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 listen-only mode, and the floor will be opened for your questions following management's prepared remarks. 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'd like to direct your attention to the forward-looking statements 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'd 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 the 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 detriment. 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'd 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'll turn the call over to Tom for his comments.

Thank you, Erik, 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 continued 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, alkylation and cat nat (6:35), the hydrotreating 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 coupled 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…

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

Hi. Good morning, everyone.

Good morning, Paul.

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? And 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'd hoped for, given as I said the backdrop was high OPEC production and okay spreads, I guess, in terms of heavy and sour crudes?

Yeah, 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 these – both of these were external power failures caused by human error. So, we don't believe they are systemic, although we are – and you'll hear further comments later probably – taking further steps to improve the electrical reliability at Torrance, but these events were caused by human error. So 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 rising crude market did impact our capture rate. But 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 sort of drive that point home, apart from Torrance, were there other areas where you had what you'd say were definitely one-off issues in the quarter that you can work to improve?

Well, 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 the 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. So we took an opportunity to advance some furnace work in advance of the turnaround we're doing now. So, there were a number of smaller – 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 TI odds (15:35) that Toledo will be cutting back crude and that's what we did in the fourth quarter, we mentioned that. But I believe that this is all basically one loss 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, certainly for gasoline is extremely weak. So, 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.

Yeah. So, I think that's a great question. Everybody asks the question and everybody has a lot of different opinions on it. Certainly, we follow a lot of consultants as you do. PIRA believes that the 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's some New York Harbor summer grade fill, because the harbor has been open to get summer grade gasoline in, we'll see that over time. And there is a question of whether or not there's 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're well aware. On inventories, distillate is a little bit better because of the colder weather. But gasoline is sitting right about where it was this time last year, and we go back to the point. If you are looking at the screen for 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. So, we're really looking at these inventories and shame on us if we fall into the same trap that we did last year.

Thank you. And we'll take our next question from Blake Fernandez with 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 just the question is around M&A.

Yeah. 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've said over the past two years that the capital markets were going to be open at very short windows. And I think we've 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. But 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 entered 2017. If there are any potential opportunities, we've 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. And aside from Tom's comments on the operational side of things, balance sheet strength is something that is extremely important to us. So, 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. So, ultimately, I don't think we have anything concrete to talk about today. It's extremely preliminary, but from our perspective, let's makes 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?

Well, very good question, Blake. The reality is that the biggest problem in Chalmette at the docks has been on the crude side and that there has been limited tankage on site. And so when the crude ships come in, they're 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 and dock – anchor offshore a bit. While the crude units pull the tank – the crude unit's tank back down, then they come in and finish pumping off the cargo. And that, obviously, not only results in significant demurrage, but you've got increased dock occupancy because you're coming back more than one occasion. So with another 625,000 barrels of the oilage, those ships will be able to point – pump off and leave. That creates vacancy and, therefore, we can get clean product ships into the dock that will allow us to then load up more clean product ships. And we're pretty confident we'll be able to get up to at least 30,000 barrels a day of gasoline, distillate exports with this project. But 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're going to see benefits, we believe, on demurrage, crude exports and improved crude flexibility at Chalmette.

Got it. Thank you.

Thank you. And we'll take our next question from Doug Leggate with Bank of America Merrill Lynch. Please go ahead. Your line is open.

Hey, guys. This is Kalei on for Doug. Good morning.

Good morning.

So, a couple of questions from me and this is sort of a follow-up to Paul's question. The reports are starting to indicate rather strong compliance from OPEC in regards to those production cuts. And a couple of your peers in the Gulf have noted that they're starting to see reduced allocations from OPEC suppliers. Wondering if you guys are starting to see the same from your perspective and 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 with it. 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. So, getting the volumes has not been an issue, although there have been periods of time where we've had weather-related delays. We had to cut back Delaware a little bit because of loading delays coming out of Venezuela. But that's 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 heavy, and sour differentials have tightened up some. We've 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 Colombian and other crudes just to be able to force some more competition into try to blunt that, but 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 premium that a lot of guys are talking about for whatever reason. Wondering if this could be a reopener for crude by rail into the East Coast. Just want to get your thoughts.

So, it's possible, particularly if the borders tax goes, and 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 in – or tariff on imported crude, what happens to WCS? WCS has to clear the market and all of a sudden they've got this 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're chasing about three or four sentences in the blueprint in the House bill. So, we really don't know what is really going to happen here. But certainly, we apostle it, it's 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, and we'll see you in a couple of weeks at our conference.

Thank you.

Thank you.

Thank you. And our next question comes from Phil Gresh with JPMorgan. Please go ahead your line is open.

Hey. Good morning.

Good morning.

First question is this. You mentioned the RINs tailwind with RINs cost having come down. Can you remind us what full-year RINs costs ended up being in Q4, in particularly? And then as we look at this reduction in RINs prices, would you expect as we look at 1Q and 2Q, if it stays at its level, that it will flow straight through the bottom line or is some of that already in the crack?

Yeah let me...

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.

Yeah. And the second part of the question. I've been on the record, and I think there has been a debate in the industry, and there are winners and losers with RINs, that's very clear to me. I do not believe that RINs is in the crack. Now, the second part of that is if RINs move from $1 to $0.50, does that all flows through to the bottom line? Probably not, because I do think some of it, RINs costs, is in the crack and you might see a moderation. It's very clear to us that we've had a discount. And any refiner who is pumping into a pipe or going to a wholesaler has had to discount the barrel at the refinery gate, but because the wholesaler wants a piece of the RIN, the retailer 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 CVR.

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's incorrect. And then in terms of the OpEx focus at Torrance specifically, what are you looking to do there to get that down and what's the timeframe?

You're correct on the first comment. The LPO that we've talked about is not associated with the OpEx, the increases that we see. On Torrance, look – now 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 on our crude deliveries because of a problem. Well, that pretty much quickly translates into a crude cut in the refinery because there's not a lot of robust tankage, oilage and things that you can do and you can't turn around and get waterborne cargoes in as quickly as you might when you're running a waterborne operation. So, first thing, as we run reliably, the throughput will be higher and, on a unit cost basis, will bring our costs down significantly. Beyond that, Jeff Dill, who's the President of the Western Region, is with us here today and I'll ask him just to make a couple of comments, but there is a concerted effort, and we're actually referring to it as the Torrance doctrine, because of the importance of Torrance in the systems 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, and inclusive of that are the steps to further reduce operating costs. Jeff, do you have anything you would add?

Yeah. Thanks, Tom. Good morning folks. I'll 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 logistic system. So, we're really looking forward to moving that forward. But 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 we're really focused on. We've also done some rationalizing of contractors. I think we've mentioned before that there has been some change in operations management. We're continuing to improve work processes in the refinery and continuing to get our heads above water on equipment inspections and reliability on rotating equipment.

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

Yeah. Look, I think we want to try to get to a sub-$7 a barrel OpEx number. I didn't get the second part of your question.

The last question is for Tom. Just in terms of the drivers of the 1Q throughput reduction across the board, any additional color relative to the slides you put out in January. Thanks.

Well, I'm not exactly sure what we put out in January, but we – 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 weather-related delays on Delaware City, so that's down a little bit. It's nothing significant. We did go into the turnaround, but that was planned at Chalmette. And frankly, the turnaround seems to be going along okay, although they always go along okay until we have to wrap them up. But just 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. So, 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 to cut crude. So relatively minor. These things will all be fixed.

Thanks.

Thank you. And our next question comes from Roger Read with Wells Fargo. Please go ahead. Your line is open.

Yeah. Thanks. Good morning.

Good morning.

Good morning.

Just if we could maybe talk a little bit – I know it's been a little bit here talked about, but cash flows, so Q4 tough quarter, I understand that. We calculated I think about $115 million of cash out the door. I'm guessing given kind of similar guidance for Q1 and with some of the turnaround issues, we should think Q1 looks a lot like that. And 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? And then 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?

So Roger, just to confirm, I'm 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 kind of 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. So, that includes PBF Logistics as well. What's probably skewing some of the numbers is while we raised $275 million of equity that's included in the net cash number at the end of the year, we also paid down $200 million worth of debt. So, 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're looking at roughly a $50 million cash build. So, unclear if that makes sense compared to your numbers. But as we go forward, I think we're only about halfway through the first quarter. We've seen decent builds in terms of cash. We've 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. And then we do have between $50 million and $100 million of strategic capital. Again, we will touch on what Tom mentioned in his comments. But the bulk of that or over 50% of that is going to come with our spend on the reformer restart in Chalmette. One thing that 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. So, aside from what we see coming at us, I don't think we're 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're above and below those targets. But I think you guys should assume that we're going to be in and around those targets at the end of every year.

One thing I would add is, and 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 differential's a little bit more narrow than what we'd budgeted. But actually our natural gas pricing and costs are a little bit better, and the crack has held in there quite nicely and the forward crack looks very good. I think it goes back to the previous discussion, watch those inventories. But right now with the market that exists, if we can accomplish number-one objective, which is keep it between the pipes and keep the equipment running, we're going to be in okay shape.

Okay. Thanks. And then as you did for the Torrance unit, kind of the guidance on the OpEx side, what are the goals at Chalmette? I mean, 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, kind of the near term and maybe stretch goals at Chalmette?

Okay, we'll try to go with both of those. We look at this very closely. And what we've said, we wanted to certainly get below $5 a 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 a barrel. There is no reason why Chalmette should not be meeting that. It's a similar refinery. So, our plans are to ultimately get down to around that $4 a barrel level. And I will tell you that in our budget there's progress being shown towards that. That's the budget. You hold us accountable as to whether we make – how quickly we get there.

Okay. Thank you.

Thank you. And our next question comes from Jeff Dietert with Simmons. Please go ahead. Your line is open. Jeff A. Dietert - Simmons & Company International: Good morning.

Good morning. Jeff A. Dietert - Simmons & Company International: (36:55 – 37:03) the first half of the year, were those turnarounds planned previously? Is there any incremental investment that you're making there, relative to previous plans to get these plants up to your standards?

I'm sorry, Jeff, I couldn't hear the very beginning. You kind of came across – I couldn't hear it on the mic. I hate to ask you to do this. Could you repeat the question? Jeff A. Dietert - Simmons & Company International: 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?

No, pretty – the only – I'd 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 underway, as I said. By the way, we think we'll be souring up that still, when we start it up with some of the improvements that we're making. It's not significantly more investment. These are really just improvements. That unit has been on stream for a significant period of time, and let me say that it needs a turnaround. In Torrance, there's some minor things that we're doing that are geared towards improved reliability. But again, at Torrance, they did a terrific job, ExxonMobil, on the FCC and the equipment that was impacted, the alkylation unit, we got that given to us in tip-top shape. But that crude unit has run for a long period of time. And frankly, there are in-situ reliability issues that the organization there has been having to deal with that are going to be taken care of during this turnaround. Jeff A. Dietert - Simmons & Company International: Great. And 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, but the reality is the two power outages, they were somewhat aberrant, because frankly it's not like it happens all the time out there in Torrance and 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 and I'm going to ask Jeff to give you an update on where that stands.

Yeah. Thanks, Tom. And as I think we talked about last quarter, there are a number of things we have pushed and really sort of kept our boots to the throat of Southern California Edison to improve what were just basically extremely poor work practices on their part. And we've been very successful with that. We'd like to get, I think, some additional help from the regulatory community to keep the pressure on Edison to follow through. But we've had a very good cooperative relationship with them, great communication. They've replaced a great deal of cable, transformers, relay systems. They have really improved the current infrastructure that is feeding the refinery and their work practices have improved with, again, some urging, I would say, from my technical team at the refinery. And 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. And then we will take directly off that system rather than coming through the current Edison infrastructure and then work that project internally from there. Jeff A. Dietert - Simmons & Company International: Thanks for your updates.

Thank you. And we'll take our next question from Chi Chow with Tudor, Pickering, Holt. Please go ahead, your line is open. Chi Chow - Tudor, Pickering, Holt & Co. Securities, Inc.: Great. Thanks. Just I guess some additional questions on Torrance here. So, you've alluded to all these reliability issues, but are you still comfortable with your annual EBITDA guidance of $360 million at the plant? And at what point do you think you can achieve that sort of level?

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're very anxious to get those turnarounds behind us and get kind of a free runway. But yes, the $360 million is something that we're confident in. And I will tell you and I mentioned this before, I think the people of Torrance are very anxious to demonstrate their capabilities and we're going to resource that place and support it so that it becomes a very successful operation. We see the upside there. I'm also very pleased with the progress that we're making in the commercial arena on the West Coast and in Torrance. I think we're going to get some surprises, which hopefully will allow us to get to that $360 million pretty quickly. We've all ready seen some and we've been able to debottleneck the plant. And we're going to make more distillate. We can make more than 12,000 barrels a day of distillate today than they were making under ExxonMobil, and it was just because of the way they were running some of the equipment versus what we can do. Now, does that mean we're going to go at 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're taking advantage of the octane length that we have out there, the crude optionality, so long-winded there. But I am very, very confident that that's $360 million number will bear out. Chi Chow - Tudor, Pickering, Holt & Co. Securities, Inc.: So, Tom, is it kind of a 2018 type event if...

I think it starts right after we come up. There is no reason we shouldn't be burning at that rate after we get this turnaround behind us. Chi Chow - Tudor, Pickering, Holt & Co. Securities, Inc.: Okay. Jeff, I guess you talked about kind of additional crude connections at the plant. Can you give us more details on that? And yeah, just anything along those lines on the improvements there.

Yeah. So, we're looking at several different options. We talked with both the suppliers and the other crude conveyance systems, both in the LA Basin and in the 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. And the beauty of lot of these particularly connections we're exploring in the LA Basin is – involves zero capital because either the producers or the other pipeline systems can put the connections in and we all sort of recoup the benefits of that over time. So, there are various different avenues we're 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. Chi Chow - Tudor, Pickering, Holt & Co. Securities, Inc.: Okay. Great. Thanks. One final question, I guess, 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?

Yeah. I think, 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 – and 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 clean products in New York Harbor would adjust to reflect a 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's 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 export pull 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're still bringing in north of a 0.5 million barrels a day of gasoline, and that is going to set the price and that price will go up, and the rest of the PADDs 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. And then 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 kind of had it right in the column he wrote, this could be a bad policy and worst 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. And frankly, that could have an impact on the economy. And certainly, I think the people on the other side of the isle will portray it as a regressive tax on the lower class and the middle class with the overall objective of being rewarding big oil or big corporations or the E&P producers. Chi Chow - Tudor, Pickering, Holt & Co. Securities, Inc.: Would you expect PADD 1 margins to actually expand in this case?

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 those things and sometimes they get – 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%. And does that happen? Yeah, it probably does. Now, the issue that I have, Chi, 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 destruction capability. Chi Chow - Tudor, Pickering, Holt & Co. Securities, Inc.: Okay. Great. Thanks. I appreciate it.

Thank you. And our next question comes from Brad Heffern with 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. And maybe any color you could give on crack spreads have performed, like your assumptions underlying that target in 2016, how Chalmette might have done versus that target?

Well, let me take the first one first. We remain comfortable on Chalmette with the $260 million, I think, we'll go – hopefully, this turnaround continues to go well and I think 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 the – haven't impact – have a positive impact on our overall crude cost at Chalmette. And of course, then we're going to have the projects that come behind this thing in relatively short order. The $70 million to $80 million margin improvement associated with the start-up of the pretreater and the reformer and the gas plant, that's real money. That's going to happen relatively quickly and the crude tank to come behind it. So again, I really do think we have done two good acquisitions. I know it's incredulous to have, perhaps, because we haven't been able to run them yet, but that's the focus and we will be able to do that. And I'm sorry. What was the second part of the question?

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

Yeah. We did a retrofit – one-year analysis looking at Chalmette. Now, of course, in the model we had $260 million, but we didn't expect to get to $260 million in the first year. And I think we had $153 million or something like that for the first year and we came in on $125 million EBITDA. And if we'd had the cracks that we had envisioned, if you looked at that back half (50:30), we had crude differentials that were fine, but we had a drop in the 2-1-1 crack of – I think it was $1.50 or $2. If we'd had that and RINs costs, we're $25 million higher than what we have modeled. So, 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. And if you overlay that on the fact that the crack was a little bit lower, we would have outperformed.

Okay. Thanks for that. And 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 compliance costs if you had to move away from hydrofluoric.

Yeah. Look, 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 that might include a phase out of hydrofluoric acid. We've met with them. We've 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. But 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 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. We will take our next question from Paul Cheng with Barclays. Please go ahead. Your line is open.

Thank you. Hey, guys. Good morning.

Good morning, Paul.

Tom, just curious that I mean now you have sometime running the two facilities, Chalmette and Torrance, if we look back in hindsight, comparing to at the time when you make 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, simply with the market scenarios, and the amount of things that weren't 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. So, in Chalmette – and by the way, who knows, but if MARPOL goes and in 2020 you've got an international bunker fuel spec of 0.5% weight (54:53) sulfur, 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. And it's really just the commercial people that are out there working with the people inside the plant and embracing a more emergent approach to the business. And again, some of the things that Jeff mentioned in terms of getting into the gathering system, we're bringing curl in, using – (55:31) coming in through Plains' Bakersfield and 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, not so much in Chalmette, I think Chalmette – frankly, the people who have come over now completely embraced the merchant culture, and so have the people in Torrance, by the way. They're very anxious to succeed and we are going to do everything we can to help them. But frankly, that organization was probably dominated more by a corporate headquarters that was bringing a lot of people from outside engineering help, their ExxonMobil research organization. So what we've 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 knew from prior lives. And frankly, we've had to make some changes since we took it over. And 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 kind of embracing the approach that we take to run the business as a merchant refiner.

Second question then, in your first quarter new throughput guidance, which is probably 20,000 barrel per day lower than your early January one, does that involve any economic run cut (57:00) or it's just that some of the delay that you mentioned earlier like in the Delaware due to the crude supply? And whether that will have any impact on your full year and second quarter guidance comparing to what you've put out? And final one would be Tier 3, if all your facility this year will be in compliance?

Yeah. Let me take the second one first. All of our Tier 3 projects are effectively done with the exception of Chalmette. And 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's done. The Paulsboro and Delaware City was an interactive project basically as we said, running that as a system. That is done. It's important to note that that is one where we're making margin, not just taking sulfur and losing octane because we're 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. So, good story, the Chalmette refinery has done a piece of the project, but not completely and we are continuing to use credits that we've already bought so that we can push out that 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're running Delaware City at a reduced rate. We did have some slippage on Venezuelan and we've had some minor incidents there. And the West Coast is down a little bit and that's 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. But 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. And we'll take our next question from Johannes Van Der Tuin with Credit Suisse. Please go ahead, your line is open. Johannes M. L. Van Der Tuin - Credit Suisse Securities (USA) LLC (Broker): Hi. Good morning and thank you for taking my call.

Good morning. Johannes M. L. Van Der Tuin - Credit Suisse Securities (USA) LLC (Broker): Quick question, and it's getting a bit late in the call so I'll try and wrap it up quickly. You talked about the inventory picture in the country, and it has been pretty heady. There are a lot of gasoline and even diesel inventories. The one exception seems to be California. At first blush, it seems like the 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, and the head of our Commercial Group for the Western Region, Paul Davis, has been telling me for the last six to 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 this is even with some really rough weather out there that has impacted demand, just because of the rains and things of that nature. And of course, we're seeing a response in the crack. We've moved over to summer time gasoline now, and we've 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. So, 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. Johannes M. L. Van Der Tuin - Credit Suisse Securities (USA) LLC (Broker): Okay. And then 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 any issues? Has it been pretty clean? Has there been any change as the C-store chains have changed hands at all? Any color there.

Actually, we've been very pleased. Again, one of the areas of highlights is in the wholesale marketing business, and we've gotten up over 90,000 barrels a day through the rack system. That's come pretty much seamless. Again, I think 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 – Paul was able to hire his team, get people in place, start working with the econ planning group inside the refinery, and that has worked very well. Our rack business is very strong out there. Johannes M. L. Van Der Tuin - Credit Suisse Securities (USA) LLC (Broker): Perfect. Thank you very much.

Thank you. And 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 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 said that California might actually look better. I'm just wondering how the prospect of opening new markets for Torrance's gasoline production is going. And also with the consolidation in the sector, particularly in the Southwest, how you see that impacting your efforts to move Torrance production into nearby markets?

Yeah. Look, 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 plant's best net-back. 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. And 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're going to be incentivized to chase the best net-back we can get and we've 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. And 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'd look for as far as coastal versus Mid-Con, or which areas and profiles of assets most interest PBF?

Yeah, 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, and the only facility we did 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 kind of off the table. PADD 2, we certainly would be interested in looking at some of the PADD 2. But frankly, I still believe the bid/ask is going to be way too high given the gorilla (1:04:34) refineries there running WCS and those crudes. Our emphasis would be looking at hedging the position that we've 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 talked before, California is a market as demonstrated by when Exxon had their problem, a loss of the refinery can create wonderful opportunities from a margin standpoint because of the islandized 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. And our next question comes from Neil Mehta with Goldman Sachs. Please go ahead. Your line is open. Neil Mehta - Goldman Sachs & Co.: Yeah. Good morning, guys. Erik, I think you made this point, but it was a good quarter 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 a – 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 reduced inventory. I think, we will consistently go back in a rising hydrocarbon environment, refiners in general will generate strong cash margins. But as a result of marking our latest purchase on the income statement, ultimately reported earnings may be lower than what the cash generation is. And I think we saw that across our peers that have already reported and I think we saw that in our Q4 numbers as well. Neil Mehta - Goldman Sachs & Co.: Is there a number you could call out for the working capital benefit?

I think from a pure cash working capital, it's probably between $100 million and $140 million. Neil Mehta - Goldman Sachs & Co.: Perfect. Thanks so much. And 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 changing the point of obligation? Do you have a sense as you discuss this with contacts about where the new administration is headed 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. But we're pleased, obviously, that the RINs cost has come down. And it is evidence that there is an understanding, with some of the comments that have been made by the Trump, incoming administration and whether it be Attorney General, Scott Pruitt becoming, Carl Icahn's influence, the reality is RFS broken and it has been broken for some period of time. And I think that's somewhat recognized and now the question is what next, if anything. We'll see – I guess 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's several paths they could take in both. Moving the point of obligation was – the comment period I think is just about over on that. Ones 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's still a 50% or higher probability that the point of obligation gets moved. Somebody who 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. And then, again, May will be the next point, and hopeful that either through the Flores Bill or just some recognition by the administration and the EPA that they recognize that there is a finite amount of ethanol that can be put on to gasoline, face this gasoline demand in the country and they're going to use the authority that the EPA has to adjust accordingly. Now that assumes that the current court proceedings that you know 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. Neil Mehta - Goldman Sachs & Co.: All right. Thanks, guys.

Thank you. And we'll take our next question from Asad Chrobak (1:09:29) with UBS. Please go ahead. Your line is open.

Hi, guys. Thank you for squeezing me in. I have two questions. One is just a nitty-gritty with Erik. I want to make sure the CapEx numbers down, I had $325 million for turnaround so $175 million for maintenance. And then what was the strategic CapEx number? And then, for Tom, just in terms of Torrance, just beating the electrical issue again. I wanted to understand what's the regulatory approvals you need to get the direct connect. And just if we can get a better handle on timing of that and just to understand where we are in terms of working with the California Edison. I know that they can sometimes take their eye off the ball and move on other projects, and I wanted to just make sure that we're still moving forward with the direct convert and any issues that we haven't thought about. Thanks.

Asad (1:10:16), you've got the $325 million and $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.

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

Yeah. Look, on the electrical side with Edison, and as I mentioned, you've put the nail on the head. Keeping the pressure on Southern California Edison is a continual focus. I think I've learned that. It needs to come from the top-down at Edison. And we've had very good cooperation and very good access to top management at Edison to continue to move these initiatives forward for Torrance. So, that part of it has worked well and I anticipate that that relationship will continue and work well going forward. So, 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 just be permitted through the City of Torrance. And we've 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. And in terms of timing for that, is it something we can budget for this year or is it more of an 2018 event?

Yeah. More of an 2018 event. It's actually something we can spread out pretty well and we would look at it as a 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 Nimbley for any additional or closing remarks.

Thank you, everybody, for your attention on the call. And 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.