Colin Murray - Head-Investor Relations Thomas J. Nimbley - Chief Executive Officer & Director C. Erik Young - Chief Financial Officer & Senior Vice President Thomas D. O'Malley - Executive Chairman Matthew C. Lucey - President.

Evan Calio - Morgan Stanley & Co. LLC Roger D. Read - Wells Fargo Securities LLC Blake Fernandez - Scotia Howard Weil Paul Sankey - Wolfe Research LLC Chi Chow - Tudor, Pickering, Holt & Co. Securities, Inc.

Jeffery Alan Dietert - Simmons & Company International Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker) Ryan Todd - Deutsche Bank Securities, Inc. Paul Cheng - Barclays Capital, Inc. Doug Leggate - Bank of America Merrill Lynch.

Good day, everyone, and welcome to the PBF Energy Fourth Quarter and Full Year 2015 Earnings Conference Call and Webcast. At this time, all participants have been placed in a listen-only mode. The floor will be opened for your questions following management's prepared remarks. It's 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'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'll 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'll 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 hydrocarbon prices decreased. And, for PBF, this generated a non-cash lower of cost or market or LCM after-tax charge of approximately $209 million.

In our comments today, we'll 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 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 U.S.

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 idled units.

We are still in the early stages of evaluating the condition of the idled 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. Barring 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 restreamed 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 turnaround 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, Tom. 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 net 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 LCM 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 purchases 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 barrels per day 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 barrels per day 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 the 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 an agreement to acquire four East Coast terminals from Plains All American.

We view this as a timely and strategic 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 to 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'm now going to turn the call over to Tom O'Malley for his closing comments..

Thank you very much. Certainly, we're 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. Second thing, and I think we should comment on it, as we follow it on a day-to-day basis, crude markets. Obviously, we continue to see them under pressure.

We don't believe that it's going to go too much lower than the current level of $26, $27 for WTI and perhaps $1 or $2 above for Brent. But we do believe it's going to take six months 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 sulfur, 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're pleased that it will continue for some period of time. On that note, we'd be pleased to take any questions you have..

We can take our first question from Evan Calio with Morgan Stanley. Please go ahead..

Yeah. Good morning, guys. Tom, maybe to pick up on your last comment, I mean, on the heavy side, you mentioned.

But can you comment on how you're seeing broader crude slate options across your system? I mean light differentials are reemerging with storage capacity issues and looming Mid-Con turnaround on the heavy side, peda (14:45) base has had some recent operating issues.

Just any color on how you're seeing options changing, real-time, to preserve margins in these current markets?.

Well, the light/heavy differential, in our view, is 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's 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're a little bit over $3 or in essence, about 12%. If you looked at it against Brent, the differential is well over $6.

If you looked at WTS, well, that's trading pretty much even with WTI, but of course, well under Brent in this marketplace. If you got out to the West Coast and you looked at your Kern River crude, you'd see that it's trading at over $7 under WTI. So we think it's 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. So, from our point of view, as a heavy crude oil refiner, we like where we are..

Right. Tom, maybe if I – just staying with the macro recession, macro risks are looming larger.

Having operated through several economic downturns, can you discuss your portfolio or thoughts, and maybe even CapEx flexibility, if markets remain a little weaker?.

Well I think, obviously, if you're an investor in the New York stock market and you're looking at it this morning, you're not feeling particularly well. The last time I looked, the Dow Futures were down 280 points. Obviously, we're 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. But I think the market got ahead of itself and there's no sector.

If you think about this, it 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 E&P 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 the exit doors of the United States. So we're buttoning the operation up. Certainly, Tom Nimbley or Erik or Matt Lucey or -.

I could add something there, Tom, to Evan's question specific to CapEx for the company. As Tom is saying, we're watching what you're watching. And our main priority is to keep the balance sheet strong.

And we are taking defensive steps that in case in fact we're wrong in our opinion or the like here Tom's opinion that we probably will not have a recession, but we could be wrong. We have about – in the guidance we gave you of $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 and environmental. And there's about $80 million – $100 million of discretionary. The discretionary is all on the table. We could cut that back. And in addition is 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 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's going on in the economy..

Great. I appreciate it, guys..

And we can take our next question from Roger Read with 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 that it would at least begin its restart in February. I was 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?.

Well, I actually have Jeff Dill in the office here who is going to be – is the President of 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 that they have reviewed with us when we were at California several weeks ago.

They now anticipate effectively starting the start-up activities on March 15. They have a 35-day start-up period which includes the 15 days that are required to prove out the units. So, effectively, there's a period of time where they are going to prove the ESP. Then they will start up the FCC and the attended units that have been down.

And then they will demonstrate performance over a 15-day period. If you do that math, right now, we are hopeful that we will effect the closing on May 1..

Okay. Great. That's helpful. And then, I don't know exactly who to direct the question to, but we saw in the DOE numbers yesterday a major decline in PADD 4 utilization. I recognize you're not a PADD 4 refiner, but the pricing pressure emanating out of PADD 2.

Do you see or have you had – are you seeing a condition in the PADD 2 area and maybe bleeding into the Gulf Coast that could force run cuts for any of your units?.

Tom..

Yeah. I can handle that. The short answer is yes. We have negative gas cracks in PADD 2. PADD 4 is under pressure as you suggest. We have taken steps in Toledo. We haven't necessarily – we've cut crude and we're running about 150,000 barrels a day 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've cut back the hydrocracker. We are storing some intermediates and not turning them into finished products. Obviously, Valero came out and said they were cutting back in Memphis.

I suspect that what we've seen is the euphoria 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 build. And what will likely happen or at least it is my expectation is that situation will reverse.

And you'll – it is no longer an incentive to be at max gasoline. And you can cut that back and go back to a balanced slate or effect run cuts to bring us back in balance. And I still am somewhat bullish on gasoline as I said in my opening remarks..

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

We'll take the next question from Blake Fernandez with Howard Weil..

Hey, 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 am assuming you're 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're looking at?.

Sure, Rob (sic) [Blake] (24:59). Let me just make a general comment regarding investment or opportunities that we see in Chalmette. And we're 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 emerged 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're focusing on that as one kind of pathway to improve the margin of new product markets and commercial opportunities. We've already entered the asphalt market which was not a business that they were in. It is better alternative than coker feed in fact.

And, certainly, if you have to get into the fuel oil business, we are going to start up likely a small – one of the idled units that they shut down was a petrochemical unit that would make paraxylene, ortho-xylene. We believe that's a good opportunity for us.

And then the third lane, Evan (sic) [Blake] (26:19), 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're not going to start up the coker. It's relatively small. And it really hasn't been kept in as good a condition as the other units.

Right now we believe that there is likelihood that we will start up – it may take till 2017 – all of the other units including a small, cost accretive which allow us to get back into the jet business. As I said, we budgeted $50 million to spend this year and to help us define further. We think we're going to – we're definitely honing in on this thing.

We're looking at several alternatives around the hydrocracker. We'll have that probably buttoned up here in the next three months to six months, which way we're going to go. I think the estimates of how much money we're going to spend will 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'd 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 and gasoline. I mean, just looking in the fourth quarter, looks like you had 17% of your crude and feedstock as heavy runs and then 50% yield on gasoline. I'm just curious. We've got 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's going to get to once the system is fully integrated and up and running? Like what's the max level of heavy that you could 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's 100% light. If you look at Paulsboro medium sour to heavy, that's basically the predominance in this slate. So if you're 150,000 barrels a day of crude runs, we're running 100,000 barrels a day of Saudi crude, either medium and in some cases we run light.

And then we're running Vasconia and other heavy crudes on the others still. Delaware City, we'll be typically running about an 80%/20% mix of heavy to light, 80% heavy. Waterborne is the most economic right now, ex the fact that we've taken the coker turnaround. Obviously that doesn't apply while the coker is down. Chalmette is about the same.

We're looking for options to run Bakken. They are not as economic as, frankly, the Venezuelan crude, some of the South American crude that we're running. So you're going to – and then when Torrance comes in, of course, it runs a 15 degree, 16 degree API slate.

So, on balance, we're 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, 50%, 51%. I go back to the fourth quarter.

Everybody, including PBF, turned the dials to make more gasoline, maximized conversion on the hydrocrackers, maximize conversion on cat naphthas and things of that nature. So it could go up a little higher. It did go up a little higher.

However, I suspect that it will re-equilibrate somewhere around a slight bias of 51%, 52% system-wide gasoline, 35% distillate and the rest others stuff..

That's helpful. Thanks, Tom..

We'll take the next question from Paul Sankey with Wolfe Research..

Good morning, everyone. Tom, I read about the Delaware City turnaround. I think that there was some additional commentary that you would 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 with that and if you can really train in additional barrels? I was just sort of thinking about the economics of this price deck. Thanks..

Yeah. Good question, Paul. We obviously – first of all, we're going to be running – we're running about 150,000 barrels a day of crude right now. Well, we'll be taking that up to about 130,000 barrels a day. We are running a mix but we are moving a little bit more towards 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 had coker down which should effectively shut down a piece of the crude unit and run a very light slate closer to crudes we've got coming in.

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

And how do the train economics look at these prices, just the loss to -.

You do not have economics on a total and average basis. That's in fact why – again, if you remember our course to move rail total and average all in, about $11, dependent upon what you buy the crude for in the field.

Last week, the commercial folks were telling me that we might be $5 to $6 under Brent but – I'm sorry, under TI and if you got a $2 arb on it, you're going to land it in at Brent plus $3 or $4. 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 of the economics on the heavy crudes and the medium crudes would be better. But with the coker down, in fact, it works..

Yeah. Got it. And then the technicalities of buying Iranian crude. Could you just – I mean I can understand there's an overall market impact. I guess, the Iranian crude moves into Europe and then it knocks out other equivalent blends, to the benefit of you guys. I mean, you couldn't buy Iranian crude directly.

Could you?.

No..

Is that because of ships or (32:54] -.

No. The U.S. government regulation at the present time, I don't think would allow us to bring in Iranian crude. But your analysis is correct. Most of their crude is going to go to their previous customer base in Europe, and it will simply back out other crudes..

Got you. Tom, do you have a sense for how much incremental crude we're going to see? I've seen, I think it's about 150,000 a day going to Total, 150,000 a day going to Eni in Europe.

Do you have any sense for -?.

Yeah. I think that – look, the best we can do, candidly, is what you are doing, the published reports on what they actually ship. I think you're looking at 300,000 barrels a day 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..

The next question comes from 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 year-to-date, or is this just preparations by the industry for extended turnarounds upcoming in the region?.

I'll weigh in on that, and then Tom could add. Well, first of all, the Midwest, I think it's safe to say, and you all understand is, that – and it's not I don't believe because of the – lifting the crude export ban, but the build out of the arteries (34:40), the logistics system, has effectively had to therefore return to the mean.

So the days of the very wide arbs 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 PADD. 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 exacerbated, as I said, because, frankly, even Chicago had very good cracks in the fourth quarter. And so all of the refiners, including us, were running and then you started to see, well, you're running, but the gasoline is not going to the consumer. It's going into a tank.

When that happens, typically, that's the old transfer of products – crude into products. You start to see the impact on the crack. But I think it's transient. You're getting a dump of wintertime gasoline. The Midwest market will transition earlier, in fact, the end of this month, to lower RVP gasoline. That's going to take butanes out of the pool.

And part of the pressure that's 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 midstream asset drops this year into 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've got plenty of liquidity under our revolver. And I think, at this point, we're content, based on having 1.3 times, 1.4 times coverage with PBFX, to continue down the growth path.

However, I think we're 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 midstream assets be under consideration for kind of the next drop, whenever that might occur?.

I think we've always said we don't have a preference as to what type of asset gets dropped. We're comfortable with our pool of $280 million of dropdown 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've 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..

Our next question comes from Jeff Dietert with Simmons..

Good morning..

Good morning..

Good morning..

Want to follow-up on a couple of popular topics this morning.

With the 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 summer driving season?.

Pretty much – most of it is just winter grade material because, as I said, as what happened is, in the fourth quarter with the margin environment that existed, people increased the gasoline yield and ran hot. And put wintertime gasoline in tank.

And at least, certainly in the Midwest, when the demand fell off, that's what I think has driven by the significant decrease in gas crash, because people are now doing what they've got 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 getting ready for summertime gasoline.

And it is in the area of octane and low alkaline where you get low RVP type material that we're seeing some build but predominantly it's wintertime gas..

Thanks. And then 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 light/heavy dips remain where they are, our view is that they will remain wide to, incent to do that. We will be moving more towards 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. And 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've run more like 20% light. I think most of that at Del City.

Are there – is that a sustainable slate? What are the restrictions on the East Coast, maybe more specifically at Del City, as to the minimum light crude runs?.

Yeah. It is a sustainable slate. As I said, Paulsboro basically can run full 100% mediums/heavies. And in fact that's the way we ran in the fourth quarter. Delaware – it's 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 barrels a day, 40,000 barrels a day of light crude. In fact, the model says that we can run Bakken in order to carry these heavy crudes.

When the arb moved open and the West African barrels became more attractive, we're actually looking at bringing in some light sweets from West Africa, but that has – it's kind of corrected itself.

So I think we'll run 30,000 barrels a day to 40,000 barrels a day of light crude at Delaware and mainly to allow us to carry what we consider to be very attractive heavy crude, one of which is the M16 crude that we're 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've started moving some of that material to the Delaware refinery. It also helps us on freight economics with two porting and that stuff. But to do that we need to run some light crude..

Thanks for your comments, Tom..

We'll take our next question from Edward Westlake with Credit Suisse..

Yes. Congrats on the EBITDA in the quarter. Just a question on Chalmette and Torrance. First, in your opening remarks, you said that 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 restarts obviously with some capital spend to get there.

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

Well, I will tell you. Tom made the comments that these are two of the more attractive assets that he had seen in a number of many refineries that he has acquired.

I would echo that kind of reminds us of Bayway back when I first started working with Tom, an underutilized asset, particularly Chalmette, product of a bad marriage and a joint venture with upside potential. So I think, yeah, we said $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 or hydro treated, there is a number of different options that we're looking at. And that $80 million of EBITDA, a high percentage of that is likely going to the additive to the $280 million.

But it's going to take some time. It's going to take some money. And we haven't fully landed on either of those two things yet..

Okay.

And then anything on Torrance? You mentioned the due diligence seemed to be going well in terms of understanding that asset versus your initial projections?.

Yeah. Torrance, first of all, we're 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 that we're focusing in right now, Ed, are on the commercial side.

There are going to – we've got a lot of people knocking on our doors. CRC, the California Resources got 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's probably down the road.

The key to Torrance is, 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're very hopeful that the significant amount of investment that has been put into that over the last two years will in fact correct some of the throughput (45:50) problems of that. But that's what we're going to focus on, commercial and getting it to run right..

Okay. 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 up 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 year to two years..

Ed, I think, overall, we've been fairly consistent in our message that we would like to longer-term keep net debt to cap below 40%. That's still our long-term goal. We've got the rating agencies on board with that. I think today we've got $1.4 billion or $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're 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's really the key for us..

One thing I'd add is we were somewhat lucky, at least in Chalmette and it appears as though we might be in Torrance. When we model those acquisitions, we model 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 would be the same, especially if we hit this timing in May 1 at Torrance..

Thank you..

Our next question comes from Ryan Todd with Deutsche Bank..

Thanks. Good morning, everybody. Maybe if I could follow-up on a couple 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've 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 – well, yeah, let me just comment. In addition to a very good crack, which you tell us what the crack will be and we'll tell you how sustainable it is. But, as we said, our view is that there'll be some balance 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 a favorable – we've got to get through this period, whatever it is.

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 diffs, wide, especially, as Tom says, on a percentage basis, the indications from a supply standpoint, Iran, et cetera, I would say that suggest that that has the probability of continuing.

So, in fact, in response to earlier question, we expect to actually increase the amount of medium sours that we're going to be running at Chalmette which should further improve the operation. So short answer – it wasn't a short answer but yes, we think it's sustainable..

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

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

The most obvious one that we're 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 oftentimes 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 in to Delaware City or, in fact, in some cases, directly into Paulsboro.

So the crude flexibility that we have is something that we're taking advantage of and we will continue to. That will be a synergy between the East Coast assets, particularly Delaware and Chalmette, other areas that share naphtha cargoes, things of that nature.

So, most of it's on the commercial bench just being taking advantage of the ability on freight but also by and large the cargos of naphtha as opposed to smaller cargoes and getting them into both sites..

Okay. Thanks. That's very helpful..

We'll take our next question from Paul Cheng with Barclays..

Hey, guys. Good morning..

Good morning..

Good morning..

Tom, on Chalmette, I know that you guys are going to look at the operation. I know that.

But in the short-term for the next several quarters, just curious that, can we use the fourth quarter as essentially the baseline for the unit cost and margin capture rate or that there are some one-off item in the quarter that we need to make adjustment?.

There is really nothing unusual in the two months that we ran. It was a 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 heavier crude, that we might be able to tweak that up a little bit from – what'd we run, 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'd go wrong using the same high capture rate, assuming the dips are there. Maybe it will be up a little bit..

So that's no inventory or anything that we should be concerned seeing that mix? The fourth quarter so far, the margin capture way look better or worse.

So that's actually if we have a similar margin environment in light/heavy differential, that you will expect the capture rate will 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's the situation, I would – that would be our expectation..

Sure. And just curious that, on the December energy bill, supposed to have a tax credit, $3 per bill for the East Coast refinery.

I never fully understand on that, and just wanted to make sure that – is that fully offset the additional cost of Jones Act compared to a foreign flag, if you're 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 Act versus people who are loading crude in Corpus Christi and taking it to Canada. But that $3 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?.

Yeah. It's classic Washington. They tried to put language in there that was going to be a small benefit to refiners. But as is currently written, it actually needs to be amended a bit to actually take hold. So we're not as simple as Washington. We're not counting on anything from it.

We might be able to get a minor boost from a tax perspective, but it's nothing worth modeling..

So we should not build that in and assume that you guys will be never paying through (55:33) you actually will be able to ship crude from the Gulf Coast up to the East Coast in the equipment price?.

Absolutely not..

I see. Okay..

Yeah. We have much better economics on waterborne foreign crudes and -.

So what is the current – do you get any tax credit at all, or not at all?.

We can explain it offline. It's not a tax credit. It has to do with incremental tax deductions. But, like I said, it's not worth modeling at this point. And we're happy to discuss it, but I don't want to bog down this call..

Okay. That would be great. Thank you..

We'll take our next question from Doug Leggate 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 a kind of add-on to that.

Why have the step up in exports – there's obviously been another major change in the industry – not helped alleviate at least part of the problem that we're seeing right now? I've got a quick follow-up please..

I'll give you – this is little Tom. One of the things, in terms of how quickly it could alleviate, let's put this in perspective. PBF has basically a system that can swing about 8% to 10% of its clean products production between distillate and gasoline through the various steps. And other refiners are probably – could be plus or minus on that.

But if you use a number, 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's a significant increase in gasoline production.

And then, 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 builds. Right now, everybody is going to reverse that, or certainly we're going to reverse it. I can't say what everybody else is going to do.

But we'll go back and say, well, that's 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've got a combination of people who are going to be dialing back on a GDD production.

You're going to have summertime gasoline, which is going to take all 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 (58:22) 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've read is, they think that perhaps some of the weather related problems in Gulf Coast have restricted exports, but I'm 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's really unrealistic. You are still getting exports of very light material. But the system is not there, and it's all driven by economics.

And we don't see that the ability to export is going to cure the U.S. market from a pricing point of view..

Thanks, fellas. 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, is – 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 the margins are already weak with Torrance offline. I'll leave it there. Thanks..

Yeah. Torrance – they did have – I guess here in the last month they shut down their crude unit.

They have 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.

One, to your point, when the charges of gasoline machine, as you know, the FCC, a lot of FCC, so you're going to see a pretty significant margins there, increase in gasoline out of Torrance.

Right now, the crack is coming as it has everywhere but the reality is gasoline demand year-over-year in California in 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 one is a problem in a refinery unfortunately for ExxonMobil (01:01:28) period of time is where if you run properly you can do extremely well..

Thanks, fellas. I appreciate the answers..

And we can take a follow-up from Chi Chow. Please go ahead..

Thanks. Just one follow-up.

Can you quantify the breakeven, medium and heavy crude discounts, on a percentage basis for your system and does that breakeven differ by refinery?.

We'd have to get back to you on the system. You can work out with Colin. But yes, the second piece is very clear. That's why we have these linear models. And the breakeven will move around. And so it's difficult to say exactly what they are over a longer period of time.

We can look at them at any spot time and run it through the model and it will say, yes, here's your breakeven 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 couldn't give you something that we would feel that you should run with over an extended period of time as a percentage..

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

I'd 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 and we might be misleading you. As Tom says, it's percentage based.

So you've 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 match it up to the hardware and the refinery to be able to do that. And that's why we run LPs..

Okay. Thanks..

And, ladies and gentlemen, we've reached the end of our allotted time. I'll now turn the call back to Tom Nimbley for closing remarks..

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

Okay. And, ladies and gentlemen, this does conclude our program. And we thank you for your participation. You may now disconnect. Have a great day..