Earnings Call: Q3 2019

Oct 31, 2019

Good day, everyone, and welcome to the PBF Energy's Third Quarter 2019 Earnings Conference Call and Webcast. 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, Catherine. Good morning. Happy Halloween, and welcome to today's call. With me today are Tom Nimbley, our CEO Matt Lucey, our President Eric 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 website. Before getting started, 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 $10,000,000 adjustment, which includes an after tax non cash lower of cost or market adjustment gain related to a land sale completed in the 3rd quarter, which decreased our reported net income and earnings per share. As noted in our press release, we'll be using certain non GAAP measures while we'll 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'll now turn the call over to Tom Nibley. Thanks, Colin. Good morning, everyone, and thank you for joining our call today. Our 3rd quarter results reflect solid operational performance in all of our regions. West Coast margins were very weak for the 1st 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 see that shift. IMO is starting to take hold. This started over the late summer with high sulfur fuel oil 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 as the industry prepares for IMO. High sulfur fuel oil is competing with sour crude in a refiner's diet for raw materials. With the collapse in HS Petal 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 3,500,000 barrels a day of high sulfur bunkers transitions to the new 0.5 fuel. Sweet 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 shifts 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 conversion capabilities like PBF will be at an advantage to refiners with less complex kits. We remain cautiously optimistic on the broader 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. Distillate in particular is lower year over year and versus the 5 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 go over our financial results for the quarter. Thank you, Tom. Today, PBF reported an adjusted 3rd quarter income of $0.66 per share. 3rd quarter EBITDA comparable to consensus estimates was approximately $272,000,000 and adjusted EBITDA was approximately 317,000,000 dollars Our Q3 results included $32,000,000 of RIN related obligations. At prevailing pricing, we expect full year 2019 RIN expense in the $125,000,000 to $150,000,000 range. We ended the quarter with over $2,200,000,000 of liquidity, which includes over $500,000,000 in cash and our net debt to cap was 30%. As expected, our front loaded planned maintenance in 2019 provided our 5 refineries the opportunity to run unimpeded in Q3, which allowed us to generate more than $300,000,000 in free cash flow. Included in that figure is consolidated CapEx of approximately $128,000,000 which includes $120,000,000 for refining and corporate CapEx and $8,000,000 incurred by PBF Logistics. As expected, our 3rd quarter CapEx was significantly lower than the first half twenty nineteen 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 $625,000,000 to $675,000,000 range. As we look forward to the end of the year, 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, Eric. 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 a changing pattern of flows as a result of the regulation. We are seeing more availability of Atlantic Basin high sulfur cracked and straight run stock. We are currently running HSFO in our system with throughput ramping up to 50,000 barrels a day during the Q4. 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 will see improved product realizations going forward as the Philadelphia product market went from long to relatively balanced. 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 and 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. Additionally, 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 upgrade 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 the FTC and pending regulatory and other approvals. We now anticipate that the transaction transaction will close during the Q1 of 2020. With that, we've completed our opening remarks. Operator, we'd be pleased to take some questions. Your first question comes from Roger Read with Wells Fargo. Please go ahead. Hi, thank you. Good morning. 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. Yes. Just make sure I get a fee for it. All right. At least an attribution, right. I guess, could we dive into the very last comment there on Martinez closing in the Q1? 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 matter, Eric, which one of you was probably best to address that and maybe help us a little on the timing. We think in Jan 1 or we think in March 31 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 you 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. Eric can comment if you want to follow-up, but nothing's changed from our original announcement. And 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 when we originally 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. And Roger, it's Eric. 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 Q3 is really the first step in the right direction here for us. So I know there are 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 $450,000,000 Of that, a couple of $100,000,000 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're 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. We took a really big step in the right direction during the Q3. Okay, great. Thanks. And then maybe just as a quick follow-up, things it sounds like things are going to be really solid with IMO. We're hearing from multiple companies that they're really seeing the effects start to hit the market. As you think about the way you front end loaded your maintenance in 2019, wouldn't expect you to need to do that again in 2020. But I'm just curious as you take sort of an initial view of the first 6 months of next year, well below normal on 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? Well, the biggest thing that is scheduled and we will execute in the Q1 is a turnaround on the 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 Q1. As Matt said, we have a complete clean runway on Martinez when we closed that deal. And for the rest of our system, we expect to be able to run high utilization rates during that first six month period or first half of the year to capture what we think will be a continued strong margin environment because of IMO related impacts. Awesome. Thank you. The next question comes from Manav Gupta with Credit Suisse. Please go ahead. Guys, congrats on a very strong free cash flow at the end of the day. It will go a long way in supporting the Martinus deal. My first question, So additional So additional production will rise from Canada. I am just trying to figure out if those incremental 150,000 to 200,000 barrels do start hitting the U. S. Market, how would your system respond to it? Yes. We are planning we are running a fair amount of crude by rail as we speak. But by the way, that's a combination of Canadian heavies, a fairly significant 50,000 barrels a day still right now. And then we are also running Bakken. Frankly, that's an outfall from PES, it's 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 go up to prior to the announcement, our thinking was we were going to run somewhere between 80000, 90000 barrels a day of rail crude in the Q4 and maybe a little bit north of that we go into 2020 and about 20 of 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 are actively in discussions and we would expect and thank you for telling us because I'm waiting for announcement for the last 2 weeks because it was imminent for the last 2 weeks. With it out there, we expect this will give us the latitude to procure at a 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. Thank you. A quick question, if you look at the refining this quarter, 3 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 much on it. The 1st 2 months of Q3, 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 Q1 into Q2. As it usually happens, people run very hard to capture the margins. Those operating problems passed and in the third early parts of the Q3, we had a high utilization and the cracks responded in a negative way. It did start to recover at the end of the Q3, 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 wound up losing about 3 days production and that was as the margins were starting to recover rather significantly. Now as we look at the Q4, 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 crack environment. It started to again correct as some of the equipment came back. However, there has been some reported operational problems and over the last 3 days, we have now gotten to relatively very strong cracks and the 4th quarter prospects look good. Thanks guys. Thanks for taking my question and congrats on a very strong free cash flow. The next question comes from Paul Cheng with Scotia Howard. Please go ahead. Hey guys, good morning. Tom and Matt, I think you guys talked about you're already running some high sulfur fuel oil up to 50,000 barrels per day. Can you tell us that, does it make any difference whether that you're using the fluid cooker or the late cooker technology? And also, when you do the test run or you're running it, does it result in any light product yield differences or efficiency loss or anything or just really just no difference, you can just replace the heavy oil? And is it 1 to every 1 barrel that you go in will replace 2 to 3 barrels of heavy oil or is 1 to 1? 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 a slight advantage that is available if you run the coke feeds or fuel oil in particular directly to a fluid coker. And without getting too technical, basically we had the capability in our fluid coker in Delaware to split that heavy fuel law, or 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 the 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 debit. 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 cocoa 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 dependent 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 decide we want to run high sulfur fuel into say the crude unit at Xiaomi, 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 an Arab medium or Mars certainly, then you would have and your cocoa was full and your crude unit was full, there would be a bigger back out ratio. So I don't know 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're buying to put into the crude unit. And there will be a back out ratio depending upon what crudes are in there. And then it's just an economic analysis as to what you want to do. And are you guys 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 being is bypassing the crude tower and is going directly into the coker units. In other refineries, we'll run it through when we run it. In Chalmette, we're not running any right now because we have a turnaround underway on a cap feed hydrate. We're going to initially run that through the crude unit. A final question for me. 2020 CapEx, any rough estimate on a pro form a basis may look like? Paul, I think we are still going through final 2020 budgets. We've not yet gotten approval from the board on anything. So it's a bit premature. But what we would say is longer term based on the 5 refinery system that we have today in the portfolio, we should at times be anywhere circa $550,000,000 of CapEx and probably 2 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. Thank you. The next question comes from Brad Heffern with RBC. Please go ahead. Hey, everyone. Good morning. First of all, I was hoping we could touch on RINs. I wanted to get your thoughts on the quote deal and any thoughts on the trajectory of RINs as sort of the SREs go back into the RINs pool? Consistent with last quarter of my comments, there's no question the President and his 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 the ag 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 if they lose sight of that fact, I think you'll see more actions by the EPA to address it. Okay, thanks. 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 had a much more light crude runs than normal. I think the light crude side you mentioned was potentially due to the Philadelphia Energy Solutions 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 in fact in in Paulsboro as well, ex Duluth 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 order volume crudes that were in the queue 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 a 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 was making high sulfur fuel to a lighter crude. And I do want to make sure everybody realizes that it's kind of back on Paul's question on fuel. That is not a one to 1. 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. Okay, got it. And then just finally, maybe for Eric, the Torrance land sale during the quarter, can you just talk about what that was and potentially what the proceeds from that were? Yes, it's roughly $35,000,000 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 having 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. Okay. Thank you. The next question comes from Neil Mehta with Goldman Sachs. Please go ahead. Good morning, guys, and congrats on the strong cash generation. I guess my first question, it's been a couple of months since Philadelphia has gone down. And I wonder 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 its section. So when you Philadelphia Basin, where you have our 2 refineries, you have the train refinery and where obviously Philadelphia was, you effectively reduced local clean product production by 225,000 barrels a day. It ran 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 are 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 of PADD 1 has improved because it's going to require more inputs from further places away. That makes sense. The follow-up is just can you call out, Eric, sorry if I missed this, what the working capital swing was in the quarter? And just the latest thoughts on the need to issue equity given the cash balances are now north of $500,000,000 I would think the answer is you don't see a need for it, but just want to confirm. Sure. We'll go in reverse order. I think consistent with earlier comments, we are executing on the plan that we laid out based on market conditions that the second half of 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 3rd quarter inventory reductions, which ultimately drove almost $150,000,000 of working capital increase associated with inventories being reduced. So overall working capital was north of $200,000,000 but the vast bulk of that comes down from inventory reductions. Great, guys. The next question comes from Phil Gresh with JPMorgan. Please go ahead. Yes. Hi, good morning. Good morning. My first question is just a follow-up to Paul's question when you're talking about fuel oil versus heavy crude. Tom, I think you mentioned that there would 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 viewing kind of today's heavy dips versus fuel oil dips as kind of that crossover point? And then if fuel oil continues to weaken faster than heavy crude and there's a timing effect there, that would be more of a one for one capture for every incremental dollar of fuel oil weakening, if that makes 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 dips, 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 there's another leg down on high sulfur fuel oil, in fact, that would be exacerbated. My own view though is that what we're likely going to see is the light heavies or sweet sours. And it really is I said sulfur is the enemy for a reason. IMO is not just getting rid of or losing a market for high sulfur fuel oil. 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 crews to those differences 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 to your crude unit, you are going to back out more than 1 barrel of crude of Basra to run 1 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 this is 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. Understood. 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 2, several other refineries have come to market or are proposed to come to market in PADS IV and PADS V 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. Okay. Thank you. The next question comes from Matthew Blair with Tudor, Pickering, Holt. Please go ahead. Hey, good morning, everyone. We seen a recent increase in tanker rates. Could you talk about how that might affect your earnings in the Q4 as well as into 2020? Yes. Obviously, there's been 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 Saudis are to be congratulated for putting their customers, but to keep the market stable and they were successful with that. But they did have an effect on rates and then of course the sanctions exacerbated that. We think that will calm down and it is calming down. We also think if you look at our system, we've got 5 refineries and right now and Torrance and Toledo are effectively pipeline supported refineries. We have a significant amount of domestic crude or 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 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 someone who's running a high percentage of either sweet or sour foreign crude from Europe or Asia. Sounds good. And then Tom, any thoughts on NAFTA 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 length going away anytime soon. There's going to be more likely pressure to run sweet crudes as the medium conversion or simple refiners who are running sour crudes have to take some steps. You have this ongoing tremendous increase in NGLs and the naphtha that are coming, pentanes that are coming with that. Are competing into the petrochemical business. But the bottom line is this naphtha length and I think that's going to continue. And then that gets you into a situation where what do 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 haul that into the gasoline pool. But I think you're going to wind up with a distressed NAFTA market continuing longer. Appreciate the thoughtful response. Thanks. The next question comes from Jason Gabelman with Cowen. Please go ahead. Yes, thanks. It looks like the gasoline market is holding up pretty well here as we head into winter. Front month 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 Q4 or did you kind of get it all this quarter? Thanks. Okay. I'll take the first question. And again, I go back to what is happening with IMO is this shift of 3,500,000 barrels a day of high sulfur fuel oil disappearing as a market. Obviously there'll be some of that that stays because of scrubbers, but an increase in light product demand, light lower sulfur product demand of 2,800,000 barrels a day. I think it's going to go across the spectrum of 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's 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 deconverting gasoline in the back end of a cat cracker to distillate, if you have strong distillate prices, but equilibrate. So we think that in fact there is a benefit across the whole light product system because of what's happening with IMO, if that makes sense. And on the working capital, again, we generated over $200,000,000 from working capital during the Q2, 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 Q4. Working capital now from an AR and AP standpoint is really going 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 materially received during the Q3. Understood. Thanks. The final question today comes from Doug Leggate with Bank of America. Please go ahead. Thanks guys. I appreciate all your detail this morning. I just have 2 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 marginos? It's a good question, Doug. 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 heavy 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. That is a heavy, relatively light in terms of sulfur or sweet crude and the prices have remained stable. In fact, the dips 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 coca, we were actually selling some fuel off 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 it's 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 economic 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. I appreciate that detail. 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 talk 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 would be better back as part of the broader system. I'll leave it there. Thank you. Sure. Look, 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 a 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 valuing us. And so we're certainly not making any news with these comments, but we'll continue to evaluate it. But the MLP has been a net positive for our suite of companies and the strategy it laid out is in front of it. So, nothing is static and we'll continue to evaluate as we go forward. Thanks for taking my questions guys. Good luck. Thanks. This does conclude the question and answer session. I would now like turn the call over to Tom Nimbley for closing remarks. Well, thank you very much for your attendance and your interest today. We look forward to having another call with you at the end of the