Good day, everyone. And welcome to the PBF Energy's Third Quarter 2019 Earnings Conference Call and Webcast. At this time, all participants have been placed in a listen only mode, and the floor will be open for your questions following management's prepared remarks [Operator Instructions]. Please note this call may be recorded. It is now my pleasure to turn the floor over to Colin Murray of Investor Relations. Sir, you may begin.

Thank you, Cathy. Good morning. Happy Halloween and welcome to today's call. With me today are Tom Nimbley, our CEO; Matt Lucey, our President; Erik Young, our CFO; and several other members of our management team. A copy of today's earnings release, including supplemental information, is available on our Web site. Before getting started, I'd like to direct your attention to the safe harbor statement contained in today's press release. In summary, it outlines that statements contained in the press release and on this call, which 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 describe in our filings with the SEC. Consistent with our prior quarters, we will discuss our results excluding special items. This is a net $10 million adjustment, which includes an after-tax non-cash lower of cost or market adjustment and a gain related to a land sell completed in the third quarter, which decreased our reported net income and earnings per share. As noted in our press release, we will be using certain non-GAAP measures while describing PBF's operating performance and financial results. For reconciliations of non-GAAP measures to the appropriate GAAP figure, please refer to the supplemental tables provided in today's press release. I will now turn the call over to Tom Nimbley.

Thanks, Colin. Good morning, everyone and thank you for joining our call today. Our third quarter results reflect solid operational performance in all of our regions. West Coast margins were very weak for the first couple of months of the quarter, but ended much stronger. East Coast margins were strong and with both Paulsboro and Delaware operating well, we were able to capture the benefit of those strong margins. Narrow light heavy differentials continue to be a headwind during the quarter, but predictably we are starting to shift. IMO is starting to take hold. This started over the late summer with high-sulfur fuel oil cracks coming off. Asia has stopped calling for high-sulfur fuel oil and trade flows have been disrupted. High-sulfur fuel oil has backed up into the Atlantic Basin and into Europe, and is seeking alternative disposition from its traditional home in the bunker market and as the industry prepares for IMO. High-sulfur fuel oil is competing with sour crude and the refining started for raw materials. With the collapse in HSFO cracks, the simple refiners will need to make decisions to either sweeten slates or risk producing an uneconomic barrel that no longer has a home as 3.5 million barrels a day of high-sulfur bunkers transitions to the new 0.5 fuel. Sour crude differentials are starting to widen, but not at the rapid pace that the sweet sour fuel oil has. As always, there is a lag in the physical crude market. This will take a bit more time as crude purchasing decisions are made months in advance. Additionally, sweet sour crude differentials have been very narrow over the past year with light shale growth and extraordinary circumstances, keeping sour crude off the market due to curtailment, production quotas and sanctions. These ships are indeed underway. And while continuing volatility can be expected, the fact is that sweet sour will have to widen to accommodate the penalty for making sour fuel. Sulfur is the enemy. Simply stated, complexity matters and refiners with deep converging capabilities like PBF will be at an advantage to refiners with less complex pits. We remain cautiously optimistic on the border economy. In general, the consumer is doing well. Oil demand growth is picking up in the second half of the year. From an inventory balance view, the market looks constructive in the near term. Inventories in the U.S. for crude oil, gasoline and distillate have destocked in 2019. This was in particular is low year-over-year and versus the five year average, and then we will enter IMO. I have said many times the best way to be prepared to take advantage of opportunities in the market is to have our assets operating well. We intend to run our assets in a safe, reliable and environmentally responsible manner. Now I'll turn the call over to Eric to go over our financial results for the quarter.

Thank you, Tom. Today, PBF reported an adjusted third quarter income of $0.66 per share. Third quarter EBITDA comparable to consensus estimates was approximately $272 million and adjusted EBITDA was approximately $317 million. Our third quarter results included $32 million of RIN-related obligations. At prevailing pricing, we expect full year 2019 RIN expense in the $125 million to $150 million range. We ended the quarter with over $2.2 billion of liquidity, which includes over $0.5 billion in cash and our net debt-to-cap was 30%. As expected, our front-loaded planned maintenance in 2019 provided our five refineries the opportunity to run unimpeded in Q3, which allowed us to generate more than $300 million in free cash flow. Included in that figure is consolidated CapEx of approximately $128 million, which includes $120 million for refining and corporate CapEx and $8 million incurred by PBF Logistics. As expected, our third quarter CapEx was significantly lower than the first half 2019 run rate with most of the spend associated with the coker restart and hydrogen plant tie-ins. We continue to expect full year CapEx to be in the $625 million to $675 million range. As we look forward to the end of the year, we expect our assets to continue to generate free cash flow as a result of strong market conditions and low CapEx requirements. Finally, we are pleased to announce that our Board has approved a quarterly dividend of $0.30 per share. Now I'll turn the call over to Matt.

Thank you, Erik. Our assets delivered a total throughput averaging approximately 850,000 barrels per day. Simply stated, our assets ran well during the quarter. Looking ahead, our refining system is in a good place. All of our assets are ready for Tier 3. As stated earlier, we are well-positioned for IMO. PBF circuit has already seen the changing pattern of flows as a result of the regulation. We are seeing more availability of Atlantic basin high-sulfur crack and straight run stock. We are currently running HSFO in our system with throughput ramping up to 50,000 barrels a day during the fourth quarter. Based on pricing and availability, that volume could conceivably double depending on crude slates. We are seeing improved dynamics on the East Coast with the shutdown of the Philadelphia refinery. We believe we'll see improved product realizations going forward as the Philadelphia product market went from long to relatively balance. Finally, we are coming in on time and on budget with our projects. The Chalmette coker project is in the process of starting up as we speak. It was completed on time and on budget. We believe that is coming on at exactly the right time. We made the investment decision on the coker just about a year ago. The market today and prospectively looks as good if not better than it did when we made the investment decision. Initially, at Chalmette, we are completing our last bit of maintenance for the year. We are in the midst of a catalyst change in the cat feed hydrotreater, as well as finishing a small great project that will increase our clean product yield by approximately 3,000 barrels per day. Our hydrogen plant project at Delaware City is also progressing well, and we expect that to come online towards the end of the first quarter. By adding additional hydrogen capacity at Delaware, we will be able to run additional volumes of high sulfur inputs and produce low-sulfur products. On the regulatory front, we are pleased that we came to a win-win agreement with the governing board of the South Coast Air Quality Management District, effectively ending the alkylation process review in the state of California. Lastly, we continue to work closely with Shell on completing the acquisition of the Martinez refinery. We are progressing through the second information request from FTC. And pending regulatory and other approvals, we now anticipate that the transaction will close during the first quarter of 2020. With that, we've completed our opening remarks. Operator, we would be pleased to take some questions.

[Operator instructions] Your first question comes from Roger Read with Wells Fargo. Please go ahead.

I guess if we ever write a book about refining, I'm going to title it sulfur is the enemy, if that's okay with you, Tom?

That's -- just make sure I get a [pay] for it.

All right, at least an attribution then. I guess can we dive into the very last comment there on Martinez closing in the first quarter. And obviously, there's been questions out there about laying, being able to lay out all the financing for that from a balance sheet perspective. And I was just wondering, Matt or Eric, which one of you was probably best to address that. And maybe help us a little about the timing. Are we thinking Jan 01, are we thinking March 31st, and so forth?

In regards to specific timing, the driver of it, unfortunately, the reality is it's not being driven by PBF or Shell, but we have to deal with the process. And dealing with the regulators, we've been in the midst of the second request from the FTC, and that does just take its own time. My expectation is that we would be in the first half of the first quarter. But again, it's not completely in our control. We are as bullish today as we have been. So getting it in the 10 as quickly as possible is absolutely the right story. In regards to financing, nothing has changed. I can comment if you don't want to follow up, but nothing's changed from our original announcement. In fact, our strategy and cash generation is coming in line with right where we expected. So the only other thing with Martinez that the market should be aware of is we recently announced the transaction. We were going to conduct a turnaround. That was advanced by Shell, which is nothing but good news. The only thing better than being reimbursed for the work is not having to, Martinez is up to have a very clean run in 2020.

I think on the financing side of things, just to follow up on Matt's comments. We absolutely are still 100% bought into the plan that we laid out originally in June and then reaffirmed on the last call, that ultimately the second half of this year market conditions, subject to those market conditions, would put us in a position as a result of having very low CapEx. As long as we run well, we should be able to generate significant free cash flow. And quite frankly, the third quarter is really the first step in the right direction here for us. So I know there're lots of questions around working capital rebounding. What I would say on that is we had overall operating cash flow prior to CapEx of north of $450 million. Of that, a couple of hundred million dollars of working capital came back into the system, that's bulk of that is going to come from inventory reductions. Again, we laid out a plan and I think we are executing on that plan, which was building inventories during the first half of the year that then should be reduced throughout the end of the third and fourth quarters. And we took a really big step in the right direction during the third quarter.

And then maybe just as a quick follow-up. It sounds like things are going to be really solid with IMO. We're hearing from multiple companies that they're really seeing the effect start to hit the market. As you think about the way you front end loaded your maintenance in '19, wouldn't expect you to need to do that again in '20. But I'm just curious as you take sort of an initial view of the first six months of next year, well below normal maintenance, and so you should be able to take advantage of the situation? Or is there something scheduled we need to be paying attention to at this point?

The biggest thing that is scheduled and we will execute in the first quarter is a turnaround on a FCC block at Toledo. If you look at Toledo under a special light, it really is insulated from IMO. So we will be doing a relatively large turnaround in Toledo at the end of the first quarter. As Matt said, we have a complete clean runway on Martinez when we closed that deal. And for rest of our system, we expect to be able to run high utilization rates during that first six month period, the first half the year to capture what we think will be continued strong margin environment, because of IMO related impacts.

The next question comes from Manav Gupta with Credit Suisse. Please go ahead.

Congrats on a very strong free cash flow at the end of the day. It will go a long way in supporting the Martinez deal. May first question, I know its a little bit unfair because this happened at the call stated but we just heard that Alberta is now approving rail over curtailment deal. So additional production will rise from Canada. I'm just trying to figure out if those incremental 150,000, 200,000 barrels to start hitting the U.S. market. How would your system respond to it?

We are planning -- we are running a fair amount of crude by rail, as we speak. By the way, that's a combination of Canadian heavies, a fairly significant 50,000 barrels a day still right now. And then we also run in Bakken. Frankly, that's an outflow from PES is unfortunate incident. We are now getting some of those crews that were being processed at PES in there. So that's just what we're running today. We expect to have that what to -- prior to the announcement, out thinking was we were going to run somewhere between 80,000 and 90,000 barrels a day of rail crude in the fourth quarter and maybe a little bit north of that in as we go into 2020 and about 20 that would be light and the rest would be heavy. We've been in constant touch with the Canadian Government, the NEB and most importantly, the producers. So we were actively in discussions. And we would expect -- and I thank you for telling this, because I'm waiting for this announcement for last two weeks, because it was imminent for the last two weeks. With it out there, we expect this will give us latitude to procure at reasonably good price additional heavy crude, and we have the capability both to unload it in Delaware, we can bring it further down into Chalmette. Again, it's a positive because it's going to -- these barrels are going to come in in addition to what we believe will be distressed -- more distressed barrels, or perhaps recalibrated barrels of sour crudes coming into the system.

A quick question, if you look at the refining this quarter. Three of the regions actually came in ahead of our expectations. West Coast was a little light. So I'm just trying to understand if something was off on the West Coast for you in 3Q? And given the spike we saw towards the start of this quarter, how you're thinking about capturing that spike in the West Coast margins?

You're very right on it. The first two months of the third quarter, the West Coast margins were lackluster, to say the least. The West Coast, as we recall, if you just replay history here of this year, we had a lot of operating problems and scheduled maintenance in the end of the first quarter and into the second quarter. As it usually happens, people run very hard to capture the margins. Those operating problems are passed. And in the third -- early parts of the third quarter, we had a high utilization and the cracks responded in a negative way. It did start to recover at the end of the third quarter, but we did have an operating problem where there was unfortunately some preventive maintenance being done on a hydrogen unit, a big hydrogen unit in Torrance. And it tripped off the line and we wind up losing about three days production, and that was as the margins were starting to recover rather significantly. Now as we look at the fourth quarter where this is Halloween, I'm superstitious, but we have had good operations in Torrance throughout the month of October. We obviously had a very good cracking volume and it started to again correct as some of the equipment came back. However, there's been some reported operational problems. And over the last three days, we have now gotten to a relatively very strong cracks, and the fourth quarter prospects look good.

The next question comes from Paul Cheng with Scotia Howard. Please go ahead.

Tom and Matt, I think you guys talk about you already running some high-sulfur fuel oil up to 50,000 barrels a day. Can you tell us that does it make any difference, whether that you're using the fluid coker or the coker technology? And also when you do the test one or you're running it, does it result in any low product yield differences, or efficiency loss or anything, o r really just no different? You can just replace the heavy oil? And is it one to everyone barrel that you go in or replace 2 to 3 barrel of heavy oil, or just one to one?

Okay, I'm going to try and if I don't get them all in sequence come back at me. First of all, there is a difference, it's not huge. There is the slight advantage that is available if you run the coker feeds or the fuel oil and in particular directly to a fluid coker. And without getting too technical, basically we have the capability and our fluid coker in Delaware to split that heavy fuel oil half -- a portion of it will go directly into the reactor that chews up hydraulic capacity, which is also most of the time the limiting agent for how hard you can run your coker. But in a fluid coker, you can also put some of that material into another processing unit as part of the coker called the scrubber, and that allows you to flash off the lighter products, the cutters that are in heavy fuel oil. So effectively, you get that out and you don't have to put it in a reactor. So you don't take as much of a capacity debt. On a delayed coker, you're pretty much putting the stuff into the coker directly, but you're going to have back out crude, or resid from crude if the coker is already full. Now a second piece of your question, and I think this really all gets related is, is there a back out? Well, yes. There can be depending upon the type of fuel oil you're running and most importantly, the type of crude oil that you're running, i. e., if you are running -- if we're running a bunch of Maya, very heavy crude, and we decided we want to run high-sulfur fuel into say the crude unit at Chalmette, the back out ratio would not be very significant, because Maya is such a heavy crude. If on the other hand, you were backing out maybe in our medium or MAR certainly, then you would have and your coker was full and your crude unit was full, there would be a bigger back out ratio. Finally, if I'm getting there, Paul, but basically, the way you would have to look at it is, what is the gravity of the crude oil that you're running versus the gravity and the quality of the fuel oil you are buying to put into the crude unit, and there will be a back out ratio depending upon what crudes are in there. And that's just an economic analysis of the way you want to do.

And are you guys running directly into the coker or that you mix it with the crude and run it through your distillation tower?

Both, and that's the case, we have the capability of doing particularly in some of our refineries, we can run heavy fuel oil, and today we are. In the East Coast, we are running, as Matt said, getting close to 50,000 barrels a day of heavy fuel oil and that material is bypassing the crude tower, and it's going directly into the coker unit. In other refineries, we'll run it through, when we run it, in the Chalmette, we're not running any right now, because we have a turnaround underway on a cat feed hydrotreater. We're going to initially run that through the crude unit.

And final question from me, the 2020 CapEx, any rough estimate on a pro forma basis may look like?

Paul, I think we are still going through final 2020 budgets. We've not yet got an approval from the Board on anything. So it's a bit premature. But what we would say is longer-term based on the five refinery system that we have today in the portfolio, we should at times be anywhere circa $550 million of CapEx. And probably two-thirds of that is turnaround related and about a third of it is going to be general maintenance. Depending on timing on turnarounds, you may see some fluctuations there where we're 50 high or 50 low off that number. But directionally, that's a pretty good number on an annual basis going forward.

The next question comes from Brad Heffern with RBC. Please go ahead.

First of all, I hoping we could touch on RINs. I wanted to get your thoughts on deal, and any thoughts on the trajectory of RINs as sort of the SREs go back into the RINs pool?

Consistent with last quarter on my comments, there is no question at the present that administration is working with the ag community and softening the blow maybe of some of the impacts of negotiations with China, and all the other macro things going on. But I have no doubt that this administration is committed to containing RIN prices, and they've done a reasonable job at that. They are continuously reminded by a large group of centers who have been very vocal. And so I think it's going to be more of the same. I think there's been concessions to that community, they weren't as draconian as some were predicting. But putting that aside, I think this administration is committed to not letting RINs move, I think the market generally appreciates that fact and that they lose sight of that fact, I think you'll see more actions by the EPA to address it.

And then just looking at the East Coast this quarter, you guys had the highest distillate yield I've seen for quite a while, and then you also have much more light crude runs than normal. I think the light crude side, you mentioned was potentially due to the Philadelphia Energy Solutions Bakken volumes. But can you just walk through the reasons for those two things?

I think it's a combination. We would switch in the base case given the tight light heavy differentials that existed. So we've been running some light water bonds in Delaware, in particular, and factoring in Paulsboro as well ex the lube still. But then that we had the benefit, the added benefit from the unfortunate incident at PES of the commercial people negotiating and picking up some of the crude, Bakken and other crudes that were in a few for PES, and that resulted in a relatively high light product, light crude slate, which indeed did result in a higher distillate yield. I'll make a point, because I want to -- maybe this is good time to just make the point, because people are going to have to be facing whether or not they want to switch from a medium sour that it was making high sulfur fuel oil to a lighter crude, and I do want to make sure everybody realizes that just kind of back on Paul's question on fuel, that is not a one to one. When we lightened up the crude slate in Delaware City, Delaware was blocked on how much crude it could run by naphtha yield. And so as people do that, you're going to see that effect and I just think it's important for you folks to monitor that as you go forward.

And then just finally maybe just for Eric, the Torrance plant sale during the quarter. Can you talk about what that was, and potentially what the proceeds from that were?

Yes, it's roughly $35 million of proceeds. This is consistent with the strategy that we laid out. I think we had another land sale previously. These are small parcels of land in and around Torrance not really associated with anything it has to do with day-to-day operations at the plant, ancillary land that ultimately will probably be converted into some type of alternative commercial use there.

The next question comes from Neil Mehta with Goldman Sachs. Please go ahead.

I guess my first question, it's been a couple of months since Philadelphia has gone down. And I wanted your thoughts on the long term implications you see on the loss of capacity for the East Coast market?

Yes, when you look at PADD 1 you can break it down to a section. So when you Philadelphia basin where you have R2 refineries, you have the trainer refinery and where obviously Philadelphia was, you factually reduce local clean product production by 225,000 barrels a day at RIN close to 300,000 barrels a day of total throughput. And so the environment simply went where that local production was long, and so marginal barrels would have to make its way up to New York Harbor, that's not the case anymore. And so that particular market has tightened up. We've seen our business improve as our rack volumes have increased, our disposition into Laurel has increased and our sales into New York Harbor have decreased, which is all positive. Now no different than anything else in the physical market with flows, these things do take time. You have contracts with different wholesalers or different customers that you need to change over time. So nothing is instant. But we absolutely believe our positioning within PADD 1 has improved. And then directionally, all PADD 1 is improved, because it's going to require more input from further places away.

The follow up is just, can you call out, Erik sorry if missed this, what the working capital swing was in the quarter? And just latest thoughts on the need to issue equity given the cash balances are now north of $500 million, I would think the answer is, you don't see a need for it. But just want to confirm.

Sure. We will go in reverse order. I think you know consistent with earlier comments, we are executing on the plan that we laid out based on market conditions that the second half the year, we would generate significant free cash flow to essentially replenish the cash balance and put us in a position to be able to close the deal. We're still very much in line with where we thought we would be at this point along the system. And quite frankly, I think we saw in the third quarter inventory reductions, which ultimately drove almost $150 million of working capital increase associated with inventories being reduced. So overall, working capital was north of $200 million but the vast bulk of that comes down from inventory reductions.

The next question comes from Phil Gresh with J.P. Morgan. Please go ahead.

The first question is just a follow-up to Paul's questions, when you're talking about fuel oil versus heavy crude. Tom, I think you mentioned that there'd be a slight benefit to doing that right now. And my question is more obviously, fuel oil should continue to weaken. So should we be doing kind of the days, heavy diffs versus fuel oil diffs as kind of that crossover point? And then if fuel oil continues to weaken faster than heavy crude and there is a timing effect there that would be more of a one-for-one capture for every incremental dollar of fuel oil weakening, if that make sense?

Yes I think, obviously, it depends on the spread between the crude diffs or the other option of whatever crude it is. Right now, it's very clear. We don't have -- we're starting to see some widening on the crude diffs, particularly in, say, Maya, but the rest of the sour crudes, medium sours or heavy crudes, are still not as economic as running fuel oil to the coker or fuel oil to the crude unit to get it to the coker. So that's clearly economic. And as we go forward, if indeed -- and there is another leg down on high-sulfur fuel oil in the fact that, that would be exacerbated. My only view though is that what we're likely to going to see is the light heavies or sweet sour, and it really is, I said sulfur is the enemy for a reason. I am always, not just getting rid of -- or losing the market for high-sulfur fuel oil, but it's requiring an 83% reduction in the sulfur content of the new fuel. So sulfur is really under the gun here. So we expect those crudes to, those differentials to widen out. And then it will be simply a function of if you have a crude that you are running that is economic, let's just say Basra. And you want to run fuel oil, you are going to -- and you run it through your crude unit, you are going to back out more than one barrel of crude of Basra to run one barrel of fuel oil. And then you just simply have to look at the economics of that. And it's going to be an ongoing analysis and it's really very -- actually quite complicated, because you're also going to be looking at the value of light gas oils and all other things. So it's an interesting time. It's very complicated. It's not as simple as being able to say, okay, we're going to back out 1.5 barrels of crude for every barrel of fuel oil, because it's entirely dependent upon what the crude oil that you're running.

I was trying to just come up with some kind of rule of thumb, but appreciate, that's complicated. My second question is just that I know, obviously, you're in the process here with Martinez. But in the past month or two, several other refineries from the market or are proposed in the market in PADD 4 and PADD 5 outside of California. And I just wanted to gauge your interest in continuing to pursue other opportunities outside of Martinez, or would you say your primary focus is Martinez at this point? Thanks.

Yes, I think you started the question and ended the question with the right answer, and that's we're focused on Martinez and we're focused on Martinez. We never comment on what other people are selling or potentially selling, but our focus is on Martinez.

The next question comes from Matthew Blair with Tudor, Pickering, Holt. Please go ahead.

We've seen a recent increase in tanker rates. Could you talk about how that might affect your earnings in the fourth quarter as well as into 2020?

Yes, obviously it is and again, external influences on that have impacted that some questions regarding what the attack on the Saudi facilities. I might add that I think the Saudi's ought to be congratulated for putting their customers first during that whole incident and the response to that incident, and effectively taking steps to not only protect their customers but to keep the market stable. And they were successful with that. But they did have a lock on effect rates and then of course the sanctions exacerbated that. We think that will calm down and is calming down. We also think if you look at our system, we've got five refineries and right now in Torrance and Toledo are effectively pipeline supported refiners. We have a significant amount of domestic crude oil -- Canadian crude, obviously, crude by rail that we're bringing into our East Coast system. And Chalmette runs a fair amount of Gulf Coast crude. So when you look at our system -- and the waterborne crudes that we are running in our system, whether they'd be in the rest of the East Coast, the balance with one exception or Chalmette, are effectively short haul crudes from South America, Latin America, predominantly. The one area that we have a higher conveyance is, of course, if we're running Saudi crude, which we have a contract for in Paulsboro, but we think we're somewhat insulated relative to somebody who's running a high percentage of either sweet or sour foreign crude from Europe or Asia.

And then, Tom, any thoughts on naphtha into 2020? Cracks have been pretty weak this year. Do you think naphtha will be a less appealing gasoline blend stock with Tier 3 coming into full effect in 2020?

Actually I do, it's a very good question. I don't see the naphtha went -- going away anytime soon. There is going to be more likely pressure to run sweet crudes as the need of conversion where simple refiners were running sour crudes have to take some steps. You have this ongoing tremendous increase in NGLs and the naphthas that are coming up, pentanes that are coming with that. They're competing into the petrochemical business. But the bottom-line is this naphtha lands, and I think that's going to continue. And then I get you with your situation about what you do with it. It's tough to blend it directly into gasoline. The reformers are going to have to run full and in order to generate octane to be able to pull that into the gasoline pool. But I think you're going to wind up with a distressed naphtha market continuing longer.

The next question comes from Jason Gabelman with Cowen. Please go ahead.

It looks like the gasoline market is holding up pretty well here as we head into winter from what is like a $10 a barrel crack it seems higher year-over-year. I wonder what you're seeing in the market and if you expect that strength to continue? And then just following up on the working capital benefit for the quarter. Do you expect any additional benefit to come through in the fourth quarter, or did you kind of get it all this quarter? Thanks.

I'll take the first question. And again, I go back to what is happening with IMO is this shift of 3.5 million barrels a day of high sulfur fuel oil disappearing as a market. Obviously, there will be some of that that stays, because of scrubbers but an increase in light product demand, light -- lower surfer demand of 2.8 million barrels a day. I think it's going to go across the spectrum. Again, it's just going to be an analysis and an economic analysis spectrum of jet fuel, gasoline and diesel. And if the price of gasoline goes low then there is likely -- or jet fuel goes low, you're going to have some yield shifting that takes place. And frankly, that could be because you're de-converting gasoline in the back end of the cat cracker to distillate, if you have strong prices. But obviously then things will tend to equilibrate. So we think that in fact there's a benefit across the whole light product system, because of what's happening with IMO if that make sense.

And on the working capital, again, we generated over $200 million from working capital during the second quarter, which was a bit more than we originally anticipated. The vast bulk of that, just to reiterate, was driven by reductions in inventory. And so, I think we've gotten our inventory back on a level footing where we really wanted it to be and shouldn't see material decreases in inventory as we go through the remainder of the fourth quarter. Working capital now from an AR and AP standpoint is really to be driven by where the crude price and product prices go. So we can fluctuate a bit quarter-to-quarter. But the biggest piece, I think our message is going to be, ultimately, the vast bulk of the driver of working capital coming back in the system was inventory reductions, which we've materially received during the third quarter.

The final question today comes from Doug Leggett with Bank of America. Please go ahead.

I just have two quick follow ups hopefully. Tom, I wonder if you could speak to what's happening to the sweet heavy crude market. Are you starting to see -- I'm thinking specifically about West Coast feedstock and specifically about Martinez, as you move to complete that next year. Are you starting to see any meaningful changes in relative pricing there? And if so, how would you look to try and adjust the feedstock once you take possession of Martinez?

Actually, the things that we're seeing on the West Coast are more on the some of the heavier products, if you will, that are coming out. And let me explain. Effectively, we run as you know, a significant amount of heading crude from the valley that's what we're running, and there's a significant amount of crude that Martinez runs from the same area. And that is a heavy relatively light, or light in terms of sulfur or sweet crude and the prices that remained stable. In fact, the diffs to ANS have actually widened up a little bit. But the real thing that we've seen is rather interesting, is the value of the resids, even if you don't go into a coker, we were actually selling some fuel oil or resid from the Torrance refinery now and some cat slurry, which is really the bottom of the product from the cat cracker at a premium to ANS. And that's because of the quality of the fuel, because it's high density, meaning BTU content and its low sulfur. We haven't seen it -- we've seen it on the product side first, we haven't seen really anything change by far, the economics support running domestic crude versus the waterborne heavies and that's because of the lag and then widening out and in fact, obviously, some freight.

Forgive me for this, but I'm going to completely change topics and go to the MLP. I don't think anyone's asked about that today. But you've seen one of your large competitors talked about putting a special committee together to look at their MLP. Obviously, several years ago, [Valero] bought back their MLP, the whole sector seems to have fallen out of favor. I'm just curious about how you see the role of your MLP, going forward. I guess given relatively limited growth opportunities, and whether or not it'd be better back as part of the broader system? I'll leave it there. Thank you.

The MLP market has been very frustrating to us and we are continuously evaluating it. The prospects for our MLP are good, and we've laid out a strategy for the MLP that we're delivering on. And the MLP has absolutely served the purpose for our PBF and the PBF family. But we are continuously evaluating the market, the market in which we operate in, the market that is evaluating us. And so we're certainly not making any news with these comments, but we will continue to evaluate it. But the MLP has been a net positive for our suite of companies, and the strategy laid out is in front of it. So nothing is static and we'll continue to evaluate as we go forward.

This does conclude the question-and-answer session. I would now like to turn the call over to Tom Nimbley for closing remarks.

Well, very much for your attendance and your interest today. We look forward to having another call with you at the end of the fourth quarter. Thank you.

This does conclude today's program. Thank you for your participation. You may disconnect at anytime.