PBF Energy Inc
NYSE:PBF
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PBF Energy Inc
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Welcome to the PBF Logistics Second Quarter 2019 Earnings Conference Call and Webcast. [Operator Instructions]. It is now my pleasure to turn the floor to Colin Murray of Investor Relations. Please go ahead.
Thank you, Bree. Good morning, and welcome to today's PBF Energy earnings call. With me today are Tom Nimbley, our CEO; Matt Lucey, our President; Erik 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 described in our filings with the SEC.
Consistent with our prior quarters, we will discuss our results excluding a $134 million after-tax noncash 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 operational 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 first quarter, which boosted our refining margins. We continue to navigate through the narrow light heavy differentials, the ongoing OPEC cuts, sanctions on Venezuela and Iran and the Alberta curtailment limiting supply of economic medium and heavy barrels available on the market. This has put pressure on complex refineries as we are not currently being rewarded for complexity. We have responded by lightening up our slates on the East and 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 fourth quarter, 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 an expansion 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 million barrels per day and could potentially be multiples of that number. PBF's 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 refineries 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, PBF 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 2019 oil demand has been revised lower from initial forecast, consensus data is still calling for strong oil demand growth in the second half of 2019. I've 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 will manner and reliably, which will lead to profitability and improving market.
Now I'll turn the call over to Erik to go over our financial results for the quarter.
Thank you, Tom. Today, PBF reported an adjusted second quarter income of $0.83 per share. Second quarter EBITDA comparable to consensus estimates was approximately $299 million and adjusted EBITDA was approximately $310 million. Our second quarter results included $31 million of RIN-related obligations, and at prevailing pricing, we expect full year 2019 RIN expenses in the $125 million to $150 million range.
Consolidated CapEx for the quarter was approximately $241 million, which includes $237 million for refining and corporate CapEx and $4 million incurred by PBF Logistics. Our first half refining CapEx of approximately $485 million represents roughly 75% of our full year guidance of $625 million to $675 million and, importantly, includes the completion of all of our major maintenance and turnaround activity for 2019.
We ended the quarter with approximately $2 billion of liquidity, with $1.8 billion at PBF Energy and $265 million at PBF Logistics. And our net debt-to-cap was 34%. These figures include the $200 million in proceeds from the drop-down of the Torrance Valley pipeline and a $250 million 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, 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 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 second quarter. Looking forward, all the work was completed during the quarter, and we are expecting to achieve a 4-year run with that unit. As Erik mentioned, 100% of our planned major maintenance for 2019 is now complete.
Our assets have a clear operational run rate 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 to coker to be in service late in the fourth quarter, and the hydrogen plant should be in service during the second quarter 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 of 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 base 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 2019, 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.
[Operator Instructions]. And we will go to our first question from Prashant Rao with Citigroup.
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 of availability that you talked about, Tom. As you look to the back half of the year, I wanted to get a sense of generally what you expect in terms of the cadence of Canadian barrels and then what you're seeing on the market for waterborne.
And then sort of the second part of the question is I noticed, in the Gulf, you were able to optimize somewhat. You're getting some more medium barrels, I think, than our -- more than our expectations and running less light than I would've expected you to. So it looks like really good work there on the crude slate. Wanted to get a sense of where those medium barrels are coming from. And are there sort of tactical opportunities you have to not necessarily substitute sweet for light barrels 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 happen. Denial is not an acceptable opportunity. But the reality is -- as you're well aware is, it's kind of a conundrum in that there's still a market for heavy fuel oil, and the constraints that have been imposed that tightened up the diffs and the incentive to start making changes is going to be pushed back as -- for as long as they think they can continue to have a market for the product that they're producing, i.e., 3.5% fuel oil.
So we are starting to see some movement, albeit relatively light. We see some movement in the clean-dirty spread in New York harbor, movement riding at a couple of dollars a barrel. But we expect, as we go further into the fourth quarter, and I think others have opined on this, as you start to get to where it's going to take 80 to 90 days to really start turning a 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/heavy spreads.
As regards to 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, again, is a benefit of the system we have. We are a heavy refiner -- we are a very complex refiner. Toledo runs 170,000 barrels a day of 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 turn around. Tom, do you have anything you would add?
I think it sounds that -- the only thing I would really add, I mean, in terms of we did -- the second quarter probably represents the trough crude by rail for us for 2019. So you certainly see some expanse in terms of heavy volumes that we've taken from Canada that was higher -- excuse me, higher in the second quarter than the trough was in the first quarter.
I think particularly, as you look out further -- and even going back for one second, 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 take in place have already taken place. And now the market is looking forward to third quarter, the fourth quarter and ultimately, to IMO, and that's when we're starting to see, at that point, that the anticipated crude shift -- crude slate shifts that will ultimately move greater demand offshore for light sweet crude and ultimately push some mediums back to the U.S.
Okay. Thank you very much for the detailed answer there. I wanted to shift to -- you talked in your comments about kind of Tier 3 gasoline standards and tightening the octane market. A question, I think, that we're all trying to get a sense of from operators like yourselves, where would -- where is the incremental supply of octane going to come from if the market's tight in the U.S.? Is it your view that some might be imported from Europe or perhaps from Asia?
There's a few LP projects coming up in the U.S. refining system also, which could add to the octane capacity. But I think you haven't talked about -- much about Tier 3 gasoline 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 sort of how you see the market shaping up. And where -- how tight could octane get? And where can you 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 two 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 light sweet 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 what 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 that, that we actually produce our own indigenous naphtha and buying 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 a 25,000 barrels a day Appalachian unit. That's going to add some octane. There's another player on this. As octane 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 stronger in the East Coast right now and a lot of those is 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, it's more advantage for us because of the complexity of our system.
Our next question will come from Roger Read with Wells Fargo.
Erik, 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, et cetera, 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 risks 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 probably had a use of just shy of $300 million 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 second quarter numbers so you see kind of a snapshot of the balance sheet that's included in the tearsheets.
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. Ultimately, the CapEx relates to downtime associated with the refineries. We're building intermediates. We're storing those intermediates and then, ultimately, running them off kind of as the refining units come back online.
So we should really start to see the first part of working capital swing back during the third quarter. 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 million 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 prefund some stuff during 2019.
So from the perspective of Martinez, at the latter half of the year, I think where we sit today, 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 million during the quarter, so we have a 0 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 thought we've got a pretty good 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. 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 could have been better? Just kind of if you were rating it, was it a 6, a 7, an 8, a 9 or a 10 on a kind of 1 to 10 scale for the performance in Q2?
That's a great question, Roger, right to the point. I'd say probably, given the circumstances, I'll 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. It's -- as you well know, the supply chain is very tight because of the island-ized 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.
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, well, as we've said, we'll prove ourselves out later. We'll benefit with Martinez. But a very good second quarter in a great margin environment, but we're not all the way there yet.
Our next question will come from Justin Jenkins with Raymond James.
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, again, the internal combustion engine was declared dead on arrival during the first quarter. 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 second quarter, and to a certain extent, that was probably impacted -- it certainly was impacted, to a certain extent, by the heavy rains and flooding and 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, A, it's going to be a big impact on obviously feedstocks because the ability to create a barrel if you're a producer of high-sulfur fuel oil is going away unless you can buy -- put it into a coker or you put your crude in the ground on January 1. But we also thought it would be a big boom for just ULSD. It's -- our view has morphed, as others have. Is that -- what will happen is you make that compliance fuel by taking gas all the way 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 a knob -- 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 a constructive demand market. 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 it 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. I guess the second question is on the operations outlook at Chalmette. It 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 in terms of 3Q outlook for Chalmette?
Yes. There's really two 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 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 a lower throughput as you hit limitations in the tower.
The second piece is Erik 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 cat feed hydrotreater, and we're going to put some modifications inside, not to get technical. But we don't make enough ULSD in Chalmette, and we make lower-value distillates. This project is going to make some modifications that allow us to increase the production of ULSD from the planned 5,000 to 10,000 barrels a day. But that is impacting some the throughput rate in the third quarter.
Our next question will come from Neil Mehta with Goldman Sachs.
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.
Neil, it's Tom. I mean, certainly, as we're looking at the WCS market, it's certainly a little bit stronger in the first half of the year than our expectations, and the third quarter is still shaping up on the narrow end of the range. Basically, the curtailments had success in many ways in terms of narrowing differentials but hasn't had as much success in terms of absolute decrease in inventories.
But I would say that looking out, particularly in the near term, is that I do think if -- as mentioned on an earlier question, that if the first quarter represented, I think, the trough of our crude by rail business for -- what we're taking and then in the second quarter, it ticked back up, I think in the third quarter, 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 likely we'll have strong path to margins for the considerable -- for at least the near future, so that should certainly add some support to Canadian differentials, whether it's on the lights or whether it's on the heavies, in the short to medium term and then, longer term, see those moving back up.
Okay. That's helpful. And the second is just from a reliability standpoint. There have been some headlines around the Toledo, Ohio refinery, some operational issues earlier this week. Anything you can comment there in terms of that asset? And are any of the issues there baked into your Q3 guidance?
This is Matt. First off, there was an incident. There was no impact to the 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.
Our next question will come from Paul Cheng with Howard Weil.
Tom, I have to apologize. I joined the call a bit late, so you may have already addressed it. A question on the -- and I think you talked a little bit on the IMO-compliant fuel. From PBF's standpoint, what is your intention to do? Are you going to blend primarily the VGO into the VLSFO or that you're trying to use directly from the high-sulfur fuel? And also, what is your ability to take high-sulfur fuel oil as a feed into your cokers?
Great question. We spent about 1.5 hours yesterday and we've been working -- some of 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 a type of cut. You wouldn't buy 3.5%. But if you try to buy a cut resid that's got some light stuck in it and because it -- you bring it in through the crude tower and then basically the resid would go to the coker from the crude tower. In one of our refineries, we think we can get it directly to the coker.
But it is a significant buy-in that we can buy and add 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 oil 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 for high-sulfur fuel oil, that we'll be buying crude -- light/heavy crude, and we'll just make our gas oils or the compliant fuel on the back end of that. But as I said, maybe you weren't on the call, originally, we also -- a big piece of this was going to be supplied by 15 parts per million ULSD. We believe and others believe, and we can see it, that there's all going to be an increase in light product demand of maybe 2.5 million barrels a day. But if gasoline gets sloppy, you're just going to take gas oil 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 car gasoline and car diesel. The point I would make is the Torrance refinery with its complexity. Torrance refinery has a 100,000 barrel 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 Torrance 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, go 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.
Can you quantify how much is the resid 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 holding in terms of how to blend into the IMO compliance. How challenging that when a lawyer reviews that thing, the industry may have some difficulty to avoid those patents in order to get the compliant fuel or that your lawyer basically is saying that, that's not an issue that there's a patent of...
We haven't actually seen the information to -- we know that BP is doing certain things, Total is doing certain things. And of course, Exxon is doing 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 have proposed. Hang on, Paul. Tom's...
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 to end users directly. We will be selling components to the market and selling in that. So those issues will be on somebody else.
Oh, I see. So you are actually not going to sell the finished product, the VLSFO to...
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.
Our next question will come from Matthew Blair with Tudor, Pickering, 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 second quarter, we did 75,000 barrels a day. And in the third quarter, I would anticipate that number moving down and -- to the 55,000 to 60,000 barrel a day range.
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 five year highs. It looks like gasoline has started 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 -- the movement we've seen before in California, obviously, there are in part -- in the early part of the second quarter and in the first quarter, there was a significant number of planned and unplanned downtimes. In PADD 5, in California, the margins have, of course, responded, and that's why -- one of the reasons we had good -- such a good financial quarter in Torrance. But while the supply chain takes a lot longer to rebalance in California because of CARBOB, et cetera, it does rebalance, and so the motor ships started showing up.
And it overcorrected, 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 port of Los Angeles. So the imports had -- a surge in imports to try to capture that arb was the primary reason that the market moved down. It's recovered -- it actually got down with a 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 finished -- I mean we've seen high-octane components which were destined for the West Coast that are now being deviated into other markets via New York harbor, where you have a higher PBOB/RBOB spread.
Our next question will come from Patrick Flam with Simmons Energy.
I wanted to ask if you could give us an update on your latest thoughts around the political issues in Michigan and talk about the closure of Line 5 that's been turned 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's nothing unsafe or environmentally irresponsible with the pipe, and obviously, it serves a lot of refineries.
Toledo would be impacted. We -- our runs would go down 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 hara-kiri 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 do they get, the more difficult it is to process. So running WTI or running a Brent or a Brent-based crude not Brent itself, although we actually ran a little bit of Brent this month, is easier -- a West African sweet 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's 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 the West Texas light or extra light or WTL, resid-ing there at that point, that's more of a western PADD 3 scene. By the time product gets to us, we're looking more at a generic sell 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.
I know you mentioned the ability to run high-sulfur fuel directly through your system. And I'm wondering, do you guys see a risk that transmission mechanism from high-sulfur fuel oil translating to the discounts in heavy crude prices could be broken or kind of not fully translate the way that you would normally expect it to?
Yes. 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 -- international market -- fuel market for high-sulfur resids. So that spell man will be driving over the cliff. They got to have a plan. Right now, that plan is probably going to be going out and competing 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 this -- that there could be a lag is simply because the various non-free market thought for this are continuing to try to take advantage of the situation that exists with constraining heavy crudes and medium crudes and being withheld from Canada and sanctions on Iran and Venezuela. It actually works to their 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. Tom, you want to add something?
Yes. I mean, I think to just sort of expand just a slight 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 at very, very steep backwardation. And then you have things like light crude, which is basically trading flat on a differential to where the current spot markets are.
So basically, what I'm trying to say is that crude markets are definitely -- are very much torn between the light narrow heavy -- the narrow light/heavy environment that we are in today and are definitely undervalued in 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 fourth quarter or in Cal 20 than high-sulfur crude. So the industry would be wanting to get into buying that heavy, potentially at the expense of running crude at this point. I mean if high-sulfur fuels can 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.
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 that 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?
Actually, I think Tom was referring to the fact that there'd be RBOB/PBOB spread in New York harbor as octane is tightened, has given incentive to redirection cargoes that were still headed towards the West Coast when the West Coast cracks were coming down to come back to the East Coast. Obviously, worldwide gasoline balances, they're 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 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'll have a chance for runs to increase into the latter part of August, but gasoline market looks decent to us.
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.
This does conclude today's program. Thank you for your participation. You may now disconnect.