo.

Good morning.

Good morning.

I guess maybe a follow-up just real quickly on Torrance, Q2 closing the last time we talked, the expectation was at the end it would at least begin its restart in February. I'm just curious. Do you have any update on that? I mean does February still look likely, or should we think about that as having slipped a little bit?

I actually have Jeff Dill in the office here, who's going to be President of the West Coast operation. He had discussions with ExxonMobil yesterday.

They have indicated that they are on, actually, a little bit ahead of the latest schedule they reviewed with us when we were out in California several weeks ago. They now anticipate effectively starting the start up activities on March 15. They have a 35 day startup period which includes the 15 days that are required to prove at the unit.

So effectively, this period of time where they are going to approve the ESP, then they will start up the FCC and the attending units that have down, and then they will demonstrate performance over a 15 day period. If you do that math, right now, we're hopeful that we will affect the closing on May 1.

Okay. Great. That is helpful. And then, I don't know exactly who to direct the question to, but we saw in the DOE numbers yesterday major decline in pad 4 utilization. I recognize you are not a pad 4 refiner, but the pricing pressure emanating out of pad 2 -- do you see or have you -- are you seeing a condition in the pad 2 area and maybe bleeding into the Gulf Coast that could force run cuts for any of your units?

Tom?

Yes, I can handle that. The short answer is yes. We have negative gas cracks in pad 2, pad 4 is under pressure as you suggest. We have taken steps in Toledo. We have not necessarily -- we have cut crude and we're running 150,000 barrels a day of crude.

It's a tough place to get rid of the crude so cutting runs further, you sometimes hurt yourself because you lose more on the crude you're selling than you are cutting back. But we have in fact cut back the FCC, we have cut back the hydrocracker, we're storing some intermediates and not turning them into finished products. Obviously, Bolero came out and said they were cutting back in Memphis. I suspect that what we have seen is the [euforia]of pretty good gas cracks going all the way to the end of the year.

The refiners do what the refiners do. They ran hard and they went to max gasoline mode and now, we have seen the inventory. And what will likely happen or at least is my expectation is that situation will reverse. And it is no longer an incentive to be at max gasoline, and you can cut that back and go back to a balance slate or affect run cuts to bring us back in balance. And I still am somewhat bullish on gasoline as I said in my opening remarks.

No, I would not disagree with you on that. I was just curious whether it'd cut any runs, because we saw -- let's call it relative strength in Syncrude relative to WTI's, so just thinking about how that affects Ohio. I appreciate your answers. Thanks.

Blake Fernandez, Howard Weil.

Hello, guys. Good morning. Tom, during your prepared remarks, you mentioned considering some of the restart of the idled units over at Chalmette. I was wondering -- I'm assuming you are still kind of in the process of getting numbers together, but could you talk a little bit about what potential costs that might have? What kind of EBITDA contribution and maybe the timeline that you are looking at?

Sure, Rob. Let me just make a general comment regarding investment or opportunities that we see in Chalmette, and we are really focused on three areas as we continue to get more and more information around the site. One is just logistics to bottleneck. The refinery is logistically challenged. They had too much to merge at the dock.

They had some constraints on being able to export gasoline because they have limitations on the recovery system, things of that nature. So we see opportunities to spend -- and this is relatively small money to put in a new crude tank as we did in Toledo. So we are focusing on that as one kind of pathway to improve the margin of new product market and commercial opportunities.

We have already entered the asphalt market which was not a business that they were in, it is better alternative than coke or feed in fact, and certainly if you have to get at the fuel oil business, we are going to start up likely a small -- one of the idle units that they shutdown was a petrochemical unit that would make paraxyline, ortho-xyline. We believe that is a good opportunity for us.

And the third lane, Evan, is frankly the bigger units that have been idled, a hydrocracker, a reformer, pre-treater and a coker. As we look at those, we suspect that we are not going to start up the small -- the coker is relatively small. And it really has not been kept in as good a condition as the other units.

Right now, we believe there is likelihood that we will start up. It may take until 2017 [ technical difficulty ] all of the other units, including a small caustic treater which allow us to get back into the jet business. As I said we budgeted $50 million to spend this year and help us define further. We think we're definitely honing in on this thing, and we're looking at several alternatives around the hydrocracker.

We'll have that probably buttoned up here in the next three to six months of which way we're going to go. I think the estimates of how much money we will spend with probably be somewhere between $100 million and $150 million if we do all of the restarts that I just mentioned, and I would guess that we probably have somewhere around $80 million to $100 million a year, run-rate EBITDA.

Great. And just to be clear, the $50 million you mentioned this year, is that part of the $100 million discretionary spending that you referenced earlier?

Yes, it is.

Okay. The next piece is on heavy gasoline. I'm just looking in the fourth quarter. It looks like you had 17% of your crude and feedstock as heavy runs and then 50% yield on gasoline.

I'm just curious. We have a lot of moving pieces here with Chalmette coming into the mix and then potentially Torrance. Do you have any sense of kind of where that is going to get to once the system is fully integrated and up and running? What is the max level of heavy that you cold run, and what do you think your max gasoline yield could be?

Obviously, best to look at it by refinery. Toledo obviously runs zero heavy. So that is 100%. You look at Paulsboro, medium sour to heavy, that is basically the predominance in the slate.

So if you are 150,000 barrels a day of crude runs, we're running 100,000 barrels a day of soddy crude, either medium, and on some occasions we run light, and then we are running Vasconia and other heavy crudes on the other still. Delaware City will be typically running about an 80/20 mix of heavy to light, 80% heavy. Waterborn is the most economic right now. Ex the fact that we are taking the coker turnaround, obviously that doesn't apply while the coker's down.

Chalmette is about the same. We are looking for options to run Bakken. They are not as economic as frankly, the Venezuelan crude and some of the South American crude that we are running. So -- and then when Torrance comes in, of course it runs a 15 and 16-degree API space.

On balance, we are probably in the 70%, 75% medium to heavy range for the total crude slate, assuming the economics are there. Now, one of the things that we like about our system is, if they shift, we have the optionality, particularly on the East Coast and in Chalmette to swing that around.

Gasoline yield, you know 50%, 51%, I go back to the fourth quarter. Everybody including PBF turned the dials to make more gasoline.

Maximized conversion on the hydrocrackers. Maximized conversion on [cat naftas] and things of that nature. So it could go up little higher. It did go up little higher. However, I suspect that it will equalibrate somewhere around a slight bias of 51% or 52% system wide, gasoline 35%, distillate and the rest of the other stuff.

That's helpful. Thanks, Tom.

Paul Sankey, Wolfe Research.

Good morning, everyone. Tom, I read about the Delaware City turnaround. I think that there was some additional commentary that you'd be sourcing oil from the Bakken, but I don't see it in your press release.

Could you just update us on where you are on that. And if you really can train in additional barrels. I was sort of thinking of the economics of it at this price spec. Thank you.

Good question, Paul. Obviously, first of all, we are going to be running about 158,000 barrels a day of crude right now. We will be taking that up to about 130,000 barrels a day. We are running a mix but we are moving a little bit more toward Bakken.

We can make money on a variable cost basis on Bakken and we will be sourcing in some amount of Bakken. It won't be anywhere near what we did the last time we broke it down, which would be effectively shut down a piece of the crude unit and ran a very light slate closer to the crudes we have coming in.

But there will be -- there is economics to run 30,000 barrels a day of Bakken into base because it carries heavy crude and we will probably boost that up a little bit during this downtime.

And how do the train economics work at these prices? Is it just a loss to --

You do not have economics on a total and average basis. That's in fact why -- again, if you remember our cost to move rail total and average going in, about $11.00 dependent upon where you buy the crude for in the field. Last week the commercial folks were telling me we might be $5.00 or $6.00 under Brent -- I'm sorry, under TI and if you have a $2.00 ARB on it, you're going to land it in at Brent plus three or four.

That's a lot better than it's been. But we would normally not run that crude in Delaware if we had the refinery running full because the economics on the heavy crudes and the medium crudes would be better, but with the coker down in fact it works.

Yes, got it, and then the technicalities of buying Iranian crude, I can understand there's an overall market impact. I guess the Iranian moves into Europe and then it knocks out other equivalent blends to the benefit of you guys. I mean, you could not buy Iranian crude directly, could you?

No.

Is that because of ships or --? No, that is the US government regulation at the present time, I don't think would allow us to in Iranian crude but your analysis is correct. Most of that crude is going to go to their previous customer base in Europe. And it will simply back out other crudes. Got you. Do you have a sense for how much incremental crude we're going to see? I have seen, I think it's about 150,000 a day going to Totale, 150,000 a day going to ENI in Europe. Do you have any sense for --?

Yes, I think the best we can do candidly is what you are doing in publish reports on what they actually ship. I think you are looking at 300,000 or 400,000 barrels a day.

I think they got ready for this in advance. They figured out that they were going to have a settlement. Getting it far above that, I suspect will take quite a bit more time.

Great. Thank you, everyone.

Chi Chow with Tudor, Pickering, Holt.

Thank you. I guess back on the macro in the Midwest, what do you think is the underlying cause of the weak gasoline cracks there and the high inventory? Is demand particularly weak so far your date or is this just preparations by industry for extended turnarounds upcoming in the region?

I will weigh in on that and then Tom can add -- but first of all the Midwest, I think we're safe to say you all understand this that, and it's not I don't believe because of the commitment within the crude export ban, but the build out of the RVs, the logistics system has effectively had pad 2, pad 4 return to the mean. So the days of the very wide arms that let you run and still make money even with wintertime cracks are probably no longer there unless there's an operating problem in the pad.

We're going back to where typically Chicago and the Midwest goes long in the wintertime on products. That is indeed what has happened. I think it was exasperated, as I said, because frankly, even Chicago had very good cracks in the fourth quarter. So all of the refiners, including us, were running and then you started to see well, you are running but the gasoline is not going to the consumer, it is going into a tank.

When that happens, typically that is the oil transfer of the products to crude into products. You start to see the impact on the crack, but I think it is transient. You are getting a dump of wintertime gasoline.

The Midwest market will transition earlier. In fact, the end of this month to lower RVP gasoline. That will take -- butane is out of the pool and part of the pressure that has been put on it is people just getting rid of the wintertime gasoline because they realize that the marketplace is changing.

Thanks, Tom. And then on PBFX, do you have any guidance on any sort of timing or level of possible niche, some asset drops this year in the MLP, and any thoughts on financing these transactions given the current state of the MLP market?

Hi, Chi, it's Erik. So I think at this point, we obviously made the Plains All American announcement last week. We expect that to close in Q2. We continue to evaluate buying third party acquisitions or doing asset dropdowns.

Clearly, there is a lot of turmoil in the MLP equity markets. We included some language in our press release that we do have the option of having PBF Energy actually buy equity to complete the Plains transaction, we have plenty of liquidity under our revolver and I think at this point, we're content based on having 1.3, 1.4 times coverage with PBFX to continue down the growth path.

However, I think we are very cautious because issuing equity at these levels is not very attractive. You ultimately have to have extremely low purchase multiples in order for the math to work.

Right. And would the Chalmette mid-stream assets be under consideration for the next drop whenever that might occur?

I think we have always said we don't have a preference as to what type of asset gets dropped. We are comfortable with our pool of $280 million of drop-down EBITDA that sits at the parent. Doing transactions like Plains, we think are extremely attractive because it allows us to continue to keep that $280 million at the parent for future consideration but I don't think we really don't provide any guidance in terms of what would be the next asset that comes down.

And from our perspective, it could be any of the assets on the East Coast that we have highlighted or any of the $80 million worth of assets that would come from Chalmette or even Torrance once we close that acquisition.

Okay. Thanks, Erik. I appreciate it.

Jeff Dietert with Simmons.

Good morning.

Good morning.

I want to follow-up on a couple of popular topics this morning with gasoline inventory builds. Could you talk a little bit about what type of material you think that is? Is it primarily winter grade material? Or are you stocking up high-octane material to take advantage of the summer driving season?

Pretty much. Most of it is just winter grade material. As I said, what happened is in the fourth quarter with the margin environment that existed, people increased the gasoline yield and ran hot. And put winter time gasoline in tank and at least, certainly, in the Midwest, when the demand fell off, that is what I think has driven this rather significant decrease in gas cracks because people are now doing what they have to do to empty the tanks and get ready for the summer.

And the rest of the system, there has been some gradual transitioning to get ready for summer time gasoline and it is in the area of octane and [alcolyte] where you get low RVP type material that we are seeing some build, but predominantly it's winter time gas.

Thanks. Following up on Chalmette, I realize you only had it for two months during the quarter. You reported 35% heavy feedstock, 32% medium, 18% light and 15% other. Is that a reasonable assumption going forward or do you anticipate moving towards more medium and heavy barrels as you go into 2016?

That's a good question. The answer is the second part. We expect, given the market, if the buy-heavy dips remain where they are and our view is that they will remain wide to incent to do that. We will be moving more toward a medium/heavy slate.

We owned Chalmette only for two months and the first month, this crude slate that we ran was purchased by Exxon. It was based on their system, so it had a lot of HLS in it still, some of the crudes that we expected to be able -- to be moving out, you have to run some light but you don't have to run as much as was being run.

So we actually think we will be given the economic situation that exists and if it remains, moving towards a heavier slate in Chalmette.

Got you. And on the East Coast, you're down to only 5% light. And traditionally, you have run more like 20% light. I think most of that at Del City. Is that a sustainable slate?

What are the restrictions on the East Coast? Maybe more specifically at Dell City as to the minimum light crude runs?

Yes, it is a sustainable slate, as I said, Paulsboro basically can run a full 100% mediums/heavies and in fact that's the way we ran it in the fourth quarter. Delaware, it is a function of just how heavy a heavy crude you buy. We started running Altamira and some of these crudes that are very heavy.

When we do that, we actually need some light crude to carry it. So we might run 30,000 or 40,000 barrels a day of light crude. In fact, the model says we can run Bakken in order to carry these heavy crudes. When the R moved open, and the West African barrels became more attractive, we were actually looking at bringing in some light sleets from West Africa but that has kind of corrected itself.

So I think we'll are run 30,00 to 40,000 barrels a day of light crude at Delaware and mainly to allow it to carry what we consider to be very attractive heavy crude. One of which is the M-16 crude that we are getting from Venezuela which used to be run exclusively in Chalmette, but our models are telling us that in fact, we actually get a better margin at running it in Delaware.

So we have started moving some of that material to the Delaware refinery. It also helps us on freight economics with to-porting that stuff. But to do that, we need to run some light crude.

Thank you for your comments, Tom.

Edward Westlake, Credit Suisse.

Yes, congratulations on the EBITDA in the quarter. Just a question on Chalmette and Torrance. First, in your opening remarks, you said based on the due diligence and the operational performance that you see upside. I mean I'm just looking at your chart of $260 million of Chalmette and $360 million from Torrance, and then I hear in your comments about $80 million to $100 million of EBITDA at Chalmette from the restocks obviously with some capital spend to get there.

Maybe just give us a sense of what that opening comment about those two assets perhaps being better means in terms of dollars and cents.

Well I will tell you, Tom made the comment that these are two of the more attractive assets that he has seen in the number -- many refineries that he has acquired. I would echo that. It kind of remind us of Bayway when I first started working with Tom. An underutilized asset, particularly Chalmette. The product of a bad marriage in the joint venture with upside potential.

So I think, we said to $280 million -- that $280 million, if we are right in our view, particularly on the capability of bringing the hydrocracker back, either as a hydrocracker or as a gas oil hydro treater, there's a number of different options that we are looking at. Then that $80 million of EBITDA, 5% of that is likely going to be additive to the $280 but it's going to take some time, it's going to take some money and we have not fully landed on either of those two things yet.

Okay, and then anything on Torrance, you mentioned the due diligence seems to be going well in terms of understanding that asset versus your initial projections.

Torrance, first of all, we are getting very good cooperation from ExxonMobil on Torrance. It was a little bit problematic and we were somewhat concerned on Chalmette but that was because it was the JV. They are anxious. Most of the efforts we are focused on right now, Ed, are on the commercial side.

There are -- we have a lot of people knocking on our doors, CRC, the California resources, we have a lot of California heavy crude. So we're really trying to get our arms mostly around the commercial opportunities that we think are there. We think there are going to be some -- what we do with the steel, that is probably down the road.

The key to Torrance, as I think everybody on this call probably knows, we have to make sure we can run it safely, reliably, and in an environmentally responsible manner. That has been the challenge for the site.

We are very hopeful that the significant investment that has been put into that over the last two years will in fact correct some of the root problems of that but that is what we are going to focus on. Commercial and getting it to run right.

And then my second question is really around funding. Obviously, the market is worried about recession. You've got cash going out the door for Torrance which will reduce your cash balance.

The MLP market is, as we've already discussed facing some issues. So maybe just talk about how you plan to run the balance sheet say over the next one to two years.

Ed, I think overall, we have been fairly consistent in our message that we would like to longer-term keep net debt-to-capital below 40%. That is still our long-term goal. We've got the rating agencies onboard with that. I think today, we have $1.4 billion, $1.5 billion of overall liquidity.

Once we complete the Torrance acquisition, we think we will probably use between $550 million and $600 million worth of liquidity to actually go and purchase the assets as well as the hydrocarbon inventory and other parts of working capital. But that's a big reason why we were in the Capital Markets in the fourth quarter raising $850 million.

So I think we are fairly confident with the ability to close Torrance during the second quarter and longer-term I think the focus will be on managing the balance sheet in the most conservative manner that keeps us kind of inside of that long-term net debt-to-cap while at the same time, maintaining enough flexibility to go out and do what we think we do pretty well, which is uncover opportunities that other folks may not have line of sight on. I think that is really the key for us.

One thing I would add is, we were somewhat lucky, at least at Chalmette and it appears as though we might be at Torrance, when we modeled those acquisitions, we modeled them in a much higher crude price or product price and the working capital burden of Chalmette was quite a bit lower and right now it'd be the same especially if we hit this timing in May 1 at Torrance.

Thank you.

Ryan Todd, Deutsche Bank.

Thanks. Good morning, everybody. Maybe if I could follow-up on a couple of earlier ones. I appreciate the color that you gave on the potential to bring units back on at Chalmette and the growth CapEx.

If we look at the results you have seen so far, your results have clearly exceeded expectations. Some of that might be from stronger headline cracks than you had in your original view, but it appears also that even in excess of the cracks, you guys have probably exceeded our expectations, your guidance with the stronger capture rate. Can you talk a little bit about what has driven the strong results to date? How sustainable those are as well?

The latter part, let me just comment. In addition to a very good crack which you tell us what the crack will be and we will tell you how sustainable it is, but as we said, our view is that there will be some battling back here a little bit but that gasoline is going to continue to be the horse that pulls the wagon.

And we expect to have favorable -- got to get through this period -- the other thing that helped us and continues to help and I think is sustainable is what we talked about a little bit earlier. The light, medium, light/heavy gas. Light, especially as Tom says, on a percentage basis, the indications from a supply standpoint, Iran, etc., would say that suggest that has the probability of continuing.

So in fact, in response to earlier question, we expect to actually increase the amount of medium [salaries] that we are going to be running at Chalmette which should further improve the operation. So the short answer -- that was not the short answer -- but yes, we think it is sustainable.

Thanks. That's helpful. And then maybe one more. You mentioned in the press release and a couple of times in your comments about the ability that you have now to kind of run, particularly the East Coast and Chalmette together is more of an integrated system to maximize profitability.

Can you talk a little bit about what that means on a granular point of view? What are the opportunities that you have or that you see right now to run that as kind of an integrated system and whether there are some opportunities in the future that you see to maximize that?

The most obvious one that we are seeing right now is on the crude side. Delaware doesn't have the best logistics for bringing in crude by water.

We have draft restrictions so we often times sit out in Delaware Bay lightering vessels to get them to where they can get into the dock. With Chalmette and Delaware City being able to run essentially very similar crudes, we are now sourcing crudes on larger vessels, bringing them into Chalmette's dock, unloading them and then bringing them directly into Delaware City or in fact, in some cases, directly into Paulsboro.

So the crude flexibility that we have is something that we are taking advantage of and we will continue, that will be a synergy between the East Coast assets particular Delaware and Chalmette. Other areas, sharing after-cargoes, things of that nature. So most of it is on a commercial bet. Just being, taking advantage of the ability on freight but also by and large the cargoes of NAFTA as opposed to smaller cargoes and getting them into both sites.

Okay. Thanks. That's very helpful.

Paul Cheng, Barclays.

Hello, guys. Good morning.

Good morning.

Tom on Chalmette, I know you guys are going to look at the operation and all that, but in the short-term for the next several quarters, I'm just curious then, can we use the fourth quarter as the sensory, the base nine for the unit cores and margin capture rate? Or that some one-off items in the quarter that we need to make adjustments?

There was really nothing unusual in the two months that we ran. There was relatively smooth operation. Obviously, a strong crack. You guys will make the determination on what you think the crack will be. When you look at capture rate, I would have to go back and look at it.

I suspect if we run right and we get some benefit from the heavy crude, the heavier crude that we might be able to tweak that up a little bit from probably around 84% capture rate in the first two months, very nice capture rate. But again, in a low flat crude environment, you should start to see that ability. So I don't think you go wrong using the same capture rate assuming the dips are there. Maybe it will be up a little bit.

So there is no inventory or anything that we should be concerned, things that make the fourth quarter so far the margin capture rate look better or worse so that is actually, we have a similar margin environment and light heavy defense of that, you would expect the capture rate would be similar?

Yes, I don't think there was anything anomalous in the fourth quarter that was an accounting or an inventory effect that was there. So, frankly, again, if you stick with this low price environment, again that is an advantage but if that is the situation, that would be our expectation.

Sure. And I'm just curious that on the December energy bill, it is supposed to have a tax credit, $3.00 per barrel for the East Coast refinery. I never fully understand on that and I just wanted to make sure that -- is that fully offset the additional cost of Jones ex compared to a foreign frac if you are going to ship oil let's say from the Gulf Coast up to the East Coast?

The original intent was to try to see if that could at least offset some of the pain of Northeast refiners of being put at a potentially competitive disadvantage on the Jones [acq] versus people were loading crude in Corpus Christi and taking it to Canada.

But that $3.00 credit never really got to the finish line. It was actually much lower than that and in fact, to be perfectly candid the way the law was written, it really doesn't even exist as a credit. Is that fair to say, Matthew?

Yes, it's classic Washington that they tried to put language in there that was going to be a small benefit to refiners. But as it is currently written, it actually needs to be amended a bit to actually take hold. So we are not -- as typical with Washington, we are not counting on anything from it. We might be able to get a minor boost from a tax perspective but it's nothing worthwhile.

So we should not view that in and assume that you guys would be -- never paying through your, actually be able to ship crude from the Gulf Coast to the West Coast and vice --

Absolutely not.

I see. So what is the current -- what is the current? Do you get any tax credit at all or not at all?

We can explain it off-line. It's not a tax credit. It has to do with incremental tax deductions but like I said, it is not worth modeling at this point. I'm happy to discuss it, but I don't want to bog down this call.

That would be great. Thank you.

Doug Leggett with Bank of America Merrill Lynch.

Thanks, good morning, everybody. Tom -- either Tom -- I wonder if you could give us your perspective on how long you think this winter gasoline overhang takes to clean up. And maybe just to add on to that, why have the step up in exports that's obviously been another major change in the industry not helped alleviate at least part of the problem that we are seeing right now, and I have a quick follow-up, please.

I will give you just a little, Tom. The -- one of the things in terms of how quickly it could alleviate, let's put this in perspective. PBF has a basically, a system that can swing about 8% to 10% of its clean product production between distillate and gasoline through the various steps.

And other refiners are probably plus or minus on that, but if you use a number of 10%, and you go back to the fourth quarter where you had this very favorable bullish gasoline environment and a distillate overhang, and everybody cranked up and took that 10% on a 9 million barrel a day production base, that's 8.5 -- it is a significant increase in gasoline production. And frankly, I don't think there was poor demand, I just think we cranked all of the distillate, turned it into gasoline and we started to see some bills.

Right now, everybody is going to reverse that. Certainly, we are going to reverse it. I can't say what everyone else is going to do, but we will go back and say, well that is not the right way to run the system. When you look at the current gasoline cracks, the model tells you, you're not going to run it that way. So I don't think it's going to take that long.

You have a combination of people who are going to be dialing back on G to D production. You will have summertime gasoline which is going to take all of the LPGs out of the gasoline pool, and then some folks including us are decreasing production particularly in the Midwest right now although you saw Trainer is also, Delta Airlines is cutting their economics based on waterborne crudes.

So I don't think it will take that long. I could be wrong -- to correct. On the export side, I can only say that some of the stuff I have read is, they think that perhaps some of the weather related problems in the Gulf Coast have restricted exports but I am not the expert in that area.

Just commenting on that -- if you expect the government to make the right decision in terms of crude oil exports and that was going to be the magic bullet, that is really unrealistic. You are still getting exports of very light material. But the system is not there and it is all driven by economics. And we don't see that the ability to export is going to cure the US market from a pricing point of view.

Thanks, fellows. My follow-up, I'm afraid, is a repeat on Torrance, I guess. I just wanted to understand properly.

Is Torrance running as you understand it today and what's behind my question is, obviously, West Coast, like everywhere else, the margins upcoming quite a bit. So I'm just wondering what the dynamics going into summer could look like in that market if Torrance comes back given that margins are already weak with Torrance offline. I will leave it there. Thanks.

Yes, Torrance, they did have I guess here in the last month, they shut down their crude unit. They had one crude unit for a short period of time. But principally, has been running at significantly reduced rates and basically producing a bunch of intermediates and very -- some finished products from the reformer and some of the other units, but a lot of intermediates. When, to your point, when the Torrance is a gasoline machine as you know, the FCC. A lot of FCC so you will see some pretty significant, assuming the margins there, increase in gasoline out of Torrance.

Right now, the track has come in as it has everywhere, but the reality is gasoline demand year-over-year in California last year versus 2014 was up rather significantly. And if you look at the vehicle miles traveled, indications is continuing to be there.

So even with Torrance coming up, the base supply demand situation in California does not look like it's problematic to us, and California is a place where you can move along when everything is running well and make a little bit of money or some amount of money, but the history of the state is when there is a problem in a refinery, unfortunately for ExxonMobil Torrance has been announced over a period of time, is where if you run properly, you can do extremely well.

Thanks, fellows. I appreciate the answers.

We can take up follow-up from Chi Chow. Please go ahead.

Just one follow-up. Can you quantify the break-even medium and heavy crude discounts on a percentage basis for your system? And does that break-even differ by refinery?

We would have to get back to you on the system. You can work that with Colin, but yes the second piece is very clear. That is why we have these linear models. If that break-even will move around.

So it is difficult to say exactly what they are over a longer period of time. We can look at them in any spot time and run it through the model and it will say, yes, here's your break-even economics, but that changes with the spread between gasoline, distillate, it changes with octane moving out, the jet premium, it's fairly complicated so we could not give you something that we feel you should run with over an extended period of time as a percentage.

Tom, do you have any sort of rule of thumb? Do you need a 10% or 12% discount on [mia] versus light or something lower for medium crude? Anything just to kind of get a feel.

I would like to try to help you out but really, no. Again, it's just a little bit too complicated for us to give you something that we might be misleading you. As Tom says, it is percentage-based so you know, you got to look at it at a point in time and you've got to look at the whole macroeconomic environment -- not macro but specific economic environment and much it up to the hardware in the refinery to be able to do that and that is why we run LPs.

Okay, thanks.

Ladies and gentlemen, we have reached the end of our allotted time. I will turn the call back to Tom Nimbley for closing remarks.

All right. We certainly appreciate your time. Thank you for the participation and everybody have a good day.

Okay. And ladies and gentlemen, this does conclude our program. We thank you for your participation. You may down disconnect. And have a great day.