Good day, everyone, and welcome to the PBF Energy Fourth Quarter and Full Year 2015 Earnings Conference Call and Webcast. At this time, all participants have been placed in a listen-only mode. The floor will be opened for your questions following management's prepared remarks. It's now my pleasure to turn the floor over to Mr. Colin Murray, Investor Relations. Please go ahead.

Thank you, Keith. Good morning and welcome to our fourth quarter earnings call. With me today are Tom O'Malley, our Executive Chairman; Tom Nimbley, our CEO; Erik Young, our CFO; and several other members of our management team. A copy of today's earnings release, including supplemental financial and operating information, is available on our website. Before getting started, I'd like to direct your attention to the forward-looking statement disclaimer contained in today's press release. In summary, it outlines that statements contained in the press release and on this call that express the company's or management's expectations or predictions of the future are forward-looking statements intended to be covered by the Safe Harbor provisions under federal securities laws. There are many factors that could cause actual results to differ from our expectations, including those we described in our filings with the SEC. As also noted in our press release, we'll be using several non-GAAP measures while describing PBF's operating performance and financial results, as we believe these metrics are useful, but they are non-GAAP measures and should be taken as such. It is important to note that we'll emphasize adjusted fully converted earnings information and results excluding special items. Our GAAP net income or GAAP EPS figures reflect the percentage interest in PBF Energy Company LLC owned by PBF Energy Inc. We think adjusted fully converted net income and EPS are meaningful metrics to you because they present 100% of the operations on an after-tax basis. During the fourth quarter of 2015, average hydrocarbon prices decreased. And, for PBF, this generated a non-cash lower of cost or market or LCM after-tax charge of approximately $209 million. In our comments today, we'll exclude this and other special items from our discussion of our quarterly results. I will now turn the call over…

Thank you very much. Certainly, we're pleased with the fourth quarter operation. I really only have two comments. The first, that our operation of Chalmette, and the due diligence that we continue to carry out on Torrance, indicates to me that our initial expectation on both refineries was low. Both refineries have substantial upside from our initial calculations. Second thing, and I think we should comment on it, as we follow it on a day-to-day basis, crude markets. Obviously, we continue to see them under pressure. We don't believe that it's going to go too much lower than the current level of $26, $27 for WTI and perhaps $1 or $2 above for Brent. But we do believe it's going to take six months to 18 months to get a sustained improvement in this pricing. For any heavy refiner, low oil prices are a benefit. We make products, such as petroleum coke and sulfur, that really aren't related too much to the actual price of the feedstock that we use. This has been quite a benefit for us. And we're pleased that it will continue for some period of time. On that note, we'd be pleased to take any questions you have.

We can take our first question from Evan Calio with Morgan Stanley. Please go ahead. Evan Calio - Morgan Stanley & Co. LLC: Yeah. Good morning, guys. Tom, maybe to pick up on your last comment, I mean, on the heavy side, you mentioned. But can you comment on how you're seeing broader crude slate options across your system? I mean light differentials are reemerging with storage capacity issues and looming Mid-Con turnaround on the heavy side, peda (14:45) base has had some recent operating issues. Just any color on how you're seeing options changing, real-time, to preserve margins in these current markets?

Well, the light/heavy differential, in our view, is going to continue to expand. You do have storage issues there, but I don't think they are going to be an overwhelming factor. When you look at these differentials, I think the important thing, always, to focus on is not the absolute level of the differential, but rather what the differential is relative to the price of crude, on a percentage basis. So that's kind of the way we always look at it, if we see a good percentage differential. And certainly, today, the differentials are very good from our perspective. If you looked at, for instance, Mars versus WTI, today, you're a little bit over $3 or in essence, about 12%. If you looked at it against Brent, the differential is well over $6. If you looked at WTS, well, that's trading pretty much even with WTI, but of course, well under Brent in this marketplace. If you got out to the West Coast and you looked at your Kern River crude, you'd see that it's trading at over $7 under WTI. So we think it's a good environment on heavy crude. And of course, part of that is the emergence of additional production from Iran. There really is no light production coming out of Iran. The average slate is going to look like our medium. So, from our point of view, as a heavy crude oil refiner, we like where we are. Evan Calio - Morgan Stanley & Co. LLC: Right. Tom, maybe if I – just staying with the macro recession, macro risks are looming larger. Having operated through several economic downturns, can you discuss your portfolio or thoughts, and maybe even CapEx flexibility, if markets remain a little weaker?

Well I think, obviously, if you're an investor in the New York stock market and you're looking at it this morning, you're not feeling particularly well. The last time I looked, the Dow Futures were down 280 points. Obviously, we're undergoing some adjustment here. Exactly why? I suppose a combination of factors, uncertainty on the political situation, certainly still a mess in the Middle East, relatively slow growth. We don't see a recession coming. When we look at consumption patterns in our industry, we see relatively slow growth. But I think the market got ahead of itself and there's no sector. If you think about this, it seems to be pushing to the upside. Certainly, the energy sector almost universally with some exception in the refining business has had a very tough time. The E&P business is a disaster. The midstream is a disaster. You go to the financial sector, certainly, everybody has been under pressure. Pharmaceuticals, obviously, are afraid of Bernie Sanders eventually being elected. It will be a rush if he is elected to the exit doors of the United States. So we're buttoning the operation up. Certainly, Tom Nimbley or Erik or Matt Lucey or - Thomas J. Nimbley - Chief Executive Officer & Director: I could add something there, Tom, to Evan's question specific to CapEx for the company. As Tom is saying, we're watching what you're watching. And our main priority is to keep the balance sheet strong. And we are taking defensive steps that in case in fact we're wrong in our opinion or the like here Tom's opinion that we probably will not have a recession, but we could be wrong. We have about – in the guidance we gave you of $475 million to $500 million system-wide in CapEx, $200 million of that is turnaround. $200 million of it is capacity maintenance, Tier 3 health safety and environmental. And there's about $80 million – $100 million of discretionary. The discretionary is all on the table. We could cut that back. And in addition is some of the Tier 3 investment that we have an option on. In other words, we can continue to use and buy credits that are available in the marketplace which would allow us to push back the physical investment to come into compliance from January 1 of 2017 to beyond. So look at in terms of somewhere around $80 million to $100 million probably of stuff that we could just say we're not going to do because we're concerned about what's going on in the economy. Evan Calio - Morgan Stanley & Co. LLC: Great. I appreciate it, guys.

And we can take our next question from Roger Read with Wells Fargo.

Good morning.

Good morning.

I guess maybe a follow-up just real quickly on Torrance. Q2 closing, the last time we talked the expectation was that it would at least begin its restart in February. I was just curious. Do you have any update on that? I mean does February still look likely or should we think about that as having slipped a little bit? Thomas J. Nimbley - Chief Executive Officer & Director: Well, I actually have Jeff Dill in the office here who is going to be – is the President of West Coast operation. He had discussions with ExxonMobil yesterday. They have indicated that they are on – actually a little bit ahead of the latest schedule that they have reviewed with us when we were at California several weeks ago. They now anticipate effectively starting the start-up activities on March 15. They have a 35-day start-up period which includes the 15 days that are required to prove out the units. So, effectively, there's a period of time where they are going to prove the ESP. Then they will start up the FCC and the attended units that have been down. And then they will demonstrate performance over a 15-day period. If you do that math, right now, we are hopeful that we will effect the closing on May 1.

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

Tom. Thomas J. Nimbley - Chief Executive Officer & Director: Yeah. I can handle that. The short answer is yes. We have negative gas cracks in PADD 2. PADD 4 is under pressure as you suggest. We have taken steps in Toledo. We haven't necessarily – we've cut crude and we're running about 150,000 barrels a day crude. It's a tough place to get rid of the crude. So cutting runs further you sometimes hurt yourself because you lose more on the crude you're selling than you are cutting back. But we have, in fact, cut back the FCC. We've cut back the hydrocracker. We are storing some intermediates and not turning them into finished products. Obviously, Valero came out and said they were cutting back in Memphis. I suspect that what we've seen is the euphoria of pretty good gas cracks going all the way to the end of the year. The refiners do what the refiners do. They ran hard and they went to max gasoline mode. And now we have seen the inventory build. And what will likely happen or at least it is my expectation is that situation will reverse. And you'll – it is no longer an incentive to be at max gasoline. And you can cut that back and go back to a balanced slate or effect run cuts to bring us back in balance. And I still am somewhat bullish on gasoline as I said in my opening remarks.

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

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

Hey, guys. Good morning. Tom, during your prepared remarks, you mentioned considering some of the restart of the idled units over at Chalmette. I was wondering – I am assuming you're still kind of in the process of getting numbers together. But could you talk a little bit about what potential costs that might have, what kind of EBITDA contribution and maybe the timeline that you're looking at? Thomas J. Nimbley - Chief Executive Officer & Director: Sure, Rob (sic) [Blake] (24:59). Let me just make a general comment regarding investment or opportunities that we see in Chalmette. And we're really focused on three areas as we continue to get more and more information around the site. One is just logistics to bottleneck. The refinery is logistically challenged. They had too much emerged at the dock. They had some constraints on being able to export gasoline because they have limitations on the recovery system, things of that nature. So we see opportunities to spend – and this is relatively small money – to put in a new crude tank as we did in Toledo. So we're focusing on that as one kind of pathway to improve the margin of new product markets and commercial opportunities. We've already entered the asphalt market which was not a business that they were in. It is better alternative than coker feed in fact. And, certainly, if you have to get into the fuel oil business, we are going to start up likely a small – one of the idled units that they shut down was a petrochemical unit that would make paraxylene, ortho-xylene. We believe that's a good opportunity for us. And then the third lane, Evan (sic) [Blake] (26:19), is frankly the bigger units that have been idled, a hydrocracker, a reformer, pre-treater and a coker, as we look at those, we suspect that we're not going to start up the coker. It's relatively small. And it really hasn't been kept in as good a condition as the other units. Right now we believe that there is likelihood that we will start up – it may take till 2017 – all of the other units including a small, cost accretive which allow us to get back into the jet business. As I said, we budgeted $50 million to spend this year and to help us define further. We think we're going to – we're definitely honing in on this thing. We're looking at several alternatives around the hydrocracker. We'll have that probably buttoned up here in the next three months to six months, which way we're going to go. I think the estimates of how much money we're going to spend will probably be somewhere between $100 million and $150 million if we do all of the restarts that I just mentioned. And I would guess that we'd probably have somewhere around $80 million to $100 million a year run rate EBITDA.

Great. And just to be clear, the $50 million you mentioned this year, is that part of the $100 million discretionary spending that you referenced earlier? Thomas J. Nimbley - Chief Executive Officer & Director: Yes, it is.

Okay. The next piece is on heavy and gasoline. I mean, just looking in the fourth quarter, looks like you had 17% of your crude and feedstock as heavy runs and then 50% yield on gasoline. I'm just curious. We've got a lot of moving pieces here with Chalmette coming into the mix and then potentially Torrance. Do you have any sense of kind of where that's going to get to once the system is fully integrated and up and running? Like what's the max level of heavy that you could run and what do you think your max gasoline yield could be? Thomas J. Nimbley - Chief Executive Officer & Director: Obviously, best to look at it by refinery. Toledo, obviously, runs zero heavy. So that's 100% light. If you look at Paulsboro medium sour to heavy, that's basically the predominance in this slate. So if you're 150,000 barrels a day of crude runs, we're running 100,000 barrels a day of Saudi crude, either medium and in some cases we run light. And then we're running Vasconia and other heavy crudes on the others still. Delaware City, we'll be typically running about an 80%/20% mix of heavy to light, 80% heavy. Waterborne is the most economic right now, ex the fact that we've taken the coker turnaround. Obviously that doesn't apply while the coker is down. Chalmette is about the same. We're looking for options to run Bakken. They are not as economic as, frankly, the Venezuelan crude, some of the South American crude that we're running. So you're going to – and then when Torrance comes in, of course, it runs a 15 degree, 16 degree API slate. So, on balance, we're probably in the 70%, 75% medium to heavy range for the total crude slate assuming the economics are there. Now one of the things that we like about our system is if they shift, we have the optionality, particularly on the East Coast and in Chalmette, to swing that around. Gasoline yield, 50%, 51%. I go back to the fourth quarter. Everybody, including PBF, turned the dials to make more gasoline, maximized conversion on the hydrocrackers, maximize conversion on cat naphthas and things of that nature. So it could go up a little higher. It did go up a little higher. However, I suspect that it will re-equilibrate somewhere around a slight bias of 51%, 52% system-wide gasoline, 35% distillate and the rest others stuff.

That's helpful. Thanks, Tom.

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

Good morning, everyone. Tom, I read about the Delaware City turnaround. I think that there was some additional commentary that you would be sourcing oil from the Bakken, but I don't see it in your press release. Could you just update us on where you are with that and if you can really train in additional barrels? I was just sort of thinking about the economics of this price deck. Thanks. Thomas J. Nimbley - Chief Executive Officer & Director: Yeah. Good question, Paul. We obviously – first of all, we're going to be running – we're running about 150,000 barrels a day of crude right now. Well, we'll be taking that up to about 130,000 barrels a day. We are running a mix but we are moving a little bit more towards Bakken. We can make money on a variable cost basis on Bakken. And we will be sourcing in some amount of Bakken. It won't be anywhere near what we did the last time we had coker down which should effectively shut down a piece of the crude unit and run a very light slate closer to crudes we've got coming in. But there will be – this economics to run, 30,000 barrels a day of Bakken into base, because it carries heavy crude and we'll probably boost that up a little bit during this downtime.

And how do the train economics look at these prices, just the loss to - Thomas J. Nimbley - Chief Executive Officer & Director: You do not have economics on a total and average basis. That's in fact why – again, if you remember our course to move rail total and average all in, about $11, dependent upon what you buy the crude for in the field. Last week, the commercial folks were telling me that we might be $5 to $6 under Brent but – I'm sorry, under TI and if you got a $2 arb on it, you're going to land it in at Brent plus $3 or $4. That's a lot better than it's been. But we would normally not run that crude in Delaware if we had the refinery running full, because of the economics on the heavy crudes and the medium crudes would be better. But with the coker down, in fact, it works.

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

No.

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

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

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

Yeah. I think that – look, the best we can do, candidly, is what you are doing, the published reports on what they actually ship. I think you're looking at 300,000 barrels a day or 400,000 barrels a day. I think they got ready for this in advance. They figured out that they were going to have a settlement. Getting it far above that, I suspect, will take quite a bit more time.

Great. Thank you, everyone.

The next question comes from Chi Chow with Tudor, Pickering, Holt. Chi Chow - Tudor, Pickering, Holt & Co. Securities, Inc.: Thank you. I guess back on the macro in the Midwest, what do you think is the underlying cause of the weak gasoline cracks there and the high inventory? Is demand particularly weak so far year-to-date, or is this just preparations by the industry for extended turnarounds upcoming in the region? Thomas J. Nimbley - Chief Executive Officer & Director: I'll weigh in on that, and then Tom could add. Well, first of all, the Midwest, I think it's safe to say, and you all understand is, that – and it's not I don't believe because of the – lifting the crude export ban, but the build out of the arteries (34:40), the logistics system, has effectively had to therefore return to the mean. So the days of the very wide arbs that let you run and still make money even with wintertime cracks are probably no longer there, unless there's an operating problem in the PADD. We're going back to where typically Chicago and the Midwest goes long in the wintertime on products. That is indeed what has happened. I think it was exacerbated, as I said, because, frankly, even Chicago had very good cracks in the fourth quarter. And so all of the refiners, including us, were running and then you started to see, well, you're running, but the gasoline is not going to the consumer. It's going into a tank. When that happens, typically, that's the old transfer of products – crude into products. You start to see the impact on the crack. But I think it's transient. You're getting a dump of wintertime gasoline. The Midwest market will transition earlier, in fact, the end of…

Our next question comes from Jeff Dietert with Simmons. Jeffery Alan Dietert - Simmons & Company International: Good morning. Thomas J. Nimbley - Chief Executive Officer & Director: Good morning. C. Erik Young - Chief Financial Officer & Senior Vice President: Good morning. Jeffery Alan Dietert - Simmons & Company International: Want to follow-up on a couple of popular topics this morning. With the gasoline inventory builds, could you talk a little bit about what type of material you think that is? Is it primarily winter grade material? Or are you stocking up high octane material to take advantage of summer driving season? Thomas J. Nimbley - Chief Executive Officer & Director: Pretty much – most of it is just winter grade material because, as I said, as what happened is, in the fourth quarter with the margin environment that existed, people increased the gasoline yield and ran hot. And put wintertime gasoline in tank. And at least, certainly in the Midwest, when the demand fell off, that's what I think has driven by the significant decrease in gas crash, because people are now doing what they've got to do to empty the tanks and get ready for the summer. And the rest of the system, there has been some gradual transitioning to getting ready for summertime gasoline. And it is in the area of octane and low alkaline where you get low RVP type material that we're seeing some build but predominantly it's wintertime gas. Jeffery Alan Dietert - Simmons & Company International: Thanks. And then following up on Chalmette, I realize you only had it for two months during the quarter. You reported 35% heavy feedstock, 32% medium, 18% light and 15% other. Is that a reasonable assumption going forward or do you anticipate moving towards more medium…

We'll take our next question from Edward Westlake with Credit Suisse. Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker): Yes. Congrats on the EBITDA in the quarter. Just a question on Chalmette and Torrance. First, in your opening remarks, you said that based on the due diligence and the operational performance that you see upside. I mean I'm just looking at your chart of $260 million of Chalmette and $360 million from Torrance. And then I hear in your comments about $80 million to $100 million of EBITDA at Chalmette from the restarts obviously with some capital spend to get there. Maybe just give us a sense of what that opening comments about those two assets perhaps been better means in terms of dollars and cents? Thomas J. Nimbley - Chief Executive Officer & Director: Well, I will tell you. Tom made the comments that these are two of the more attractive assets that he had seen in a number of many refineries that he has acquired. I would echo that kind of reminds us of Bayway back when I first started working with Tom, an underutilized asset, particularly Chalmette, product of a bad marriage and a joint venture with upside potential. So I think, yeah, we said $280 million. That $280 million, if we are right in our view, particularly on the capability of bringing the hydrocracker back, either as a hydrocracker or as a gas or hydro treated, there is a number of different options that we're looking at. And that $80 million of EBITDA, a high percentage of that is likely going to the additive to the $280 million. But it's going to take some time. It's going to take some money. And we haven't fully landed on either of those two things yet. Edward…

Our next question comes from Ryan Todd with Deutsche Bank.

Thanks. Good morning, everybody. Maybe if I could follow-up on a couple earlier ones. I appreciate the color that you gave on the potential to bring units back on at Chalmette and the growth CapEx. If we look at the results you've seen so far, your results have clearly exceeded expectations. Some of that might be from stronger headline cracks than you had in your original view, but it appears also that even in excess of the cracks, you guys have probably exceeded our expectations, your guidance with the stronger capture rate. Can you talk a little bit about what has driven the strong results to-date? How sustainable those are as well? Thomas J. Nimbley - Chief Executive Officer & Director: The latter part – well, yeah, let me just comment. In addition to a very good crack, which you tell us what the crack will be and we'll tell you how sustainable it is. But, as we said, our view is that there'll be some balance back here a little bit, but that gasoline is going to continue to be the horse that pulls the wagon. And we expect to have a favorable – we've got to get through this period, whatever it is. The other thing that helped us and continues to help and I think is sustainable is what we talked about a little bit earlier, the light/medium, light/heavy diffs, wide, especially, as Tom says, on a percentage basis, the indications from a supply standpoint, Iran, et cetera, I would say that suggest that that has the probability of continuing. So, in fact, in response to earlier question, we expect to actually increase the amount of medium sours that we're going to be running at Chalmette which should further improve the operation. So short answer – it wasn't a short answer but yes, we think it's sustainable.

Thank you. Thanks. That's helpful. And then maybe one more. You mentioned in the press release and a couple times in your comments about the ability that you have now to kind of run particularly the East Coast and Chalmette together as more of an integrated system to maximize profitability. Can you talk a little bit about – I guess about what that means on a granular point of view? What are the opportunities that you have that you see right now to run that as kind of an integrated system and what are maybe some opportunities in the future that you see to maximize that? Thomas J. Nimbley - Chief Executive Officer & Director: The most obvious one that we're seeing right now is on the crude side. Delaware doesn't have the best logistics for bringing in crude by water. We have draft restrictions, so we oftentimes sit out in Delaware Bay lightering vessels to get them to where they can get into the dock. With Chalmette and Delaware City being able to run essentially very similar crudes, we are now sourcing crudes on larger vessels, bringing them into Chalmette's dock, unloading them and then bringing them directly in to Delaware City or, in fact, in some cases, directly into Paulsboro. So the crude flexibility that we have is something that we're taking advantage of and we will continue to. That will be a synergy between the East Coast assets, particularly Delaware and Chalmette, other areas that share naphtha cargoes, things of that nature. So, most of it's on the commercial bench just being taking advantage of the ability on freight but also by and large the cargos of naphtha as opposed to smaller cargoes and getting them into both sites.

Okay. Thanks. That's very helpful.

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

Hey, guys. Good morning. Thomas J. Nimbley - Chief Executive Officer & Director: Good morning. C. Erik Young - Chief Financial Officer & Senior Vice President: Good morning.

Tom, on Chalmette, I know that you guys are going to look at the operation. I know that. But in the short-term for the next several quarters, just curious that, can we use the fourth quarter as essentially the baseline for the unit cost and margin capture rate or that there are some one-off item in the quarter that we need to make adjustment? Thomas J. Nimbley - Chief Executive Officer & Director: There is really nothing unusual in the two months that we ran. It was a relatively smooth operation, obviously a strong crack. You guys will make the determination on what you think the crack will be. When you look at capture rate, I would have to go back and look at it. I suspect, if we run right and we get some benefit from the heavier crude, that we might be able to tweak that up a little bit from – what'd we run, around 84% capture rate in the first two months, very nice capture rate. But, again, in a low flat crude environment, you should start to see that ability. So I don't think you'd go wrong using the same high capture rate, assuming the dips are there. Maybe it will be up a little bit.

So that's no inventory or anything that we should be concerned seeing that mix? The fourth quarter so far, the margin capture way look better or worse. So that's actually if we have a similar margin environment in light/heavy differential, that you will expect the capture rate will be similar? Thomas J. Nimbley - Chief Executive Officer & Director: Yes. I don't think there was anything anomalous in the fourth quarter that was an accounting or an inventory effect that was there. So, frankly, again, if you stick with this low price environment, again, that is an advantage. But if that's the situation, I would – that would be our expectation.

Sure. And just curious that, on the December energy bill, supposed to have a tax credit, $3 per bill for the East Coast refinery. I never fully understand on that, and just wanted to make sure that – is that fully offset the additional cost of Jones Act compared to a foreign flag, if you're going to ship oil, let's say, from the Gulf Coast up to the East Coast? Thomas J. Nimbley - Chief Executive Officer & Director: The original intent was to try to see if that could at least offset some of the pain of Northeast refiners of being put at a potentially competitive disadvantage on the Jones Act versus people who are loading crude in Corpus Christi and taking it to Canada. But that $3 credit never really got to the finish line. It was actually much lower than that. And in fact, to be perfectly candid, the way the law was written, it really doesn't even exist as a credit. Is that fair to say, Matthew?

Yeah. It's classic Washington. They tried to put language in there that was going to be a small benefit to refiners. But as is currently written, it actually needs to be amended a bit to actually take hold. So we're not as simple as Washington. We're not counting on anything from it. We might be able to get a minor boost from a tax perspective, but it's nothing worth modeling.

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

Absolutely not.

I see. Okay. Thomas J. Nimbley - Chief Executive Officer & Director: Yeah. We have much better economics on waterborne foreign crudes and -

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

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

Okay. That would be great. Thank you.

We'll take our next question from Doug Leggate with Bank of America Merrill Lynch.

Thanks. Good morning, everybody. Tom – either Tom, I wonder if you could give us your perspective on how long you think this winter gasoline overhang takes to clean up. And maybe just a kind of add-on to that. Why have the step up in exports – there's obviously been another major change in the industry – not helped alleviate at least part of the problem that we're seeing right now? I've got a quick follow-up please. Thomas J. Nimbley - Chief Executive Officer & Director: I'll give you – this is little Tom. One of the things, in terms of how quickly it could alleviate, let's put this in perspective. PBF has basically a system that can swing about 8% to 10% of its clean products production between distillate and gasoline through the various steps. And other refiners are probably – could be plus or minus on that. But if you use a number, 10%, and you go back to the fourth quarter, where you had this very favorable bullish gasoline environment and a distillate overhang, and everybody cranked up and took that 10%, on a 9 million barrel a day production base, that's 8.5%. It's a significant increase in gasoline production. And then, frankly, I don't think there was poor demand. I just think we cranked all of the distillate, turned it into gasoline, and we started to see some builds. Right now, everybody is going to reverse that, or certainly we're going to reverse it. I can't say what everybody else is going to do. But we'll go back and say, well, that's not the right way to run the system. When you look at the current gasoline cracks, the model tells you you're not going to run it that way. So I don't think it's going to take that long. You've got a combination of people who are going to be dialing back on a GDD production. You're going to have summertime gasoline, which is going to take all the LPGs out of the gasoline pool and then some folks, including us, are decreasing production, particularly in the Midwest right now, although you saw Trainer (58:22) is also – Delta Airlines is cutting their economics based on waterborne crudes. So I don't think it will take that long – I could be wrong – to correct. On the export side, I can only say that some of the stuff I've read is, they think that perhaps some of the weather related problems in Gulf Coast have restricted exports, but I'm not the expert in that area.

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

Thanks, fellas. My follow-up, I'm afraid, is a repeat on Torrance, I guess. I just wanted to understand properly. Is Torrance running as you understand it today? And what's behind my question is, obviously, West Coast, like everywhere else, is – the margins upcoming quite a bit. So I'm just wondering what the dynamics going into summer could look like in that market if Torrance comes back given the margins are already weak with Torrance offline. I'll leave it there. Thanks. Thomas J. Nimbley - Chief Executive Officer & Director: Yeah. Torrance – they did have – I guess here in the last month they shut down their crude unit. They have one crude unit for a short period of time, but principally has been running at significantly reduced rates and basically producing a bunch of intermediates and very – some finished products from the reformer and some of the other units, but a lot of intermediates. One, to your point, when the charges of gasoline machine, as you know, the FCC, a lot of FCC, so you're going to see a pretty significant margins there, increase in gasoline out of Torrance. Right now, the crack is coming as it has everywhere but the reality is gasoline demand year-over-year in California in last year versus 2014 was up rather significantly. And if you look at the vehicle miles traveled, indications is continuing to be there. So even with Torrance coming up, the base supply/demand situation in California does not look like it's problematic to us. And California is a place where you can move along when everything is running well and make a little bit of money or some amount of money. But the history of the state is one is a problem in a refinery unfortunately for ExxonMobil (01:01:28) period of time is where if you run properly you can do extremely well.

Thanks, fellas. I appreciate the answers.

And we can take a follow-up from Chi Chow. Please go ahead. Chi Chow - Tudor, Pickering, Holt & Co. Securities, Inc.: Thanks. Just one follow-up. Can you quantify the breakeven, medium and heavy crude discounts, on a percentage basis for your system and does that breakeven differ by refinery? Thomas J. Nimbley - Chief Executive Officer & Director: We'd have to get back to you on the system. You can work out with Colin. But yes, the second piece is very clear. That's why we have these linear models. And the breakeven will move around. And so it's difficult to say exactly what they are over a longer period of time. We can look at them at any spot time and run it through the model and it will say, yes, here's your breakeven economics, but that changes with the spread between gasoline, distillate. It changes with octane moving out, the jet premium. It's fairly complicated. So we couldn't give you something that we would feel that you should run with over an extended period of time as a percentage. Chi Chow - Tudor, Pickering, Holt & Co. Securities, Inc.: Tom, do you have any just sort of rule of thumb? Do you need a 10% or 12% discount on Maya versus light or something lower for medium crudes? Anything just to kind of get a feel. Thomas J. Nimbley - Chief Executive Officer & Director: I'd like to try to help you out, but really no. Again, it's just a little bit too complicated for us to give you something and we might be misleading you. As Tom says, it's percentage based. So you've got to look at it at a point in time and you've got to look at the whole macroeconomic environment – not macro, but specific economic environment and match it up to the hardware and the refinery to be able to do that. And that's why we run LPs. Chi Chow - Tudor, Pickering, Holt & Co. Securities, Inc.: Okay. Thanks.

And, ladies and gentlemen, we've reached the end of our allotted time. I'll now turn the call back to Tom Nimbley for closing remarks. Thomas J. Nimbley - Chief Executive Officer & Director: All right. We certainly appreciate your time. Thanks for your participation and everybody have a good day.

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