Earnings Call: Q2 2019

Aug 1, 2019

Welcome to the PBF Logistics Second 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 question following management's prepared remarks. It is now my pleasure to turn the floor over to Colin Murray of Investor Relations. Please go ahead. Thank you, Brie. Good morning, and welcome to today's PBF Energy earnings call. With me today are Tom Nimbley, our CEO Matt Lucey, our President Eric Young, our CFO Tom O'Connor, our Chief Commercial Officer 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, 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 a $134,000,000 after tax non cash lower of cost or market or LCM adjustment, 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 strong second quarter results reflect solid operation performance from our West Coast, Mid Continent and Gulf Coast refineries and some operational headwinds on the East Coast. Product margins in all regions improved versus the Q1, which boosted our refining margins. We continue to navigate through the narrow light heavy differentials. The ongoing OPEC cuts, sanctions on Venezuela and Spain and the Alberta curtailment limit the supply of economic medium and heavy barrels available on the market. This has put pressure on complex refiners as we are not currently being rewarded for complexity. We have responded by lighting up our slates on the Eastern Gulf Coast. We do believe that our complexity will be rewarded on the backs of the upcoming IMO implementation and Tier 3 gasoline. In regards to IMO, the situation continues to develop as we speak and we expect to see even more activity as we approach the Q4 and January 1, 2020 does put a line in the sand. We believe that IMO will be a significant event for both products and light heavy crude differentials. It is our view that low complexity refiners will need to shift to a lighter and sweeter crude slate in an effort to stop producing high sulfur fuel oil, which will struggle to find a home. This will result in the differential between low sulfur and medium heavy crudes. We believe that in the Atlantic basin alone, we could see a shift in the lightening of crude slates for less complex refiners. We estimate this number to be at least 1,000,000 barrels per day and could potentially be multiples of that number. PBS refineries are ideally situated and have the flexibility and complexity to benefit from this shift. One impact we have seen in the market recently as refiners shifted to running lighter crude, particularly light tight oil crudes is the fact that we are seeing an excess of naphtha, which is struggling to find a home with octane for the gasoline pool being very tight globally. Octane levels will be an area to monitor going forward as the industry shifts to producing even cleaner lower sulfur fuels such as Tier 3 gasoline. As a company, is well positioned to capitalize on this market and all of our assets can produce Tier 3 gasoline. It will be interesting to see how the landscape develops over the next 6 months. Although first half twenty nineteen oil demand has been revised lower from initial forecast, consensus data is still calling for strong oil demand growth in the second half of twenty nineteen. 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 safely in an environmentally responsible manner and reliably, which will lead to profitability in an improving market. 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 2nd quarter income of $0.83 per share. 2nd quarter EBITDA comparable to consensus estimates was approximately $299,000,000 and adjusted EBITDA was approximately $310,000,000 Our second quarter results included $31,000,000 related obligations and at prevailing pricing, we expect full year 2019 RIN expenses in the $125,000,000 to 1 $50,000,000 range. Consolidated CapEx for the quarter was approximately $241,000,000 which includes $237,000,000 for refining and corporate CapEx and $4,000,000 incurred by PBF Logistics. Our first half refining CapEx of approximately $485,000,000 represents roughly 75% of our full year guidance of $625,000,000 to $675,000,000 and importantly includes the completion of all of our major maintenance and turnaround activity for 2019. We ended the quarter with approximately $2,000,000,000 of liquidity with $1,800,000,000 at PBF Energy and $265,000,000 at PBF Logistics, and our net debt to cap was 34%. These figures include the $200,000,000 in proceeds from the drop down of the Torrance Valley Pipeline and a $250,000,000 debt repayment. As we look forward to the back half of the year, we expect to generate significant free cash flow as a result of strong cracks, relatively low CapEx and the normalization of working capital following our first half builds. Finally, 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 throughput of approximately 855,000 barrels per day. With the exception of extended turnaround work at Delaware City, our assets ran well during the quarter and we were able to capitalize on the favorable market conditions, especially in the Mid Con and on the West Coast. On the East Coast, we finished planned work at both Delaware and Paulsboro. The Delaware turnaround on the fluid coker ran approximately 40 days long as we encountered some unplanned work. As a result, coker availability was limited to just 20 days in the Q2. Looking forward, all the work was completed during the quarter and we are expecting to achieve a 4 year run with that unit. As Eric mentioned, 100 percent of our planned major maintenance for 2019 is now complete. Our assets have a clear operational runway for the remainder of the year. We are progressing with our strategic investments in the Chalmette Coker and the Delaware City Hydrogen Plant. Both projects are on schedule and we expect the coker to be in service late in Q4 and the hydrogen plant should be in service during the Q2 of 2020. We continue to work closely with Shell on the acquisition of Martinez. We did receive a second request from the FTC and are working to provide all the requested information to the appropriate parties. Pending regulatory approval, we anticipate the transaction will close by the end of the year. Lastly, the dynamics on the East Coast have shifted with the outage of PES. It is still very early to definitively state what the outcome for the asset might ultimately be, but the near term impacts are that we have seen the market tighten. The PES refinery supplied approximately 250,000 barrels per day of clean products in PADD 1, including about 35,000 barrels a day of premium gasoline. There is a hole to be filled that will likely come from imports off Colonial Pipeline and from Europe, which have been traditional suppliers to the product short East Coast market. With the outage, more barrels are going to have to be attracted to the East Coast and this should provide a transportation based benefit to PBF and other PADD 1 refiners. We remain intently focused on the aspects of our business that we can control. And with our strategic decision to move our maintenance into the first half of twenty nineteen, we believe we have put our system in a beneficial position for the second half of the year. Operator, that's our opening remarks. We're pleased to take questions. We will now open the call to questions. The company requests that all callers limit each turn to one question and one follow-up. And we will go to our first question from Prashant Rao with Citigroup. Please go ahead. Good morning. Thanks for taking the question. I wanted to get to sort of basics here on crude slates and the light heavy availability sorry, the heavy and medium barrel availability or lack availability you talked about, Tom. As you look through the back half of the year, I wanted to get a sense of generally what you expect in terms of cadence of Canadian barrels and then what you're seeing on the market that's waterborne? And then sort of a second part of the question is I noticed in the Gulf you were able to optimize somewhat here getting some more medium barrels I think than our more than our expectations and running less light than I would have expected to. So looks like really good work there on the crude slate. Wanted to get a sense of where those medium barrels are coming from and other sort of tactical opportunities you have, so not necessarily substitute straight for a light barrel in some of these instances? I think we'll piggyback this answer. I'll take the beginning of it. In terms of as we said, I think IMO is going to have denial is not an acceptable opportunity. But the reality is as you're well aware is kind of the conundrum in that there's still a market for heavy fuel oil and that the constraints that have been imposed to tighten up the dips and the incentive to start making changes is going to be pushed back for as long as they think they can continue to have a market for the product that they're producing, I. E. 3.5 percent fuel oil. So we are starting to see some movement, albeit relatively light. We've seen some movement in the clean dirty spread in New York Harbor, movement widened out a couple of dollars a barrel. But we expect as we go further into the Q4 and I think others have been pined on this, as you start to get to where it's going to take 80 to 90 days to really start turning the system over to be ready on January 1, 2020. You're going to start to see first a decrease in heavy fuel oil, 3.5% heavy fuel oil pricing and that will ultimately lead ultimately to a widening probably with a lag effect and I'll ask Tom O'Connor to add to that in a moment on the light HEFFY spreads. As regards specifics, Canada obviously is slowly increasing or decreasing the constraints that they're putting on. We have seen some movement, although frankly, the prices have come in with WTI Brent that Canadian by rail is still not economic or significantly economic more breakeven, but we expect to see that widen out. To your point though, and this is again is a benefit of the system we have. We are a heavy refiner. We are a very complex refiner, but Toledo runs 170,000 barrels a day oil light sweet crude. Over half of our slate in Delaware City has been moved to light sweet crude. You're right, Chalmette, we've moved up on how much light barrels we're moving. Of course, the Mars LLS differential has incented that. And we do have some flexibility to do more. But frankly, we believe that we're on the cusp of seeing that situation turnaround. Tom, you have anything you would add? I think Tom, the only things I would really add, I mean in terms of we did the Q2 probably represents the troughs of crude by rail for us for 2019. So you certainly see some big stance in terms of heavy volumes that we've taken from Canada that was higher in the second quarter than the trough was in the Q1. I think particularly as you look out further and even going back for one second though, we've been in a narrow world for quite some time, right? So at this point, a lot of shifts that have already expected to taking place have already taken place. And now the market is looking forward to the Q3, the Q4 and ultimately into IMO and that's when we're starting to see at that point that they're anticipating crude slate shifts that will ultimately move greater demand offshore for light sweet crude and ultimately pushing some mediums back to the U. S. Okay. Thank you very much for the detailed answer there. I wanted to shift to talking in your opening comments about putting Tier 3 gasoline standards and tightening the octane market. Question I think that we're all trying to get a sense of from operators and yourselves. Where would where is the incremental supply of octane going to come at the market site in the U. S? Is your view that it's some might be imported from Europe or perhaps from Asia? There is a few alky projects coming up in the U. S. Refining system also, which could add to that capacity. But I think you haven't talked about much about Tier 3 gasoline in the last few quarters because it's been sort of on the back burner relative to other issues, but it's coming soon. And so 5 months to go, wondering, so how you see the market shaping up and where how tight could I think and where can we get that incremental source from? Yes, I'd say let me first preface this by I think the industry is by and large ready for Tier 3 gasoline. It's been around since 2017 and the fact is that we've had the ability to make decisions on economic trade offs, capital investment or buying credits. And in that regard, good managed companies will have thought through the fact that there was going to be a paradigm shift on January 1, 2020, when you no longer have the Tier 2 credits to purchase and the game is going to change some. So I think by and large, the industry is in reasonably good shape. There's 2 things here that I would point out. One is the impact of the increased light sweet crude runs and as I said, particularly shale oil. And if you are a light refiner who is now trying or even a medium refiner who is now trying to lighten up the slate and you wind up running shale oil or lights we crude, it's very possible that you wind up with a surplus of naphtha coming out of your distillation units and you can't fit it into your own reforming capacity, the reformers that turn that naphtha into high octane finished gasoline. And I'll point out that one of the first things we did when we bought Chalmette is the joint venture ExxonMobil, PDVSA had shut down a number of units as you might recall because of whatever reasons, we know where they were. But a parcel of those units was a naphtha hydrotreater, a naphtha reformer and a light ends plant. We've started up that block of units, So we actually have taken Chalmette. We would be in a position in Chalmette having not done that project that we would have had a surplus naphtha from our own crude slate indigenous production and that would have been a headwind on capture rate. We've turned that around to where now instead of selling naphtha, we actually produce our own indigenous naphtha and buy naphtha on the marketplace, taking advantage of the economics in that situation and turn it into a higher percentage of finished product gasoline. As to your question on other ways that you can make octane, well, frankly, you can increase reformer severity and make octane. Obviously, I guess it was Valero that just started up the $25,000 a day alkylation unit, that's going to add some octane. There's another player on this, as FOX-ten gets very short, then ethanol can be a player as you bring it into the pool, especially if it's an E15. Our position is, while octane is going to be strong and part of the reason octane is strong in the East Coast right now and on local transitory is PES was a pretty big producer of octane. So we think fundamentally octane is going to be okay. I mean it's going to be strong, but the market will be supplied and again, more an advantage for us because of the complexity of our system. Okay. Thanks very much, Tom. Appreciate the answers guys. I'll turn it over. Our next question will come from Roger Read with Wells Fargo. Please go ahead. Hey, good morning. Good morning. I'd have to say compared to some of the mispronunciations that occur, that's pretty minor there. I was going to say, good morning, Red. How you be? Thanks, Tom. Eric, if we could, back to the cash flow from operations kind of discussion. I mean, I think everybody knew coming in this year with the accelerated CapEx, maintenance, etcetera, tough. But in the back half of the year, we have the hopefully Martinez acquisition coming through against a better operating backdrop. Can you give us maybe a little more granularity on what we should be expecting in terms of any risk on CapEx being higher or lower in the second half and maybe the pace of working capital recovery that you would anticipate? Yes. I think ultimately, let's go kind of in reverse order. We'll start with the working capital side of things. So to date, we've probably had a use of just shy of $300,000,000 of working capital. Now a portion of that is related to inventory, but also a portion of it just relates to a handful of other categories on the balance sheet. We do believe we're going to start to see that swing back the other way. Obviously, we just reported our 2nd quarter numbers. So you see kind of a snapshot of the balance sheet that's included in the tear sheets. Ultimately, we have already started to see a portion of that come back as we sit here through the end of July now. And so from our perspective, and this is similar to what we've seen in prior years where we've been more front end loaded from a CapEx perspective, that ultimately the CapEx relates to downtime associated refining units come back online. So we should really start to see the first part of working capital swing back during the Q3. Then there will be some follow on effects to that, that should be positive towards the back end of the year. That being said, all of this is subject to where hydrocarbon prices are. So if we see a massive spike in hydrocarbon prices, it does blunt some of that working capital coming back. Then with respect to working I'm sorry, with respect to CapEx, we're through 100% of our major maintenance activity. And so the vast bulk of the CapEx left to be spent through the remainder of the year really relates to the completion of the coker project and essentially doing all of the tie ins associated with the hydrogen project at Delaware City. So there's a hodgepodge of other much smaller activities that are going on at each of our 5 refineries. But from our perspective, we're still very confident with that guidance. We know there's a $50,000,000 band included in there. I think as we sit here today, we're probably going to wind up somewhere close to the middle of that band. But I do think we want to give ourselves a little bit of cushion in the event that something unforeseen happens along the way if we by chance decide that it may make sense to spend a little bit of 2020 CapEx to basically pre fund some stuff during 2019. So from the perspective of Martinez at the latter half of the year, I think where we sit here today is we've obviously we did the Torrance Valley pipeline drop. We talked a lot back in June in conjunction with the transaction announcement that we will be accessing the debt markets at the appropriate time. And ultimately, we're going to use our ABL. We were successful in paying down $250,000,000 during the quarter. So we have a zero balance outstanding balance on that particular security. And ultimately, we'll use that to fund the working capital associated with Martinez. We do expect to generate significant free cash flow, partially driven by increased cracks really across the board. And I think we feel like we're in pretty good position here through the end of the year. Okay. And still comfortable not using the equity side to fund the transaction? As we sit here today, unless something changes between now and the time of close, we feel like we've got a broad runway. Clearly, this is all subject to the whims of the market that we really cannot control. But as we sit here today looking at the forward curves, things look reasonable for us to generate the type of cash flow that we think we're capable of producing. Okay, thanks. And then just to go one more step down on the California side, best results we've seen from Torrance since you've owned it. Obviously, the market was in pretty favorable position to start the quarter. I was just wondering, looking at it from the outside, we think it's great. From your perspective, did it operate as well as it should have? Were there things that it could have been better? Just kind of if you were rating it, was it a 6 or 7, 8 or 9 or a 10 on a kind of 1 to 10 scale for the performance in Q2? That's a great question, Roger. It's right to the point. I'd say probably given the circumstances, I'd give them an 8%, give us an 8%, give them an 8%. And what I mean by that is, this is why you buy California refineries to a certain extent is, it's as you well know, the supply chain is very tight because of the islandized nature of the products and there are some times where you go short on production because of problems or plant shutdowns and what you want to do is be in a position that you actually have your equipment run reliably. And they did. So, the Torrance did very well and ran reliably. But they have moved so far, so fast out there since we took the acquisition, made the acquisition. I'm very proud of the organization. But we still have, let's say, 8 to 10 or 7.5 to 10 to go. We are not there yet. That place has more potential. And so we still have work to do there. And I think we'll actually, as we said, we'll prove ourselves out later. We'll benefit from Martinez. But a very good second quarter and a great margin environment, but we're not all the way there yet. Great. Thank you. Our next question will come from Justin Jenkins with Raymond James. Please go ahead. Great. Thanks. Good morning, everyone. I guess I'll start on the macro side from the demand picture you mentioned, Tom, that second half outlook is seemingly better than the first half. Have you noticed any shifts in terms of the market portfolio or kind of the demand environment that you're seeing across the board of your system, whether it's throughout 2Q or even recently here in 3Q? I'd say, obviously, we go back to 1Q and that was a rocky environment because of the gasoline situation, which gave the internal combustion engine was declared dead in arrival during the Q1, we recovered and we predicted that and the markets are efficient and they will continue to be efficient. A little bit of lull in diesel in the Q2 and to a certain extent that was probably impacted, it certainly was impacted to a certain extent by the heavy rains and flooding and a decrease in agricultural usage. We expect to see a reasonably good diesel market, especially as with some additional push from IMO coming as we move along in the second half of the year. And our own view is that IMO even we when we first thought about IMO, we looked at it in terms of, hey, it's going to be a big impact on obviously feedstocks because the ability to clear the barrel if you're a producer of high sulfur fuel oil is going away, unless you can buy it, put it into a coke or you put your crude in the ground in January 1. But we also thought it would be a big boon for just ULSD. It's our view is more of as others have is that what will happen is you can make that compliant fuel by taking gas all away from an FCC if the gas cracks are low and selling the VGO into that pool. And so we think there's going to just basically be an odd between all of the clean products and the gas oils that will play out different knobs that will turn. But by and large, we see the second half. Tom, do you have anything you would add? Yes. Tom, I would add to that. I mean, clearly year on year, we're seeing increases in distillate inventory, but the inventory is still quite comfortable relative to 5 years. And I think adding on at this point is distillate has room and needs to build in front of IMO with the increased demand that will be coming from that side of the barrel in that equation. Perfect. Thanks for that, Suvitvio. I guess the second question is on the operations outlook at Chalmette. Seems like the throughput guidance is a little bit lower sequentially. Is that the kind of shifting of the crude slate that you mentioned or anything to note here terms of 3Q outlook for Chalmette? Yes, there's really 2 things and one you've hit on. I've said this before, when the economics dictate taking a heavy machine and turn it into a light machine or vice versa, you don't get the same capacity. They're not built to just make that switch and run the same. You can't run 200,000 barrels a day of light sweet crude one day and turn it to heavy. The economics have gotten compelling that with the incentives, the differential between LLS and Mars, we should be running all LLS and we are increasing LLS, but and other light crudes. But there's going to be a limit on that and some of that is results in lower throughput as you hit limitations in the tower. The second piece is Eric and Matt have both said that and it is true we've advanced all of our major maintenance efforts, turnaround efforts into the first half. We do have one project that we consciously left open that we're going to execute in Chalmette in September and that we're going to go into a unit called the Caffeine hydrotreater and we're going to put some modifications inside not to get technical, but we don't make enough ULSD in the Chalmette, we make lower valued distillates. This project is going to make some modifications that will allow us to increase the production of ULSD from the plant 5000 to 10000 barrels a day, but that is impacting some the throughput rate in the Q3. Perfect. Thanks, Tom. Our next question will come from Phil Gresh with JPMorgan. Please go ahead. Phil, your line is open. Our next question will come from Neil Mehta with Goldman Sachs. Please go ahead. Good morning, team. I guess the first question is on Western Canada. There's a big range of potential outcomes when we talk to investors about how they see the spread playing out from here. Curious on your guys' views as large consumers of Canadian crude. Good morning, Neil, it's Tom. I mean, certainly as we're looking at the WCS market, it's certainly been a little bit stronger in the first half of the year than our expectations. And the Q3 is still shaping up on the narrow end of the range. Basically, the curtailments had success in many lights in terms of narrowing differentials that hasn't had as much success in terms of absolute decreasing inventories. But I would say that looking out, mentioned on an earlier question that if the Q mentioned on an earlier question that if the Q1 represented, I think the trough of our crude by rail business or that what we're taking. And then in the second quarter, it ticked back up. I think in the Q3 at this point, we are looking to optimize that position and move off the base lower from where we were today. I think longer term, I do think IMO does start to factor into play. But we do have we have and like we will have strong PADD II margins for the considerable for the least of the near future. So that should I think, and then longer term see those moving back out. Okay. That's helpful. The second is just from a reliability standpoint, there have been some headlines around the Toledo, Ohio refinery and some operational issues earlier this week. Anything you can comment there in terms of that asset or any of the issues there baked into your Q3 guidance? Hey, this is Matt. First off, there was an incident that there was no impact to community. None of our employees or contractors were injured. But the net result for our investors is there's no change to our throughput guidance for the quarter and we don't see it as a material event. Okay, great. Thanks guys. Our next question will come from Paul Cheng with Howard Weil. Please go ahead. Hey guys, good morning. Welcome back, Tom. Thank you. Tom, I have to apologize. I joined the call a bit late, so you may have already addressed it. Question on the I think you talked a little bit on the IMO compliance field. From PBS standpoint, what is your intention to do? Are you going to bring primarily the VGO into the VLSFO or that you're trying to use directly from the high sulfur fuel oil? And also, what is your ability to take high sulfur fuel oil as a feed into your coke test? Great question. We spent about an hour and a half yesterday and we've been working as to some this is on the latter part of your question. We have significant ability to buy high sulfur fuel oil if it's obviously at an economic price and bring it into actually all of our coking refineries have the capability of doing that. Now, some of them can only do it through the crude tower. So you would bring in some type of a cut. You wouldn't buy 3.5%, but if you try to buy a cut resid that's got some livestock in it and because of that you bring it in through the crude tower and then basically the resid would go to the coker from the crude tower. And one of our refineries, we think we can get it directly to the coker. But it is a significant volume that we can buy and that's some of the flexibility that we've been pushing. One of the reasons we bought the logistics asset that we bought in the East Coast, which is next to Paulsboro and sits between Paulsboro and Delaware City is to augment that flexibility to move high sulfur fuel all around. In fact, we used that during the recent Delaware City coker turnaround. On the first part of your question, I mean we ultimately see when the system equilibrates and the light heavy spreads widen out to reflect the fact that there is no market by sulfur fuel oil that will be buying crude, light heavy crude and we'll just make our gas hauls or the compliant fuel on the back end of that. But as I said, maybe you weren't on the call, originally we thought a big piece of this was going to be supplied by 15 parts per 1,000,000 USD. We believe and others believe and we can see it that it's all going to be an increase in light product demand of maybe 2,500,000 barrels a day. But if gasoline gets sloppy, you just take gas all out of the FCCs and then move it and sell it as a 0.5 fuel. I'll point out again, I've mentioned it before, the California system is ideally suited for this because of the fact that you have to make carb gasoline and carb diesel. The point I would make is the Torrance refinery with its complexity, Torrance refinery has a $100,000 a day high pressure piece of equipment that sits in front of the cat cracker that reduces the sulfur in the feed to the FCC in torrents to below 0.1 sulfur. So you could literally blend higher fuel into that material to sell it as 0.5 material. And if the economics are there to do something like that, you'll shut the valve or at least decrease the valve for the cat cracker, make more fuel and then the markets will equilibrate. So what I'm saying is I think there's going to be a number of knobs that turn and we'll be supplying the fuel in different ways. Tom, Can you quantify how much is the we said you can buy into your system? I asked the question yesterday and it's certainly probably north of 50,000 barrels a day. And just curious that, I mean, when I'm sure that you'll be aware that some of your competitors, particularly Exxon and Shell have patent out there in terms of how to brand into the IMO compliance. How challenging that when your lawyer review that thing, the industry may have some difficulty to avoid those patents in order to get the compliance view? Or that your lawyer basically saying that that's not an issue, that there's a plenty of We haven't actually seen the information to we know that VPs doing certain things, Total is doing certain things and of course Exxon is certain things. At this point, we have no reason to believe that we're going to be constrained by that, but we have not seen the details of the formulations that they are proposing. Okay. All right. Thank you. All right. Hang on Paul. I would add, the way our system is designed at this point as it relates to IMO fuels, we are not setting ourselves up to be a dramatic wholesaler selling end users directly. We will be selling components to the market and selling that and that. So those issues will be on somebody else. I see. So you're actually not going to sell the finished product, the VLSS, old? That's correct. We may have it from time to time, but we don't have a big business model to be competing with the global bunker players. And is that market liquid enough for you to just be a major wholesaler of components? Yes. Yes. Okay. All right. Thank you. Our next question will come from Matthew Blair with Tudor, Pickering and Holt. I'm not sure if you've already covered this, but could you provide your WCS crude by rail volumes to the East Coast in Q2 and any sort of outlook for Q3? Yes. It's Tom. In the Q2, we did 75,000 barrels a day. And in the Q3, I would anticipate that number moving down into the 55,000 to 60,000 barrel a day range. Thank you. And then, I was hoping you could provide a little bit of commentary on the West Coast product market. We're seeing PADD 5 gasoline, diesel and jet inventories all at new 5 year highs. It looks like gasoline to start off the quarter a little soft. Could you just talk about the dynamics you're seeing on the West Coast? Are you seeing more imports come in? Is this just a result of refineries running harder coming off of Q1 and I guess a little bit of Q2 turnarounds? Any commentary there? Yes, I think it's a movie we have seen before in California. Obviously, during parts of the early part of the second quarter, end of the first quarter, there was a significant number of planned and unplanned downtimes. In PADD V in California, the margins of course responded and that's why one of the reasons we had a good financial such a good financial quarter in Tarrant. But while the supply chain takes a lot longer to rebalance in California because of car Bob and etcetera, it does rebalance. And so the Yamadera shift started showing up and it over corrected. And it took it's only now from the folks out in the West Coast telling me that as you look out the windows from the offices that you start to see the ships leaving the various ports, particularly part of Los Angeles. So the imports had a surge in imports to try to capture that arb arb was the primary reason that the market moved down. It's recovered. It actually got down with couple of dollars a barrel lower than it is right now and it's starting to recover. So we think we're going to California will be fine going forward. We've seen high octane components, which were destined for the West Coast are now being deviated into other markets, I. E. New York Harbor, where you have a higher, TBOB, RBOB spread. Sounds good. Thanks. Our next question will come from Patrick Flam with Simmons Energy. Please go ahead. Hey, guys. Thanks for taking my question. I wanted to ask if you could give us an update on your latest thoughts around the political issues in Michigan and the talk about the closure of Line 5 that's been thrown down? I know you guys are kind of close to the issue there. We are. We're monitoring it. We're working it. Look, I think it's political suicide for certain politicians in the state of Michigan. You have a tremendous amount of propane to heat homes that come through that pipe. There is nothing unsafe or environmentally irresponsible with the pipe. And obviously, it serves a lot of refineries. Toledo would be impacted. Our runs would go down and as a result, not too indifferent from the rest of the market. Your gasoline production and your jet fuel production, all your clean products production would decline precipitously and it would be a major event for the people of Michigan and would end up paying significantly more for products. I do think there would immediately be a response from the federal government. And quite frankly, I think it would be a major boost to President Trump's campaign effort in 2020 in the upper Midwest. So it's something that the politicians are playing with. We're clearly monitoring it. But at the end of the day, my guess is either the Michigan politicians will not commit Harry Carey or if they do, I would expect the White House and the Trump administration to step in. Okay, great. That's very helpful. My second question is basically, as Permian production continues to ramp up, we're seeing an increased prevalence of light barrels entering the market, especially around this new lighter grade of WTL. Do you guys have any capacity to run that and also just capacity to run lighter crudes in general across the system? We can obviously run lighter crudes, but the lighter that they get, the more difficult it is to process. So running WTI or a Brent or Brent base crude, not Brent itself, although we actually ran a little bit of Brent this month, is easier a West African suite is easier than running these Permian crudes, these very light crudes, these condensate crudes for us. So we can run them, but again, there's no free lunch in this business. If your unit is designed to run a certain ratio of crudes, a range of gravities between X and Y, if you deviate from that, you're probably going to have to cut back your throughput. I would also add, I think, West Texas lighter, extra lighter WTL, we're sitting there at that point. That's more of a Western PADD III phenom. By the time product gets to us, we're looking more at a generic hell barrel as opposed to a neat Permian just due to basically Jones Act restrictions. And our last question will come from Jason Gabelman with Cowen. Please go ahead. Yes. Hey, thanks for taking my question. I know you mentioned the ability to run high sulfur fuel oil directly through your system. And I'm wondering, do you guys here risk that transmission mechanism from high sulfur fuel oil translating to the discounts and heavy crude prices could be broken or kind of not fully translate the way that you would normally expect it to? So, I think the thing we think might happen is initially there'll be a lag because what happens is January 1, 2020, there is no market into the industrial bunker fuel market for high sulfur resist. So that's Thelma and Louise driving over the cliff. They got to have a plan. Right now that plan is probably going to be if you're going to power and compete against coal or you try to get a refiner who has the capability to buy this material and can bring it into their refinery. The reason I say there's going to there could be a lag is the the situation that exists with cut constraining heavy crudes and medium crudes and being withheld from Canada and sanctions on Iran and Venezuela, it actually works to that benefit right now because they're getting increased prices on some of the other crudes. So there's probably going to be a lag. In the long term, there's not going to be in my mind anything that really disconnects that formula. Tommy, do you want to add something? Yes. I mean, I think to just sort of expand just to slice a little bit to that answer is that the product markets from our view are definitely way ahead of the crude market as it relates to IMO, right? I mean, we've seen the development of this new 0.5 market, high sulfur fuel oil from a crack perspective, which is trading very, very steep backwardation. And then you have things like light crude, which are basically trading flat on a differential to where the current spot markets are. So basically what I'm trying to say is that the crude markets are definitely very much torn between the the narrow light heavy environment that we are in today and are definitely undervaluing the crude slate changes that are pending on the horizon as we basically go into an IMO world. So as it stands today, yes, high sulfur fuel is definitely cheaper at some point in the Q4 or in CAL 2020 than high sulfur crude. So the industry would be wanting to get into buying that at the potentially the expense of running crude at this point. I mean, if high sulfur fuel is going to remain very, very discounted, you are going to ultimately you're going to derate refineries and you're going to be running less because you're going to be keeping your coker full with somebody else's material as opposed to somebody's crude. Thanks. And I appreciate those comments. If I could just ask a follow-up on another comment that you made earlier just about the fact that it sounds like there's a lot of gasoline supply out there was supplying the West Coast earlier in 2Q, now backfilling on the East Coast. What do you think is driving the higher amount of global supply of gasoline that's out there and do you see that persisting through the rest of the year? Thanks. Actually, I think Tom was referring to the fact that the ARBOB, PEBOB spread in New York Harbor as Okane has tightened has given incentive to redirect some cargoes that were still headed towards the West Coast when the West Coast price were coming down to come back to the East Coast. Obviously, worldwide gasoline balances, they are not bad or the U. S. Balances certainly are not bad. And as we look at it, gasoline will come under a little bit of pressure as it does seasonally when you get the RVP change and some of the butanes go back into gasoline. But I think gasoline is going to get some support as is every light product from IMO as it comes in. Yes. I mean, we're not seeing any material weakness in gasoline anywhere right now. I mean, we've got runs across the U. S. Have not challenged any sort of historic numbers as we've been looking at throughout the summer. At this point, maybe we have a chance for runs to increase into the latter part of August, gasoline market looks decent to us. Thanks a lot. And there are no further questions at this time. So I'll turn it back to Tom Nimbley for closing remarks. Well, thank you very much everyone for joining us today and we look forward to talking to you again and hopefully with very good results at the next call.