PBF Energy Inc (PBF) 2016 Q4 法說會逐字稿

Good day, everyone, and welcome to the PBF Energy fourth quarter and full year 2016 earnings call and webcast. At this time all participants have been placed in a listen only mode.

(Operator Instructions).

It is now my pleasure to turn the floor over to Colin Murray of Investor Relations. Sir, you may begin.

Thank you, Lynn. Good morning and welcome to today's call. With me today are 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. Before beginning our discussion of the fourth quarter 2016, I would like to highlight that the Company has provided full year 2017 guidance which is included in our January investor presentation available on our website.

This guidance reflects the Company's expectations on a consolidated basis for both PBF Energy and PBF Logistics. Throughput expectations for this first quarter 2017 were updated in today's press release. Should you have any questions on our guidance or other matters not covered on today's call please contact our investor relations department.

Moving on to the fourth quarter, as noted in our press release we will be using certain non-GAAP measures while describing PBF's operating performance and financial results, as we believe these metrics are useful. For reconciliations of non-GAAP measures to appropriate GAAP figures please refer to the supplemental tables provided in today's press release. I will now turn the call over to Erik Young.

Thanks, Colin. Today we reported fourth quarter 2016 net income of $71.7 million, net income attributable to PBF Energy Inc. of approximately $54.6 million and diluted earnings per share of $0.54. As a result of rising hydrocarbon prices during the fourth quarter of 2016, we generated a non-cash lower of cost or market, or LCM, after-tax benefit of approximately $122 million and the remainder of our comments today will exclude this special item.

PBF reported an operating loss of approximately $60.7 million and adjusted fully converted net loss of $74.9 million, or $0.71 per share on a fully exchanged, fully diluted basis. Included in our results is a net after-tax charge of $7.2 million or $0.07 per share related to the liquidation of higher-priced inventory, or otherwise known as a LIFO decrement.

In addition, our fourth quarter results reflect a 49% effective tax rate which includes several rate adjustments and year-end true ups. When compared to our normalized 40% tax rate, our earnings were negatively impacted by approximately $0.09 per share in the quarter. For modeling purposes, you should continue to assume an effective tax rate of 40%.

For the quarter G&A expenses were $41 million, depreciation and amortization expense was $59 million and interest expense was approximately $39 million. Our RINs purchases for the fourth quarter totaled $96 million bringing our year-to-date net RIN expense to approximately $350 million. We are encouraged by the recent decrease in RINs pricing and are hopeful for regulatory reform.

Refining and corporate CapEx for the fourth quarter was approximately $165 million, which includes $90 million for the turnaround at Paulsboro. On a comparable basis, annual CapEx for 2016 was $520 million. At this point I would like to update our 2017 CapEx guidance which changed as a result of the tank and pipeline projects which will be funded by PBF Logistics, mentioned in today's press release.

We expect that refining and corporate CapEx for 2017 will be reduced to a total of $575 million to $600 million, and PBF Logistics 2017 CapEx will increase to approximately $50 million to $75 million for the full year. We ended the quarter with liquidity of approximately $1.3 billion due to strong cash margins in the quarter. In addition, our liquidity was bolstered by our December 2016 equity raise of $275 million.

As a result, we ended the quarter with a 32% net debt to capitalization ratio and a balance sheet ready to act on any opportunities that may arise in 2017. We are pleased to announce that our Board has approved a quarterly dividend of $0.30 per share. Also of note, today PBF Logistics announced a quarterly distribution increase to $0.45 per common unit. With that, I will turn the call over to Tom for his comments.

Thank you, Eric, and good morning everyone. Our fourth quarter and full year 2016 financial results were well below our expectations. Market conditions continued to be challenging in the fourth quarter with seasonally weak gasoline margins in many regions and rising commodity prices negatively impacting our overall margin capture.

RINs continue to be a burdensome headwind. Operationally we did not perform. We left $75 million on the table in the fourth quarter and more than $300 million in terms of lost profit opportunities for the year. Almost two-thirds of the lost profit events are related to three events, the Delaware City coker outage in the first quarter, and the two external power outages at Torrance. This is obviously unacceptable and the Company is taking concrete steps to improve our reliability.

A high point in the fourth quarter was the execution of our FCC turnaround at Paulsboro. Following a record five-year run, the FCC, Appalachian and [Catnap] hydro treating units were brought down in late September and our work was completed on time and on budget by the end of October.

We continue to see the benefits of running our East Coast refineries as a combined system as we have successfully transferred intermediates between Paulsboro and Delaware to increase our Tier 3 gasoline and other high-value product yields. Despite our most profitable refinery being in turnaround for a month during the fourth quarter, the East Coast generated positive EBITDA.

Toledo, on the other hand, ran well but at reduced rates in the quarter due to poor [mid-con] refining margins. High input costs couple with particularly weak gasoline cracks resulted in the lowest quarterly capture rate that we have experienced in Toledo. This is not entirely unexpected as we are in the part of the year where demand traditionally comes off. We expect product markets to improve as we approach spring and demand picks up.

Chalmette's total throughput was in line with our expectations. Chalmette's operating expenses continue to run higher than our longer-term goals and remain an area of focus. In terms of margin captures, Chalmette's results reflect the tough refining environment and an increase relative loss on the bottom of the barrel as commodity prices increased during the quarter. Following the early October power outage Torrance ran well. Relative weakness in the gasoline markets and high commodity prices resulted in a lower than planned margin capture rate. As with Chalmette, operating reductions at Torrance continue to be a major focus, and like Chalmette, we expect to meet the long-term cost targets.

As I mentioned in my opening remarks, we did not run our refineries to the PBF standard in 2016 and improved reliability is our primary focus in 2017. If we operate and when we operate our assets safely and reliably, we will limit lost profit events and put ourselves in a position to be rewarded by the market, which benefits us as well as all of our shareholders. The Chalmette crude unit turnaround is underway and the Delaware FCC and Appalachian unit turnarounds are scheduled to begin in March.

During the Chalmette turnaround we are also completing work related to the ongoing strategic project to restart the reformer by the end of the second quarter. This project will improve high-value product yields and add an incremental $70 million to $80 million to our annual margin on the Gulf Coast.

In conjunction with PBF logistics, we are progressing with the construction of the 625,000 barrel crude tank at Chalmette and we expect the tank to be in service by late fall. As Erik mentioned, PBF Logistics is funding 100% of the project. After storage fees paid to PBFX, this year they add an additional $20 million to Chalmette's annual refining margin through direct demurrage cost savings and increased efficiency at our dock, which increases our ability to export products.

Exporting products is something we are focused on at all of our facilities. On previous calls, we have mentioned our capabilities at Chalmette and we continued to export about 22,000 barrels a day during the fourth quarter, which is about 16% of our total clean product yield. We continue to expand this activity and with dimension improvements at our docks, we should be able to increase export volumes.

We are also taking advantage of opportunities to export in all of our other regions. We have exported to Latin America markets from Torrance, to Canada from Toledo, and we have recently exported finished gasoline from the East Coast, which has traditionally, due to logistical constraints and lack of economic incentives, not been a major export market for PBF.

Beyond exports, our commercial team is also focusing on improving margins at all of our refineries by entering new local markets. On the West Coast we have been successful in increasing our wholesale business and have also moved product into the Nevada markets.

On the East Coast we are aggressively targeting new markets in Pennsylvania and Maryland. We expect our asphalt business to pick up with the announced shutdown of the neighboring Axeon plant in Paulsboro, New Jersey. We are also looking at our ability to produce incremental asphalt out of our Paulsboro, Delaware, and Chalmette facilities.

In addition to our efforts to grow our topline revenues, we continue to focus on cost control. We expect to achieve the previously mentioned cost reductions at Chalmette and Torrance and bring their total operating cost more in line with regional peers. While I have talked extensively about our challenges in 2016, let me be clear; we see significant opportunities in 2017.

We are absolutely focused on improving operational reliability at each of our facilities. Avoiding lost profit events improves safety and environmental performance and directly impacts margins and costs. The improving regulatory environment and the recent 45% decrease in the price of RIN should provide PBF, in particular, with tailwinds in 2017.

Finally, the combination of strategic projects, cost reductions and commercial initiatives will add incremental EBITDA across our system. Taken individually, each of these improvements is material and collectively they are certainly substantial.

Operator, we have completed our opening remarks and we would be pleased to take any questions.

(Operator Instructions)

Our first question comes from Paul Sankey, Wolfe Research. Please go ahead, your line is open.

Hi. Good morning, everyone. Guys, it was a quarter when OPEC production was very high and when some of your, let's say, also highly complex refiners posted results that were okay. How concerned should we be about the capture rates here? Were these one-off elements that you're obviously working to improve? Or is there some other element here to why we didn't see quite the results we would hope for? Given as I said, the backdrop was higher OPEC production and okay spreads, I guess in terms of heavy and sour crudes.

Yes, Paul, I think you're correct on that. It wasn't a problem with crude differentials. We certainly intend to prove to you that these are one-off events. The Torrance electrical -- second electrical incident -- and remember both of these were external power failures caused by human error, so we don't believe they are systemic, Although, we are -- and you will hear further comments later, probably -- taking further steps to improve the electrical reliability at Torrance. But these events were caused by human error.

When we look at the fourth quarter, we left $75 million on the table. We had a good quarter from a cash standpoint, but elements on the rise -- and crude market did impact our capture rate. As I said, if we can solve the problem, and we will, of running our refineries reliably -- that's what we are, we're a refining company. I don't have any concerns as we move forward.

Just to drive that point home. Apart from Torrance, were there other areas where you had what you would say were definitely one-off issues in the quarter that you can work --?

There's -- some of them were driven by -- we talk about differentials. I'll give you a perfect example in Chalmette. Although the heavy crude differentials and the medium crude differentials, because of what you said, OPEC continuing to produce were good, we actually decided to shut down a furnace on the sweet crude unit in Chalmette. Because sweet crudes were expensive, and we couldn't make any money on the sweet crude. We weren't making significant money on the sweet crude facility. We took an opportunity to advance some furnace work in advance of the turnaround were doing now.

There were a number smaller -- Toledo. Toledo is seasonal now, let's face it. Toledo has come back to gravity. We're going to have periods of time without the strong Brent [TIRs] that Toledo will be cutting back crude. That's what we did in the fourth quarter, we mentioned that.

I believe this is all basically one-offs associated with a little bit on the market on the sweet crude side and our own ability and capability -- demonstrated ability to run.

Got it. That's great. The current environment and the outlook for 2017 may be also pretty weak. I mean people are worried that product inventory is looking very bloated, and demand, probably weather related, but demand is certainly -- gasoline's extremely weak. Could you just give us a quick outlook on how you are seeing the market? Especially as again, our concern is as the OPEC cuts bite, this could be a tough year. Thanks.

I think that's a great question. Everybody asks the question and everybody has a lot of different opinions on it. I certainly -- we follow a lot of consultants that you do.

PIRA believes that gasoline demand is down 0.1%, when you adjust for what they believe the real export number should be. There are certainly some people, including our own folks, who believe that there is some New York Harbor, summer-grade fill because the harbor has been open to get summer-grade gasoline in. We will see that over time. There is a question of whether or not there is some winter fill, too.

My view is, let's not repeat last year's mistakes. We are pretty much in the same position, as you are well aware, on inventory. This crude is a little bit better because of the colder weather. But gasoline is sitting right about where it was this time last year. We go back to the point, if you are looking at the screen or today's crack, and you think you've got margins, and you produce but that barrel of gasoline or distillate is going into a tank, you should be very concerned of whether or not you're on a fool's errand. We've got a -- we are really looking at these inventories, and shame on us if we fall into the same trap that we did last year.

Thank you. We will take our next question from Blake Fernandez, Howard Weil. Please go ahead, your line is open.

Hey, guys, good morning. Question for you on the equity raise. Just any thoughts around the thinking behind that, and potentially how that positions you for this coming year? I think Erik mentioned some opportunities, so I guess really the gist of the question is around M&A.

I think ultimately we saw a tremendous move in the share price during the fourth quarter, clearly before the Trump administration was elected. In November, we were trading below $20 per share. We saw a big run-up. We have said over the past two years that the capital markets were going to be open at very short windows. I think we have proven over, again, 24-month period, that we try to get in and out as quickly as we can. That doesn't mean that we go out and we're irresponsible.

From our perspective we really wanted to make sure that we were in a position -- I mentioned 32% net debt to cap. That excludes special items. We wanted to align the balance sheet and be in a position as we enter 2017, if there are any potential opportunities, we have said it time and time again, we look at everything that's out there from an M&A perspective. But we have a very disciplined growth strategy.

The key is, we have to have the balance sheet to be able to execute. Aside from Tom's comments on the operational side of things, balance sheet strength is something that is extremely important to us. Ultimately, the equity raise -- while we're not trading at $27.75 today, the equity raise was something that we felt was extremely prudent as we were entering 2017. I would note: we did, from a cash generation standpoint during the fourth quarter, Tom mentioned strong cash margins. We were able to pay down $200 million worth of debt during the fourth quarter, which is an important point as well.

Ultimately, I don't think we have anything concrete to talk about today. It's extremely preliminary, but from our perspective, let's make sure that PBF is always going to be in a position to execute if the opportunity warrants.

Good deal. Thanks, Erik. The second question is on the storage project at Chalmette. I'm just curious specifically if that is more oriented toward crude or products? I'm just trying to understand is that going to help you from a crude slate standpoint, or is that going to help your capability to export product?

Both. Very good question, Blake. The reality is, the biggest problem in Chalmette at the docks has been on the crude side. In that, there's been limited tankage on site. So when the crude ships come in, they are capable of pumping off at a very rapid rate and in quick time. But they can't do it at Chalmette because as they start pumping they fill up the available tankage and literally have to move away from the dock, anchor offshore a bit while the crude units pull the crude unit tank back down. Then they come in, and finish pumping off the cargo.

That obviously not only results in significant demerge, but you've got increased in-dock occupancy because you're coming back more than one occasion. With another 625,000 barrels of ullage, those ships will be able to pump off and leave. That creates vacancy. Therefore, we can get clean product ships into the dock that will allow us to then load up more clean product ships. We are pretty confident we will be able to get up to at least 30,000 barrels a day of gasoline distillate exports with this project.

The second benefit from it, is we have more crude tankage, which gives us more flexibility to custom blend the crude receipts to the various stills. So we would see benefits, we believe, on demerge, crude exports and improved crude flexibility at Chalmette.

Got it. Thank you.

Thank you. We will take our next question from Doug Leggate with BofA Merrill Lynch. Please go ahead, your line is open

Hey, guys, this is Clay on for Doug. Good morning. A couple of questions for me. This is a follow-up to Paul's question. The reports are starting to indicate rather strong compliance from OPEC in regards to those production cuts. A couple of your peers in the Gulf had noted that they're starting to see reduced allocations from OPEC suppliers. I'm wondering if you guys are starting to see the same from your perspective? Talk about whether or not this will impact any crude decisions for the next few months.

We are not yet seeing any real issues associated -- let me put it this way. Our suppliers are performing against the contract. We're getting the crude, whether it be the Iraqis, Saudis, or Venezuelan crudes.

Th getting the volumes has not been an issue, although there have been periods of time where we have had weather related delays. We had to cut back Delaware a little bit because of loading delays coming out of Venezuela. That is kind of normal, to be honest, weather related events.

The availability of the crude has been there. I will say that we have seen tightening up of the differentials. The medium and heavier sour differentials have tightened up some. We have taken steps to actually broaden the operating envelope at all three of the real heavy sour crude refineries: Chalmette, Delaware City and Torrance. Bringing in other Columbian and other crudes just to be able to pour some competition in to try to blunt that. Certainly, there has been an impact as OPEC is starting to cut back.

Thank you. My next question is on crude by rail and border tax. Wondering if there could be a situation where we do get border tax and WTI doesn't flip to, let's say, the $10.00 premium that a lot of guys are talking about for whatever reason. I'm wondering if this could be a re-opener for crude by rail into the East Coast? I want to get your thoughts.

It's possible, particularly if the borders tax goes. We can talk about the borders tax if we want to. I think we've been talking about this for some period of time. But if the border tax goes and all of a sudden you've got a 20% increase or tariff on imported crude, what happens to WCS? WCS has to clear the market and all of a sudden they've got a very large differential. It's possible that you could bring rail economics back.

Frankly, on the borders tax itself -- first of all, I think we are chasing about three or four sentences in the blueprint and the House bill. So we really don't know what is really going to happen here. Certainly, re-postulate, it is very possible that strange things can happen. But if you force a tax like that on those crudes, they may in fact bring rail economics back. I don't think it's going to be that likely, but it's possible.

Thank you for your comments. We will see you in a couple weeks at our conference.

Thank you.

Thank you. Our next question comes from Phil Gresh, JPMorgan. Please go ahead your line is open.

Hey, good morning. First question is just, you mentioned the RINs tailwind with RINs costs having coming down. Can you remind us what full-year RINs costs ended up being in 4Q, in particular? As we look at this reduction in RINs prices, would you expect as we look at Q1 and Q2, if it stays at its level, it'll flow straight through to the bottom line, or is some of that all ready in the crack?

I'll cover the 2016. The full-year 2016 expense was roughly $350 million, and the fourth quarter was just shy of $100 million, at $96 million.

The second part of the question, I've been on the record and I think there's been a debate in the industry there are winners and losers with RINs. That's very clear to me. I do not believe that RINs was in the crack.

Now the second part of that is. If RINs moves to $1.00 to $0.50, does that all flow through to the bottom line? Probably not, because I do think some of it, the RINs cost, is in the crack, and you might see a moderation. It is very clear to us that we have had a discount at any refiner who's pumping into a pipe or going to a wholesaler has had to discount the barrel at the refinery gate because the wholesaler wants a piece of the RIN. The retailers is making some of the RIN costs.

So our belief is at least 50% of the reduction, and maybe north of that, will actually wind up flowing back to the people who are being harmed the highest, and that is the merchant refiners like ourselves and CBR.

Okay. That's helpful. Thanks. Second question is just on the OpEx focus. I assume the lost opportunity cost of $300 million does not include the OpEx. You can clarify, if that is incorrect. Then in terms of the OpEx focus at Torrance, specifically, what are you looking to do there to get that down and what is the timeframe?

You're correct on the first comment. The LPO that we have talked about is not associated with the OpEx, the increases that we see. On Torrance -- that being said, Torrance's operating costs are going to come down as soon as we can run completely square, if you will. The reality is that is a system that is very tight.

We had some episodes in the fourth quarter where we had a disruption in our crude deliveries because of a problem. That pretty much quickly translates into a crude cut in the refinery because there's not a lot of robust tankage, ullage and things that you can do to -- and you can't turn around and get water-born cargoes in as quickly as you might when you're running a waterborne operation. First thing is, if we run reliably, the throughput will be higher, and on a uni-cost basis we will bring our costs down significantly.

Beyond that, Jeff Dill is the president of the Western region is with us here today. I will ask him just to make a couple of comments.

But there is a concerted effort, and we're actually referring it to the Torrance doctrine, because of the importance of Torrance in the system, to resource up and structurally go in and improve the reliability of Torrance and allow us to capture the full potential of Torrance, which we think is very, very high. Inclusive of that are the steps to further reduce operating costs.

Jeff, do you have anything you would add?

Thanks, Tom. Good morning, folks. I will just add that the crude delivery issue that Tom was referring to was not our own system, it was the result of third parties. Our crude delivery system, through logistics and what we own at PBF Energy, has been just rock solid and a real benefit.

As a matter of fact, a lot of the future upside at Torrance is going to come from additional connections and a bit of commercialization of that logistics system. So we are really looking forward to moving that forward.

In addition, as Tom mentioned, a big part of reducing OpEx is getting the plant to run reliably. That is a huge part of the equation and that's what were really focused on. We have also done some rationalizing of contractors. I think we've mentioned before that there has been some change in operations management. We are continuing to improve more processes in the refinery and continuing to get our heads above water on equipment inspections and reliability on rotating equipment.

Okay. If you could clarify what the absolute OpEx target or per barrel target is at Torrance? When you think you can get there? If I could ask one last one? The throughput reduction in 1Q, what was the driver? Thanks.

I think we want to try to get to a sub $7.00 a barrel OpEx number. I didn't get the second part of your question.

The last question is for Tom. In terms of the drivers of the Q1 throughput reduction across the board, any additional color relative to the slides you put out in January? Thanks.

I'm not exactly sure what we put out in January, but here's the revised slide. Okay. We're going to run Toledo a little bit lower; that's very clear. Again, we're running Toledo at 130,000 barrels a day. We have had, as I said, some other related delays on Delaware City, so that's down a little bit. It is nothing significant. We did go into the turnaround, but that was planned, at Chalmette. Frankly, the turnaround seems to be going along okay, although they always go along okay until you have to wrap them up.

Relatively minor things. Torrance -- as I said Torrance is an interesting machine. It's been running very well the last several weeks. But, it doesn't take much before you get a cascading effect, so you have to cut back some things. We've had some minor events -- believe it or not, we had an event in the API water treatment plant that ultimately wound up having us cut crews. Relatively minor. These things will all be fixed.

Thanks.

Thank you. Your next question comes from Roger Read, Wells Fargo Securities, LLC. Please go ahead your line is open.

Yes. Thanks. Good morning.

Good morning.

If we could maybe talk a little bit -- I know it's been a little bit talked about, but cash flows. Q4 tough quarter, I understand that. We calculated I think about $115 million of cash out the door. I am guessing giving similar guidance for Q1and with some of the turnaround issues, we should think Q1 looks a lot like that. Then, you've got the Torrance turnaround in Q2. So I'm just wondering, as you think about managing the balance sheet and the cash flows through the first half of the year, are there any other offsets, another inventory liquidation or something like that we should consider? Also, what are the thoughts on the dividend here, given what's going to probably be three tough quarters in a row on the cash flow side?

Roger, just to confirm, I am unclear where you got the number. What we would say is for the fourth quarter we actually generated positive cash flow. This is after cash margin, less cash CapEx, cash interest. We did have a payment under our TRA, so assume that that's a tax payment.

Ultimately, I'm not going to sit here and say we generated hundreds of millions, but we did generate between $25 million and $50 million of positive cash across the overall system. That includes PBF logistics as well. What's probably skewing some of the numbers is, while we raised $275 million of equity, it's included in the net cash number at the end of the year. We also paid down $200 million worth of debt. Overall, cash balance increased by about $120 million. But on a net basis, if you strip out the $75 million of net equity proceeds, then ultimately you are looking at roughly a $50 million cash build.

Unclear if that makes sense compared to your numbers. But as we go forward -- I think, we are only about halfway through the first quarter. We have seen a decent builds in terms of cash. We paid down another $75 million under the ABL at PBF Energy. We clearly have a large CapEx number coming at us throughout the course of the year, roughly $325 million of CapEx related to multiple turnarounds that we've outlined for everyone. there's probably another $175 million of maintenance, health safety, environmental spend. Then we do have between $50 million and $100 million of strategic capital.

Again, we will touch on what Tom mentioned in his comments. The bulk of that, or over 50% of that, is going to come with our spend on the reformer restart in Chalmette. One thing we've tried to do as a result of this organic project is have PBF logistics fund a portion of the CapEx for this year.

Aside from what we see coming at us, I don't think were going to see large swings in working capital. Clearly, reducing inventory at the end of the year was a prudent move. I think there are going to be times where it ebbs and flows, but overall we have our long-term targets. There may be times where we are above and below those targets, but I think you guys should assume that we are going to be in and around those targets at the end of every year.

One thing I would add is time will tell, but where we are sitting here mid-February versus where we expected to be from a market perspective, I would agree that the crude differentials a little bit more narrow than what we had budgeted. But actually our natural gas pricing, or costs, are a little bit better. The crack has held in there, quite nicely, and the forward crack looks very good. I think it goes back to previous discussion: watch those inventories. Right now, with the market that exists, if we can accomplish number one objective. Is to keep it between the pipes and keep the equipment running, we are going to be in okay shape.

Okay. Thanks. Then, as you did for the Torrance unit, the guidance on the OpEx side, what are the goals at Chalmette? Obviously, the tank -- to add the $20 million, which I'm presuming is more of a crack capture issue than an OpEx number. What are the goals the near term and maybe stretch goals at Chalmette?

We will try to go with both of those. We look at this very closely. What we've said -- we wanted to certainly get below $5 per barrel in the relatively short term. Frankly, the stretch goal -- the competition in the Gulf Coast of the United States, our peer group, is pretty much below or around $4 per barrel. There is no reason why Chalmette should not be meeting that. It is a similar refinery.

Our plans are to ultimately get down to around that $4 barrel level. And I will tell you that in our budget there is progress being shown towards that. That's a budget. You hold us accountable as to whether we make it -- how quickly we get there.

Okay. Thank you.

Thank you. Our next question comes from Jeff Dietert, Simmons. Please go ahead, your line is open

Good morning. (Technical difficulties) the first half of the year. Were those turnarounds planned, previously? Is there any incremental investment that you are making there relative to previous plans to get these plans up to your standards?

I'm sorry Jeff I couldn't hear the very beginning you came across -- I couldn't hear it on the mic. I hate to ask you to do this. Can you repeat the question?

I'm sorry about that. At Chalmette and Torrance, you've got planned maintenance in the first half of the year. Was all this turnaround activity planned and moving forward as expected? Or are you making incremental investments there to get these plants up to your standards?

I would say there's some slight timing shift in Chalmette, as I referenced. We took an opportunity on the crude unit that is currently down and being turned around, which predominately has been run in the ExxonMobil system as a sweet crude unit. The economics on the sweet crudes with the cracks that existed in the fourth quarter were not that great, so we decided to shut down the furnace and get a jump on that. That cut crude for a period of time. The rest of the turnaround is undergoing -- is underway as I said.

By the way, we think we will be souring up that still when we start it up with some of the improvements that we are making. It is not significantly more investment. These are really just improvements. That unit has been on stream for a significant period of time. Let me say that it needs a turnaround.

In Torrance there is some minor things that we are doing that are geared towards improved reliability. Again, at Torrance they did a terrific job, ExxonMobil, on the SCC and the equipment that was impact the Appalachian unit. We got that given to us in tip-top shape. But that crude unit has run for a long period of time. Frankly, there are [insit] through reliability issues that the organization there has been having to deal with that are going to be taking care of during this turnaround.

Great. Secondly, could you talk about any kind of updates on the Torrance power situation? You were looking at hitting the mainline. What progress have you made there so far?

As I said, I want to emphasize that while we had these two events -- I hate the term events in refining. That means something bad really happened.

The reality is the two power outages, they were somewhat average because, frankly, it's not like it happens all the time out there in Torrance. They were basically a result of human error and improper procedures on the part of the outside utility. That being said, we have to get a much more robust electrical system inside Torrance.

I'm going to ask Jeff to give you an update on where that stands.

Yes, thanks, Tom. As I think we talked about last quarter, there are a number of things we have pushed and really kept our boot to the throat of Southern California Edison to improve what were just basically extremely poor work practices on their part. And we have been very successful with that. We would like to get, I think, some additional help from the regulatory community to keep the pressure on Edison to follow through.

But we have had a very good cooperative relationship with them. Great communication. They have replaced a great deal of cable, transformers, relay systems. They have really improved the current infrastructure that is feeding the refinery. Their work practices have improved with, again, some urging, I would say, from my technical team at the refinery.

We are continuing to advance and are now getting into the permitting and advanced engineering for allowing the refinery to have a direct connection to the high-voltage 220 KV system on the Edison grid. Then, we will take directly off that system rather than coming through the current Edison infrastructure, and then work that project internally from there.

Thanks for your updates.

Thank you. We will take our next question from Chi Chow, Tudor, Pickering, and Holt. Please go ahead, your line is open.

Great. Thanks. Just some additional questions on Torrance. You've alluded to all these reliability issues. Are you still comfortable with your annual EBITDA guidance of $360 million at the plant? At what point do you think you can achieve that sort of level?

Obviously -- well, the short answer is yes. Confident with the $360 million guidance. Obviously, the first half of this year will be challenged somewhat because of the turnarounds. We are very anxious to get those turnarounds behind us and get a free runway.

Yes, the $360 million is something that we are confident in. I will tell you, and I mentioned this before, I think the people of Torrance are very anxious to demonstrate their capabilities. We're going to resource that place and support it so that it becomes a very successful operation. We see the upside there.

I am also very pleased with the progress that we are making in the commercial arena on the West Coast and in Torrance. I think we are going to get some surprises, which hopefully will allow us to get to that $360 million pretty quickly. We've all ready seen some. We've been able to de-bottleneck the plant. We're going to make more distillate. We can make more than 12,000 barrels a day of distillate today then they were making under ExxonMobil. It was just because of the they were running some of the equipment versus what we can do.

Now, does that mean we are going to go up 12,000 barrels a day? No, but if the market is there, we have the capability of doing that. As we mentioned, we're in the Las Vegas market. We are taking advantage of octane length that we have out there. The crude optionality. So long-winded there, but I am very, very confident that that $360 million number will bear out.

Tom, is it a 2018 type event if --

It starts right after we've come up. There is no reason we shouldn't be burning at that rate after we get this turnaround behind us.

Okay. Jeff, you talked about additional crude connections at the plant. Can you give us more details on that? Just anything along those lines on the improvements there.

Yes. We are looking at several different options. We talked with both the suppliers and the other crude conveyance systems, both in the LA Basin and into Bakersfield-Taft area. We have already put a new truck rack in at one of our pump stations outside of Taft to bring some truck barrels into our M70 system.

The beauty of a lot of these, particularly connections we're exploring in the LA Basin, involves zero capital because either the producers or the other pipeline systems can put the connections in. We all recoup the benefits of that over time. There are various different avenues we are pursuing, both on the inbound and quite frankly on the outbound side, as well, trying to diversify our pipeline outlets to move product out of the refinery.

Okay. Great. Thanks. One final question on the border tax issue. If this is a topic, can you talk about what you would expect on product price reactions in your markets?

Yes, look, everybody's got an opinion on this, but mine is very clear. If the borders tax goes with what we understand and there's a 20% increase in the price of crude oil, I think you're going to see virtually an instantaneous reaction in PADD 1. PADD 1 is an import market, so I would expect rapidly, maybe overnight, that the price of plain products in New York Harbor would adjust to reflect the higher cost of raw materials into that import market.

The rest of the regions will then trade, probably, over time in transportation parity. It may be a little bit of a lag. It is kind of interesting with the economics that we have and the trade patterns, you actually have a stronger crack in the Gulf Coast much of the time because of the expert poll versus PADD 1 or PADD 2.

But over time, we would expect kind of an immediate reaction in PADD 1, and PADD 1 would lead the way. Some others may not believe that, but I do. Simply because it is the one area we are still bringing at a north of 0.5 million barrels a day of gasoline. That's going to set the price and that price will go up and the rest of the pads will follow. If there's a lag, maybe there is a lag, but I don't think -- ultimately, the problem with this is it's going to be borne by the consumer.

The problem with the borders tax, as I see it, not weighing in on whether or not -- how it's exactly going to be implemented. But at the end of the day, Steve Forbes had it right in the column he wrote. This could be bad policy and worse politics.

Something that increases the cost of gasoline and every other imported good into the United States by 20% is going to have a significant impact on the consumer who has a limited amount of discretionary spending capability. Frankly, that could have an impact on the economy. Certainly I think, the people on the other side of the aisle will portray it as a aggressive tax on the lower class and the middle class with the overall objective of rewarding big oil or big corporations or the E&P producers.

Would you expect PADD 1 margins to actually expand?

Yes. If you do the math, you actually do get an expansion. There's a number of consultants that the AFPM has hired and others have hired to basically go through all of this thing. Sometimes they produce volumes of paper, but basically they came down and said that you're going to wind up expanding the crack by the same 20%.

Does that happen? Yes, it probably does. The issue that I have, see, is over time a $0.50 or $0.30 or $0.50 a gallon increase in the price of gasoline and distillate is not something I would like to see from a demand disruption capability.

Okay. Great. Thanks. I appreciate it.

Thank you. Our next question comes from Brad Heffern, RBC Capital Markets. Please go ahead, your line is open.

Hi, everyone. Just as a follow-on to Chi's question. We talked about the Torrance EBITDA target. I was wondering if you could talk about the comfort with the Chalmette target? Maybe any color you could give on if crack spreads have performed like your assumptions underlying that target in 2016, how Chalmette might've done versus that target?

Will let me take the first one, first. We remain comfortable on Chalmette with the $260 million. Hopefully, this turnaround continues to go well, and I think that the folks are off to a very good start. We come up with a clean unit, and it's supposed to start up on March 3. With the cracks that we've got now and even some tightening of the crude differentials, we actually expect to blunt that by running more sour crude, Mars type crude on the sweet crude unit and not impact -- have a positive impact on our overall crude costs at Chalmette.

Of course then, we're going to have the projects that come behind this thing in relatively short order. The $70 million, $80 million margin improvement associated with the start up of the pre-treater and the reformer and the gas plant, that is real money. That is going to happen relatively quickly, and the crude tanks come behind it. Again, I really do think we have done two good acquisitions. I know it's incredulous perhaps because we haven't been able to run them yet, but that is the focus. We will be able to do that.

What is the second part of the question?

Just if cracks had held up in line with what you had assumed for that $260 million EBITDA figure, like what Chalmette might have done?

We did a one-year analysis looking at Chalmette. Of course, in the model we had $260 million, but we didn't expect to get the $260 million the first year. We had $153 million or something like that for the first year, and we came in out $125 million EBITDA. If we had had the cracks that we had envisioned -- if you looked at that back [cast], we had crude differentials that were fine. But we had a drop in the 211 Crack of -- I think it was $1.50 or $2, if we had had that and RINs costs were $25 million higher than what we had modeled. That's not an insignificant item, and that was because we obviously had the higher RINs headwinds in 2016. Even, if you just take a look at RINs alone, we would have probably met the model for the first year. If you overlay that on the fact that the crack was lower, we would have outperformed.

Okay. Thanks for that. Then maybe for Jeff Dill, since he's on. There's this potential hydrofluoric acid ban in California. I was wondering if you could talk about the impact that that could have on Torrance, and maybe a compliance cost if you had to move away from hydrofluoric?

Yes, I think it's helpful to take a step back. There's around 90 alkylation units across the country. About half of them use hydrofluoric acid; the other half use sulfuric acid.

The AQMD in Southern California came out at the end of last year saying they were going to explore rulemaking on the use of HF at the refineries in Southern California. We then later learned that might include a phase-out of hydrofluoric acid.

We've met with them. We have talked with them about what the ramifications of such a phase-out would be, as have others in the industry and, quite frankly, as well as a much broader coalition of other industry groups in California, who recognize the ramifications of this are not insignificant on a much broader scale. We will continue to have those conversations and participate in that rulemaking process in a meaningful way.

The units in Southern California, including the one in Torrance, are some of the most advanced units in the world. They have a modified form of hydrofluoric acid, and they have a large number of mitigation and safety measures built into them that you don't necessarily see on plants elsewhere in the country. So we're pretty confident that rather than moving away from this proven technology that has operated safely in Torrance for well over 50 years, instead of pushing towards a alternate technology that literally would increase the emissions from the plant that the air quality management district would be well suited to allowing these units to continue on.

Okay. Thanks.

Thank you.

(Operator Instructions)

We will take our next question from Paul Cheng, Barclays Capital. Please go ahead, your line is open.

Thank you. Hey, guys, good morning. Tom, just curious that -- now you have some time running the two facilities, Chalmette and Torrance. If we look back in hindsight, comparing to at the time when you made the purchase assessment, are there any meaningful positive or negative surprises comparing to at the time?

Yes. Good question, Paul. I think in both cases, I would say, the positives are that we probably have more upside than what we expected over the longer term, just simply with the market scenarios and the amount of things that were not done. If we take Chalmette, there's a lot of things that just was put -- not only the equipment we're looking at starting up here in the short term. A lot of things that weren't done because of the problems with the joint venture.

We look at, obviously, the ability to export more, take advantage of the -- we're in the asphalt business. We really didn't envision that when we put the model in. In Chalmette -- and by the way, who knows? But if [ma paul] goes and in 2020, you've got an international (inaudible) of 25% weight sulphur, my guess is that small idle coker at Chalmette will be brought to life because the economics could be compelling.

Similarly in Torrance, I think lots of upside on two areas. We didn't envision this 12,000 barrels a day increase that we got on distillate. That we've already executed. It's really just the commercial people that are out there working with the people inside the plant and embracing a more merchant approach to the business. Again, some of the things that Jeff mentioned in terms of getting into the gathering system, we're bringing curl in, coming in through Plains/Bakersfield. These are things that while we had some ideas there, the number of things that we're looking at doing have increased.

On the other side of the equation. We -- not so much in Chalmette. I think Chalmette, frankly, the people who have come over have now completely embraced the merchant culture, and so have the people in Torrance, by the way. They are very anxious to succeed, and we are going to do everything we can to help them.

Frankly, that organization was probably dominated more by a corporate headquarters that was bringing a lot of people from an outside engineering help, their ExxonMobil research organization. So what we have got to do -- and we've had to bring in more talent. We've changed some people out. Initially we didn't have everybody available to us from Exxon, so we put some of our own people in and people we know from prior life. Frankly, we've had to make some changes since we took it over. That's going to continue. That's going to be a process that we have to work through in terms of making sure everybody is embracing the approach that we take to run the business as a merchant refiner.

Second question, that in your first quarter, new full-year guidance, which is probably 20,000 barrel per day lower than your earnings January 1. Is [there more than economic] one, or is it just that some of the delay that you mentioned earlier (inaudible) due to the crude supply? Whether that would have any impact on your full-year and second-quarter guidance comparing to what you put out? The final one would be tier three, if all your facility this year will be in compliance?

Let me take the second one first. All of our tier three projects are effectively done with the exception of Chalmette. I might point out, they all came in on budget, on schedule, and so we instituted or started up the project in Toledo in January. That is done. The Paulsboro and Delaware City was an interactive project, basically as we said, running that as a system. That is done.

It is important to note that that is one where we are making margin, not just taking sulfur and losing octane because we are effectively putting a reformate splitter at Paulsboro, which takes the reformate from the reformer and basically moves it over to Delaware City, which extracts benzene and increases our chemicals production. Good story.

The Chalmette refinery has done a piece of the project, but not completely. We are continuing to use credits that we've all ready bought so that we can push out the capital, probably to 2018, to finish that up.

When it comes to the first quarter, we have slightly lower guidance on the East Coast. Some of that is because we had some delays that continued. We actually ran Paulsboro pretty low in the first quarter. We are running Delaware City at a reduced rate. We did have some slippage on Venezuelan, and we've had some minor incidents there. The West Coast is down a little bit, and that is, again, mainly because of some throughput reductions we've had so far during the quarter because of some either pipeline deliveries or other related events.

I don't think -- if we get these units turned around and get them up clean, I don't think it's going to have an effect on our full year.

Thank you.

Thank you. We will take our next question from Johannes Van Der Tuin, Credit Suisse. Please go ahead, your line is open.

Hi. Good morning and thank you for taking my call. A quick question. It's getting a bit late in the call, so I will try and wrap it up quickly. You've talked about the inventory picture in the country. It has been pretty [tidy]. There are a lot of gasoline and even diesel inventories. The one exception seems to be California. First question seems like inventory picture out there is a lot healthier. If you could give us some comments and color on how you see that market shaping up as the year passes.

I will. The head of our Commercial Group for the Western region, Paul Davis, has been telling me for the last six, eight weeks, things are going to get good in California, and it is because of the inventories. They are lower -- certainly, in much better position than the rest of the country is in terms of the absolute level of gasoline, days of supply. You put that in context -- and that is even with some really rough weather out there that has impacted demand, just because of the rains and things of that nature.

Of course, we're seeing a response in the crack. We have moved over to summer-time gasoline now. We got a $17 crack out there. There's 3% less gasoline production, probably, in the state now because of the light ends coming out of it. My commercial colleague and friend has told me that he thinks it's going to be a good runway, and we will hold him to that.

Okay. As a quick follow-up, how have the barrels been clearing over the rack as you've been trying to push it out to market? Have there been issues? Has it been clean? Has there been any change as the C-store chains have changed hands at all? Any good color there?

Actually, we have been very pleased. Again, one of the area of highlights is in the wholesale marketing business. We've got up over 90,000 barrels a day through the rack system. That has almost come -- that's come pretty much seamless. Again, the fact that we set up the West Coast office in Long Beach well in advance of the close, and it turned out to be well in advance of the close because the close kept slipping. But we were always able to hire his team. Get people in place. Start working with the econ planning group inside the refinery. That has worked very well. Our rack business is very strong out there.

Perfect. Thank you very much.

Thank you. Our next question comes from Fernando Valle with Citi. Please go ahead, your line is open.

Hi, guys. Thanks for squeezing me in. My question is actually on a follow-up on the Torrance commercial, the commercial effort in the Torrance. You had talked in the previous call about opening up new markets, and now you've said that California might actually look better. I'm just wondering how the prospect of opening new markets for Torrance as the gasoline production is going? Also, with consolidation in the sector, particularly in the Southwest, how you see that impacting your efforts to move towards production in the nearby markets?

Thanks, it's Jeff Dill. I would just look at it this way. We are always going to be incentivized to put the first barrels into the Southern California market. That's going to be the plants best netback. As Tom just mentioned, we've done a great job developing a wholesale business, focused both in LA and expanding out to Las Vegas. We're going to keep our wholesale customers full and honor those commitments.

Once we have those markets where we've got them fully supplied, then we're going to look where else we've got opportunities. As Tom mentioned, there was an opportunity to get some gasoline components exported over the past quarter. That was a great opportunity, not something the plant has necessarily done in the past. But we are going to be incentivized to chase the best netback we can get. We have been very successful at expanding the wholesale business and getting new customers and opening up new avenues for outlets for product from the plant.

Great. My follow-up is actually a follow-up on an earlier question. You discussed opportunities in M&A, I was just wondering if you could give us some color as to where you see -- where you would look for, as far as coastal versus mid-con or which areas and profiles of assets most interest PBF?

It's a pretty simple question for me to answer, at least give our views on. We probably couldn't buy anything in PADD 1. The only facility we really have any interest in looking at in PADD 1 is the Bayway refinery, and we're not going to be able to buy that from a regulatory standpoint. So that's off the table.

PADD 2, we certainly would be interested in looking at something in PADD 2. Frankly, I still believe the bid-ask is going to be way too high given the grill of refineries there running WCS and those crudes.

Our emphasis would be looking at hedging the position that we got effectively in PADD 3 and particularly in PADD 5 by getting another refinery. Obviously, the discipline that Erik talked about is paramount. Sometimes it's very difficult to get over paying too much for a facility. But the focus is going to be on something that would hedge Chalmette, something that in case we had a weather-related event -- and particularly as we've talked before.

California is a market, as demonstrated by when Exxon had their problem, a loss of a refinery can create wonderful opportunities from a margin standpoint because of the island-ized nature of the supply chain. If you have two refineries in that region, you obviously can blunt the impact, if the other one is running. So that would be our focus areas

Great. Appreciate that.

Thank you. Our next question comes from Neil Mehta, Goldman Sachs. Please go ahead, your line is open.

Good morning, guys. Erik, I think you made this point, but it was a good from a cash flow standpoint relative to EBITDA. Was there anything unusual here, any one-time items that could have contributed to the cash flow from operations strength, for example, a working capital swing?

There was definitely -- we got positive working capital as a result of, primarily, the price of crude or hydrocarbons overall during the fourth quarter rose when compared to end of third quarter. It was a bit volatile during the quarter, but ultimately we reduce inventory. I think we will consistently go back to -- in a rising hydrocarbon environment, refiners in general will generate strong cash markets. As a result of marking our latest purchase on the income statement, ultimately reported earnings may be lower than what the cash generation is. I think we saw that across our peers that have already reported, and I think we saw that in our Q4 numbers, as well.

Is there a number you could call out for the working capital benefit?

I think from a pure cash working capital, it is probably between $100 million and $140 million.

Perfect. Thanks so much. As a follow-up, Tom, is just on RINs. Where do you think we are from a political standpoint on this? Whether it's adapting the RVO in the second quarter, or chaining the point of obligation? Do you have a sense as you discuss this with contacts about where the new administration is head is on this?

I think -- and it is a sense and it is -- certainly, we don't have a microscope into knowing exactly what's going on. We are pleased, obviously, that the RINs costs has come down. It is evidence that there is an understanding with some of the comments that have been made by the Trump and incoming administration and whether the Attorney General Scott Pruitt becoming Carl Icahn's influence. The reality is, RFS is broken and has been broken for some period of time. I think that is somewhat recognized. Now the question is, what next, if anything? We'll see.

Pruitt is potentially getting nominated this week, although the other party is trying to hold that up. As I said at your conference, I think there is several paths they could take in both: Moving the point of obligation -- whilst, the comment period I think is just about over on that. Once the new EPA administrator is in, there will be some period of time where the comments are digested, and we will see. I personally think there is still a 50% or higher probability that the point of obligation gets moved. Somebody comes out and says they don't think it's going to get moved because it's very complicated, that's not an acceptable reason for allowing something that's broke to continue to be in existence.

Then I think, again, May will be the next point. Hopeful, that either through the Flores Bill are just some recognition by the administration and the EPA that they recognize that there is a finite amount of ethanol that can be put onto gasoline, face this gasoline demand in the country. They are going to use the authority that the EPA has to adjust accordingly. Now that assumes that the current court proceedings that are going on, the courts don't come around and say that the EPA doesn't have that authority. If they do, it's going to get kicked back to the legislature and it might move pretty quickly.

All right. Thanks, guys.

Thank you. We will take our next question from Thad Strobach with UBS. Please go ahead, your line is open.

Hi, guys. Thank you for squeezing me. I have two questions. One is just a nitty-gritty with Erik. I want to make sure the CapEx number is down. I had $325 million for turnaround, so $175 million for maintenance. Then, what was the strategic CapEx number?

Then for Tom, in terms of Torrance, just beating the electrical issue again. I wanted to understand what is the regulatory approvals you need to get the direct connect, and see if we can get a better handle on timing of that and just understand where we are in terms of working with California Edison? I know that they can sometimes take their eye off the ball and move on to other projects. I wanted to make sure that we're still moving forward with the direct convert and any issues that we haven't thought about. Thanks for

Thad, you got the $325 million and the $175 million correct. The remaining CapEx is $75 million to $100 million, again for refining and corporate. The vast bulk of that, over $50 million, would be for the reformer restart, which again is strategic capital with returns coming out of the Chalmette.

Jeff will handle the second part of your question. Good question.

On the electrical side with Edison, and as I mentioned, you put the nail on the head. Keeping the pressure on Southern California Edison is a continual focus. I think I have learned that. It needs to come from the top down at Edison. We have had very good cooperation and very good access to top management at Edison to continue to move these initiatives forward for Torrance. That part of it has worked well, and I anticipate that that relationship will continue and work well going forward. With the support of particularly the city of Torrance, we really feel like the pressure will stay on Edison and we will keep their attention focused on this.

All of the immediate actions that have been taken and that continue as far as improving existing infrastructure and replacing equipment and upgrading equipment, none of that requires any permitting per se. That work will continue and the existing infrastructure will continue to improve as we work forward on the larger project.

On the connection of connecting the refinery directly to the 220 system, the bulk of that will really be just be permitted through the city of Torrance. We have already begun meeting with them and outlining that process. We don't anticipate that to be an impediment to moving the process forward. There will be other pieces to the process, but we're pretty confident we're going to be able to work through that pretty well. It's actually a fairly short connection to get the refinery connected to the 220 system, so we believe that really works to our advantage.

Okay. In terms of timing for that, is it something we can budget for this year, or is it more of an 2018 event?

Yes, more of an 2018 event. It is actually something we can spread out pretty well, and we would look at it as a late 2018 or slightly beyond that for that to come online.

Okay. Thank you.

Thank you. I would now like to turn the conference back over to Tom and Emily for any additional or closing remarks.

Thank you, everybody, for your attention on the call. We look forward to hopefully delivering better results and reporting them at our next call. Thank you.

This is the conclusion of today's conference. Thank you for your participation. You may disconnect your line at any time and have a wonderful day.