PBF Energy Inc (PBF) 2018 Q3 法說會逐字稿

Good day, everyone, and welcome to the PBF Energy Third Quarter 2018 Earnings Conference Call and Webcast. (Operator Instructions) Please note this call is being recorded. It's now my pleasure to turn the floor over to Colin Murray of Investor Relations. Sir, you may begin.

Thank you, Keith. Good morning, and welcome to today's call. With me today are Tom Nimbley, our CEO; Matt Lucey, our President; Erik Young, our CFO; and several other members of our management team. A copy of today's earnings release, including supplemental information and guidance 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 quarterly results, excluding a noncash lower-of-cost-or-market, or LCM, after-tax gain of approximately $40.3 million. As noted in our press release, we will also 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 Matt Lucey.

Thanks, Colin. Good morning, everyone, and thank you for joining our call today. For the third quarter, we reported adjusted EBITDA of approximately $331 million. As a system, our refineries ran well during the quarter. From operations perspective, we had relatively open runway for the quarter with only turnaround work occurring late in the quarter at Paulsboro and very low unplanned downtime throughout the system. Total throughput for a refining system during the quarter was just under 890,000 barrels per day, which is in line with our guidance. Benchmark crack spreads with the exception of the West Coast remained relatively flat versus the second quarter and continue to reflect strong demand. West Coast cracks were somewhat seasonally weak, driven by gasoline margins and high utilization was coupled with increased imports in the region. Importantly, cracks in the West Coast did improve over the course of the quarter.

Going through each of the assets and staying on the West Coast, Torrance continues to perform well, reliability was good, operating expenses were up this quarter as a result of particularly high natural gas cost on the West Coast. Normalizing for the natural gas prices, our refinery operating expenses average approximately $6.75 per barrel for the quarter. While Chalmette ran well, it remains a work in progress to realize its full potential. We are in the midst of a plant-wide optimization effort, which will result in increased profitability. The reformer and light-ends plants that we commissioned last year are running well, and we are in the process of restarting the idled coker. We expect this project to cost $110 million and the unit-- it should be in service by this time next year.

Importantly, this coker project will be completed in less than 1/3 the time and less than 1/2 the cost of building a new unit. In Toledo, our refinery ran well and was able to benefit from wider inland crude oil differentials and strong product cracks. As we enter the fourth quarter, we are seeing very favorable differentials for Canadian Syncrude. Takeaway capacity continues to be an issue for a variety of grades and Toledo certainly is well positioned to benefit from the wider Syncrude WTI spread. Similar to Toledo, the East Coast ran well and was able to benefit from expanding crude oil differentials. East Coast EBITDA, excluding special items was $110 million. In line with guidance expressed in our last earnings call, we were able to rail in approximately 70,000 barrels per day of Canadian heavy crude at very attractive discounts, and these discounts are persisting into the fourth quarter. These discounts partially offset some tightness for heavy waterborne crude differentials.

Our high complexity assets on the East Coast continue to show their advantage as we had benefited and expect to continue to benefit from wide crude differentials in certain markets. For the remainder of the year, system availability should be high. Torrance, Chalmette and Toledo do not have any planned maintenance and the remainder of our turnaround activity will be focused on the East Coast in the fall. Paulsboro has completed work on its coker and smaller crude unit. Del City has minor turnaround work scheduled for its reformer and aromatics units set for late November.

With that, I'll turn the call over to Erik.

Thank you, Matt. For the third quarter, PBF reported income from operations of approximately $232.4 million and adjusted fully converted net income of $135.7 million or $1.13 per share on a fully exchanged, fully diluted basis. Special items, excluded from operating income include the LCM amount mentioned previously, a $43.8 million gain related to the sale of land in Torrance and a $44.6 million expense related to the early retirement of railcars. Our adjusted EBITDA comparable to consensus estimates was approximately $331 million. For the quarter, G&A expenses were $69.9 million, depreciation and amortization expense was $93.3 million and interest expense was approximately $42.3 million.

PBF's effective tax rate for the quarter was approximately 25.5%, which was impacted by state tax rates. For modeling purposes, please continue to use an effective tax rate of 27%. Our RIN expense for the third quarter totaled $34 million. At the current rate, we can see full year RIN expenses in the $150 million to $175 million range as compared to our 2017 expense of approximately $300 million. Consolidated CapEx for the quarter, excluding acquisitions was approximately $103 million, which includes $82 million for refining and corporate CapEx and $21 million incurred by PBF Logistics.

During the quarter, we generated approximately $412 million of cash, including $267 million from operations. This resulted in quarter ending liquidity of more than $2.2 billion and in excess of $1 billion of cash. Importantly, our consolidated net debt-to-capitalization was 24%. Lastly, we are pleased to announce that our Board has approved a quarterly dividend of $0.30 per share. Also of note today, PBF Logistics announced its 16th consecutive quarterly distribution increase and provided additional details on its growth plans.

I encourage you to listen to their earnings call later this morning. Now, I'll turn the call over to Tom.

Thank you, Erik, and good morning, everyone. Our positive third quarter results demonstrate the benefit of having a geographically diverse multi-asset refining system. We continue to invest in our assets and improve their reliability and flexibility. We plan to continue to put our refineries in positions to benefit from the tailwinds that we see driving the refining sector and PBF.

The forward-looking market looks favorable. Globally overall market fundamentals are strong with global demand continuing to support product markets. Distillate inventories remain low with growing demand. Recently, this has been coupled with rising gasoline inventories. This is an area to watch going forward and could cause a softening in crack spreads if products are going into tanks rather than being consumed by the market.

With respect to crude oil markets, as Matt mentioned, a widen light heavy -- widening light heavy differentials should help drive strong refining results for complex refiners. As always, we seek opportunities in any market to source the most advantaged barrels for our system, and we've seen many differentials move favorably in the domestic market. WCS and Bakken Takeaway capacity constraints should continue to support wider differentials, and these differentials have knock-on effects, which should benefit our entire system.

Looking ahead, we believe our high complexity refining system is well prepared for the upcoming marine diesel fuel standard shift with IMO 2020. As we have said in the past, PBF has more coking capacity on a percentage of throughput than all, but one other independent refiner. In the past month, we've seen a bit of turmoil in the refinery -- refining equities as a result of posturing about the -- around the implementation of the impending standards. Following their meetings last week, the IMO affirmed both the time line for implementation of the new standards and the carriage band on high-sulfur fuel oil. Despite recent speculation surrounding IMO 2020, out-year differentials for both high-sulfur feedstocks and high-value distillates remain robust and relatively unchanged. Our strategy in this environment as always is to put our assets into position to succeed by running them well and in a safe, reliable and environmentally responsible manner. By executing this very disciplined strategy, our assets will be profitable and our employees and shareholders will benefit.

Operator, we've completed our opening remarks, and we will be pleased to take any questions.

(Operator Instructions) Our first question comes from Roger Read with Wells Fargo.

Just to jump in here. I guess, 2 things really stand out. Crude differentials, and if you could kind of give us an idea what the railcar cancellation was given that crude did the same favorable and you would want more rather than less railcars, maybe the thought behind that, What the real impacts of WCS differentials should be going forward. I think Syncrude is pretty easy to understand from our point of view. And then the other thing to hit on if we could, gasoline inventories and gasoline cracks, because while I agree with you on IMO was certainly a headwind for the equities here, I think fundamentally gasoline has people a little unsettled, if you could kind of give us some thoughts on that?

Yes, well, I'll take a couple of those and pass on to Erik on -- the story on rail situation. But the differentials from both WCS, Syncrude and frankly, Canadian sweets have all moved out to be very beneficial. Much of that is driven -- has been exacerbated in this quarter because of the significant amount of downtime that is occurring and still occurring in PADD 2 , but predominantly

(technical difficulty)

had a contagion spread into Syncrude. Obviously, Toledo...

Tom, excuse me. Real quick there. I don't know if it would have happened to everybody else, but you went totally blank there for about the first part of your answer.

Okay. Well, let me repeat it for everybody then. When we look at the differentials, particularly, the North American differentials coming out of Canada and Bakken -- and can you hear me now, Roger?

Yes, absolutely.

Right. They obviously were massive tailwind for us. They were exacerbated -- those spreads were exacerbated by high level of turnaround activity in PADD 2 in the quarter, which is continuing, and they will likely narrow in some, but they are underpinned by the lack of takeaway capacity coming out of Canada and that is not just WCS, it is now spread because of some shipping and sourcing of crudes to Syncrude. So we expect that we did benefit. We had a very good quarter in Toledo. We were able to capture all of that because we ran well. We expect that to be the case going forward, perhaps not at the differentials we see now when BP Whiting comes back up and turn around at the -- either mid or end of the month. But they will stay wide, and we expect to be able to benefit from them. And frankly, we're seeing those advantages in Delaware in a big way, and Erik will talk about the rationale behind the railcars. But we are running, as Matt says, we ran notionally 70,000 barrels a day of heavy Canadian crude in Delaware. That is a big advantage for our East Coast system. We expect that to be the case for the next several quarters even at the levels that we have now because of the lag in pricing and then we'll see what happens going forward. But until the takeaway capacity is really built out, we expect to be able to rail in crude into the East Coast and be in the money for probably the next several years. And let me take the gasoline, distillate. We too -- as I mentioned, looking at the gasoline inventories, there was, of course, concern. I'm not as quite as concerned I was 3 weeks ago, and that's simply because the markets are starting to move. The RV is closed completely from Europe, the RV is closed in the Gulf coast, there will be barrels moving up, but the Gulf coast is going to have massive incentive to move barrels into the export market and not up to New York harbor. And we're seeing evidence of runs cuts in Europe. We had a gasoline draw last week. I don't particularly put any stock in the APIs, but the APIs indicated, yes, last night's draw, but that has to be watched closely. There is no doubt that the gasoline -- but basically, we just came out of a negative crack environment yesterday at New York, although we're a whopping $0.50 positive crack. So we're watching it. And if the products, if gasoline goes into the tank, you don't make any money. So if that's the case, then I think the industry really has to take that in hand and make cuts if necessary. I said to you before, you will never hear us say in PBF that we're going to run 100% utilization in the upcoming quarter or 98%. You tell me what the crack is, and we'll tell you what we're going to run. And that's what we'll watch, but I'm not quite as concerned on the gasoline side as I was 3 weeks ago. And frankly, distillate and IMO coming out is again a very positive for us. Erik, would you handle Roger's third question?

Sure. So, Roger, I think the answer on the railcar fleet is relatively straightforward. While we absolutely want to continue to increase barrels coming in via rail, this is a very complex supply chain overall and ultimately, what we are really focused on are the most economic barrels, which today are heavy Canadian barrels coming in primarily to the East Coast. And ultimately, when we go back and look at our overall railcar leased fleet, we decided that probably taking a portion of those that weren't really being utilized in crude service and didn't have an alternative use for us, it was better to go ahead and terminate those leases early. As a result, you will see we took a 44 -- $45 million charge for the quarter.

We'll take our next question from Brad Heffern with RBC Capital Markets.

Just as a sort of follow-up to the last question. Can you give your thoughts on Bakken biz? And I know you guys run sort of a baseload of like 5,000 to 10,000 barrels a day at Bakken, but is there any desire to ramp that up over time?

Right now, obviously, Bakken is a very attractive crude. It's an attractive crude for both the Midwest and would be an attractive crude for the East Coast. Specific to your question, we run 5 to 10 a day on occasion of Bakken into Toledo. Right now, that is not crude of choice in Toledo because we can source the Canadian crudes, Canadian sweets and Syncrude, but we do run some Bakken and that is an economic crude in Toledo. Most of the time, we have good cracks. We are running somewhere around 10,000, 11,000 barrels a day of Bakken by rail into Delaware and right now that is obviously very attractive. I'll be interested to watch what happens when the PADD 2 capacity comes up and how much the Bakken spread narrows in because, obviously, there is no tight takeaway constraint on Bakken. You can get it -- with DAPL, get it down to the Gulf coast in The United States. So these wide spreads, I think, perhaps might be impacted by the fact that there is so much capacity offline in the Midwest, we'll see. And...

I'll just make a comment regards to the Bakken. Clearly, we're trying to run the most economic barrels we can in Bakken, that's very attractive. But the fact of the matter is the Canadian heavy to East Coast look even more attractive, orders of magnitude more attractive. So we're constantly trying to maximize our access to barrels, but these differentials exist for a reason and that is because they're somewhat trapped. And rail is not unlimited. It's not simply how many railcars you have, it's not simply your loading capacity, your unloading capacity. You have to put a whole train together of activity to unload it, but the Bakken looks good, and we'll take that where we can. But the fact of matter is the Canadian heavy has looked that much better and so we're certainly maximizing that.

I'll just make 1 point adding to what Matt said is, we've been down this path for many, many years. We were early on and favorably early on in rail. But these are not contracts you can get into. The supply chain, as you mentioned, you can't get in and get out of the day. You have to make some long-term commitments, and we would be -- we are focusing on WCS because we feel like we've got a longer runway on how long those differentials will be made. We're not going to go and enter into costly contracts to try to get another 5,000 barrels a day of Bakken into the East Coast and then have the differential compress, that would be a mistake that we simply are not going to make.

Okay, appreciate all the color. And then, I guess, on PBFX, obviously, you guys know one of your competitors bought in their MLP. So just wondering any thoughts around the value of PBFX as a stand-alone entity and whether you would look to do something with the IERS potentially soon or anything about improving the cost of capital there?

Yes. I would say, as we said in the past, we're constantly looking at the market, I guess, I'd say a little bit more in terms of. We appreciate obviously what's allowed in. We've been looking at everything. It's obviously been a market that's been sideways to down, that's not specific to PBF, but the broader market. And I would expect -- I have nothing to announce today, but I would expect that we make some decisions and talk to the market over the next quarter or so, but it's a dynamic situation. We're -- at this point, we're absolutely committed to the MLP, to PBFX. We're announcing our 16th straight distribution increase. We just closed a very attractive acquisition for both, which will turn out well for not only for PBFX, but PBF will be a beneficiary as well. So it is a mix of things going on. It's a very positive things in particular with PBFX, but the broader market creates headwinds, and we recognize that, and we're going to take steps to best position the partnership going forward.

Our next question comes from Phil Gresh with JPMorgan.

My first question just on the WCS to the East Coast. I believe earlier in the year, Erik, you talked about hedging some of that. I was wondering -- I know the hedge is still on? And if so, was there any hedging impact in the third quarter? I know you don't want to try too much in the way of numbers. In the past, you've said that. But just any kind of clarity around 4Q or 2019 you might be able to provide if there is anything?

We as -- if we go back to the fourth quarter results from 2017, we did have an unrealized hedge loss there that we tried to highlight and that has essentially burned almost all the way off through the course of this year. I think the overall P&L impact for the third quarter for hedges, which are including those WCS-related hedges is about $10 million. So relatively de minimis in relation to the $331 million of EBITDA.

Okay. And as you look at things now, are you considering future hedges? Or was that all of a onetime situation?

I don't think that's something that we're going to address in this call. Well, the forward market looks very, very good, but getting into what we are going to do, I think is not the right answer.

Okay. Fair enough. And then, Erik, just as you think about the capital spending for next year with the coker projects, are there other things that PBF is thinking about right now? Or should we be thinking more of a kind of maintenance capital plus the coker projects in terms of CapEx?

We do not have final board approval for our 2019 capital spend, but directionally what we would say is, we're probably going to have order of magnitude every year, given 5-asset system, roughly $300 million of turnaround-related spend, that's going to fluctuate probably $50 million to $75 million on both the high and low side, another couple of hundred million to $250 million of general maintenance, regulatory, safety spend and then, obviously, we have some discrete projects that we've announced. So we're going to spend, call it, roughly $40 million for the hydrogen plant hookup at Delaware City, that's on our nickel. And then, we obviously have the coker project, which will probably be close to $100 million spend all-in for calendar 2019.

Okay. Great. Last question for Tom. Just your thoughts on the West Coast. You've obviously seen the cracks fade here, it tends to happen seasonally around this time of year, of course. But I noticed that your guidance for utilization is quite high for the fourth quarter. So did you have a strong view on the cracks out there?

Well, we'll watch the California crack, as we will the whole system. The cracks in the summer, as we talked about, were actually seasonally low. We had inventories approaching 30 million barrels of gasoline, that's a number that's too high for PADD 5. That is corrected down to sub 28, which is typically a number that allows margins to improve, and we actually have seen that in the -- during the third quarter. Certainly in the month of September and October, the cracks have been relatively good, although gasoline is coming off now as we've had the change in the RVP season. But one other thing to think about in California, we have a tailwind at least for the moment that we have not had for some time and it's really they're knock-off effect of what's going on in crudes in that we are sourcing more of domestic crude as JV crude, obviously some Canadian crude into Torrance than we had been when we first took over the facility. And our crude differentials, our landing cost of crude is now several dollars under ANS, maybe $2 or $3 better than it has been historically maybe in the last year. So we do have that as a tailwind. We will look at the crack, and we will adjust accordingly. If gasoline goes in the tank, we will adjust. We just don't believe in this idea of being the last man standing. We're going to go ahead and take corrective measures.

Our next question comes from Prashant Rao with Citigroup.

Just sticking on Torrance for a second, on the crude sourcing and crude differential aspect of that. Those [indiscernible] you're bringing in incrementally, is that replacing any of the locally sourced California crudes? Or is that in addition to it? My question is sort of how much broadly speaking could we do on crude sourcing there given that, I think, if I may be correct with that, 1/2 of your crudes are nonlocal California heavies there and those discounts have been widening versus ANS Q-on-Q, but I think it's the other half that maybe there could be some flexibility, some optionality, so just wanted to get your thoughts there.

Yes. It's a good question. And as I said, the President of the western division is sitting in the room here, so he will watch what I say. But the reality is one of the strategies that he has been pushing very heavily is to back out waterborne crudes, which have been relatively tight in favor of either bringing in Canadian crudes and we've been successful in doing that by rail. We'll try to do more, but again, that is going to be limited by the supply chain there. But just as importantly, we've started gathering systems. We're bringing in small volumes of other valley crudes or California domestic crudes. And what we're doing with that is backing out less attractive waterborne crudes and that has helped us, in addition to the fact that the midway ANS diff has widened out. The crude sourcing we're doing is giving us a better landing cost of crude in Torrance than we've seen in some time.

Okay, that's helpful. I guess, sticking on the coast, more broadly speaking from a global perspective, Singapore cracks have been -- Asia cracks look like they are now under pressure. We know it's happening on the East Coast as well with Northwest Europe and this all ties into the gasoline situation. But, Tom, sort of maybe coming back to how you seem to be a little bit more assured on gasoline, but maybe some of the market is a little bit nervous and jittery about. Is that -- are you reading through any sort of run cuts maybe on -- in Asia, and then maybe the same question for the East Coast, for Northwest Europe in response to those margins and that might help to support the coastal assets for PBF in the regional markets? Is that right way? And sort of to get your thoughts around the timing around how those -- how that interplay works would be great.

Okay. It is exactly the point. The fact is, as I said, the RV is completely closed from Europe. I think imports were down sub 400,000 barrels a day last week. We'll see what the numbers say today. You surely don't have economics to run Brent-based crudes. This is a -- and I'll get to the point. This is really a problem for light sweet crude refiners that are pricing or bringing crude in on a Brent basis. So if you're running a Permian basin crude in the Gulf coast, you're not going to have too much of a problem even with gas prices that are sitting in the Gulf coast. But if you are a East Coast refiner and you run Brent crude and you're bringing crude in at Brent flat or Brent plus or Brent minus a couple of bucks, you can't make any money in this marketplace. If you're a European refiner and you're running Brent crude, and you're exporting it, you can't make any money in this marketplace. Now the advantage that we have, of course is, yes, we have heavy crude more complex refineries in the East Coast. So with the crude differentials and the landing cost of crude that we have coming in, we actually can make money as long as the diesel crack holds up, but those refiners that can't I think will have to take steps to cut production and that's the only way that you're going to get gasoline to rebound. And so we -- I see that coming. Let's see what happens...

Do you see that on the West Coast as well? I'm sort of -- I think the East Coast market, you've a very -- you gave some great color there, but as far -- in so far as Asia puts pressure on the PADD 5 gas crack, do you see some of that stepping off because they have been so...

Yes. Absolutely. And in fact, part of what happened is, I think Matt mentioned, the imports into PADD 5 had an impact on the inventories. And therefore, an impact on the cracks and then you will see the corresponding cuts. We may be headed for that as the high RVP season goes, but if indeed -- right now, we've got pretty good gasoline inventories in PADD 5, but if that's starts to move up, we'll see -- most likely, we'll see rate cuts.

Okay. And just one last sort of housekeeping question on Chalmette on the coker. I apologize, you guys have disclosed this previously, but could you remind us sort of what the -- maybe IRR or the capital return hurdle on that coker is so that we can get a sense of how you're thinking about incremental cash flow on the restart.

Yes. If you look at the coker in what I would describe is a midcycle environment, you're probably over $40 million of EBITDA, but like everything else, if you look at post-IMO market, you're more than double that. And so one of the things that's extraordinary about this project is the fact that a year from today should be operational. So whatever your views are for the post January 1, 2020, market, it simply looks very, very attractive. It looks good in a normalized market and looks extraordinary in IMO market.

We'll take our next question from Paul Sankey with Mizuho.

I hate to raise this, but there was reports on Reuters of an accident to Delaware City yesterday. Could you just update us on that?

Yes, Paul, normally quite frankly, we wouldn't, except there was some extraordinary misreporting. And so we feel somewhat obligated. There was no explosion at Delaware City. There were unfortunately some contractor injuries yesterday while they were performing routine maintenance. There was no disruption to our plant or our operations. I'm not going to get into the specific injuries with the specific people obviously. We have the highest concern and the highest care going for the individuals. And so I'm not going to get into the specifics there, but the reporting was wildly inaccurate yesterday. And in regards to operations, there is no impact to our operations.

Understood. The potential impacts, I think, we're looking at with IMO, I guess, the concern of the market is the prices are driven so high that there is an knee-jerk or whatever response from Washington. And, I guess, in the context of that, you're also committing to a coker project, which I assume have some assumptions, obviously, about pricing and markets. Is your view simply that it's not tenable for the IMO not to be put through or rather that the market doesn't react to the point where it becomes sort of a crisis?

I personally think the IMO is going to stay the course. And really when you look at this, there is -- the politicians would do what the politicians do. But when you look at it, a 3% sulfur content bunker fuel. We've said this before. I think the bunker fuel accounts for 5% of the transportation fuel demand and over 60%, some say 75%, of the sulfur additions on transportation fuel. So it's the right thing having cleaned up the sulfur levels in distillate and gasoline to take this step. So it's a little bit interesting that The United States and other places in the world require 0.1% sulfur in the ports as the ships come in, EcoPorts and concerned about whether or not this is too much, too fast. But I think it's going to go. And I think it's going to go 2020. And the fact that they put the carriage band through is going to help with compliance. There will be some market moves associated with this. I think we expect to see the diesel price go up, and we expect to see heavy fuel oil pricing go down. Therefore, the clean dirty spread goes up and that's the incentive to coke. And In fact, that will likely be the case, but this industry is well known for figuring out how to respond to the market demands. And my own view is this will be a finite opportunity particularly on the distillate side. I think it will have more legs on the crude differentials because sulfur is , again, now the enemy and the longer-term sweet-sour spreads on crude oils might stay wider by $1 or $2 a barrel. And that did influence us to a certain extent on restart of the coker. But as Matt said, that coker we shut down for reasons that were associated with the busted marriage of the joint venture. It shouldn't have been shut down. We're contemplating starting it up. It's a good project in a non-IMO world, and it's a terrific project with a $40 or $50 clean dirty spread. And if that goes away and returns to normal, if there is an upside on crude differentials of $1 or $2, it's somewhere between a good and a great project, but we're happy about that.

The fact that the coker is on the ground, it's literally a bird on the ground for us and whatever the economic are for a [indiscernible] coker, the economics associated with this project are twice as good because it comes at half the cost.

Yes. It's important to note, Paul, that when we say it's $110 million and it is $110 million. But basically $72 million of that $110 million is doing a turnaround. So there is another $20 million, $25 million of additional safety enhancements that we're doing since the unit has been down to make it safer, but it's basically saying. Okay, it was protected, it was under nitrogen. But they shut it down to avoid doing the turnaround. For us to start it up, we have to do the turnaround and it's almost maintenance.

This really, Paul, this is one of the key pieces that was attractive around the Chalmette acquisition for us a few years ago as we had a handful of idled units that were there that were taken down very carefully. However, the prior ownership group elected not to essentially do turnaround work. So for the long-term viability and flexibility of the Chalmette refinery, this is a great project that will allow us a lot more optionality and flexibility on crude and feedstock sourcing going forward.

We'll take our next question from Neil Mehta with Goldman Sachs.

So first question is just around your views on M&A. You built this company up by doing a series of acquisitions and you guys have not been shy about wanting to continue to grow the business, particularly, on the refining side. So just your thoughts on bid-ask. I would imagine it's one of the factors that's really challenging around valuing assets in any transaction as how to price in IMO, but there's more talk of some refining assets coming into the market. So just curious on your firsthand perspective around the M&A markets for refining? And where you guys see yourselves in terms of your involvement around that?

Nothing has really changed in terms of our strategy. We do have a desire, obviously, the right asset at a price that is in a wheelhouse in terms of taking the asset, growing the business. We have been on a record that part of our strategy is to have more than 1 refinery in a region that we operate in. It's a cheap form of an insurance, to be honest, if you have that. So that's an objective. We already have that in PADD 1. We will likely not go in to get it there too because to your point on bid-ask, I think base case with the Canadian situation and then IMO, it would be hard to get a deal done now. So therefore we go to PADD 3 and to PADD 5, and they are strategic areas for us. We're looking, but I think you hit it correctly. As we approach IMO, everybody wants a refinery, has figured out a way to say that it's going to be advantage because of IMO. That could be a heavy refinery, a complex refinery, it could be a [indiscernible], but they believe IMO is going to be an advantage for them. So the bid-ask is a bit wide. That being said, there are some things that we were focusing on or looking at because the strategy hasn't changed, but I do think that IMO creates a wider bid-ask and makes getting the deal done a little bit more problematic.

Yes. Now that makes a lot of sense. And second question is more -- a little bit more tactical. Tax rate just in general, where we should be using on a go-forward basis. Is 27% still the right number? Or could the number be a little lower than that?

No. 27% is probably the right long-term number. Quite frankly, during this past quarter, it simply comes down to state tax apportionment and so ultimately, if you're operating and making more money in certain regions that have a lower state tax rate, then obviously, your implied rate will come down, but again, this goes to just geographic diversity of the system. We think on a longer-term basis, our 27% guidance is pretty good guidance.

And the last question, Tom. I think it was on our panel earlier this year at the conference, you were talking a little bit about Venezuela and one of your predictions was that the situation could deteriorate and then eventually there could be light at the end of the tunnel. Just curious on your latest views there, recognizing you're buying less in terms of Venezuelan barrels, but it certainly has an impact on the way we think about the light heavy on the Gulf coast?

I think if we were having the panel today, I would say the same thing. I think the situation has continue to deteriorate, but I don't think it has to, then ultimately hit the bottom and come back. And if you look at Venezuela, their refinery utilization, I guess, I saw a number last week is down to 17%. So now they're back selling crude to the U.S. and I don't know if we're getting any, I haven't checked it lately, but they're now selling crude and they're selling crude not because their production is up. They're selling crude because they're not consuming it. So they turn around and sell the crude and then they have to buy the products in order to get products consumption to fit demand in the country. I think that what they've got -- what they've got to do. I don't really know what they have do, but the reality is, they've got these dead calls coming in, the fact that they settled quote with ConocoPhillips was a step in right direction. It would seem to me that they've got to get those deals -- those counterparty issues resolved and then they can move onto whether or not they sell Citgo or whatever they're going to do to try to solve their debt problems and hopefully get to the point that the country gets a little bit more stable and then can bring investment back. It's still country with huge natural resources, and there will be a time when all of this gets settled, and I would hope that would be earlier because the people of Venezuela frankly deserve better.

We'll go next to Matthew Blair with Tudor, Pickering, Holt.

You mentioned that Chalmette is a work in progress, and it does look like the margin capture is down this year compared to last. In terms of the timing on this plantwide optimization effort, when would you expect to see the benefits flow through? And also, is there any opportunity for WCS crude by rail into Chalmette?

Let me take the first piece. The optimization effort, I think we admitted that the focus initially was clearly on Torrance, and we had a massive effort there. And that's a priority. That effort is not completely done in tranche, but we're at the point now that we shifted the resource base and the key people that were looking at the optimization opportunities in Torrance now to the rest of our system with primary emphasis on Chalmette. We've already seen some payouts on that. We are sourcing isobutane in cheaper. We've reduced octane giveaway in the gasoline pool rather significantly, a couple of million dollars a year when I say significantly. We got into the asphalt business, but that's really kind of the tip of the iceberg. We really think the area that we want to focus in is some additional crude sourcing and that's a big area especially given what's going on in Venezuela. But one of the things that we really look at in Chalmette is that it has a relatively low light product yield, and there is a couple of opportunities that we're looking at to increase jet -- get back into the jet business and to increase the production of ULSD out of life-cycle oil. That is going to take some time, maybe 6 months and may involve a little bit of capital, nothing big. But there are very good opportunities not to the extent that we saw in Torrance. Of course, Torrance was an isolated system. And we can get into different markets, Arizona and Las Vegas, but probably about half of that. So there is a lot of opportunities yet to be coming in optimization at Chalmette.

It will feather in over the next rolling 4 quarters. We've -- as Tom mentioned, we've achieved some of it. It's -- in many respects, this can be quick kick projects, but the entire leadership down there has embraced the exercise. And like I said, I would expect a capture rate, which is clearly dependent on crude differentials and some other things, but the things that they can control, you'll see -- start seeing marked improvement in Chalmette.

In terms of WCS by rail, it's a modest amount. We can get some down there, but it's not in overly significant quantities.

Got it. And then in terms of modeling now, Toledo going forward, I guess, I would have thought the Q4 throughputs might have been a little bit higher just given the appealing crude discounts you're seeing. Could you talk about maybe why those are? Where they are? And then also the Syncrude share in Q3 was down to 27%. Is that a good number to use going forward? Or are you shifting, I guess, Canadian lights instead of Syncrude at Toledo?

Actually, the last part of your question is, we look at Canadian lights and Syncrude early basis. If you look before this latest move on differentials coming out of Canada, routinely Syncrude would be the Canadian sweets. Now there has been times in the last quarter or last 6 months where in fact that is inverted, but we still run -- we're going to run a significant amount of Syncrude and try to source in even more sweets. I think -- so there is no real change in what the raw material mix is going to be going forward. I think the reality is the difficulty in sourcing the crude because of some of the things that are going on in Canada, prorations on the pipe has got us to where we didn't anticipate being as wide as we were. We programmed in that we're going to run Toledo full assuming that it runs as well as it can, but that's after the PADD 2 refineries come up. Then Toledo is likely going to go what the Midwest market does all the time, which is when you don't need imports from PADD 2 and you're self-sufficient on your products, your crude oil to hang into products over the hang. If that's the case, then that we would normally run 140 or 145 in Toledo. If it isn't, we'll try to source more crude and take the opportunity to get more of the crowd.

Our next question comes from Doug Leggate with Bank of America Merrill Lynch.

This is Kalei on for Doug. I've got an IMO question. So let's say, the gasoline and diesel margins, these trends they carry over into 2020 where the gasoline cracks are unprofitable and diesel and marine bunker cracks are ripping. What's the ability of your system to minimize gasoline and maximize other products? And what I'm hoping now you will talk about is the flexibility of your cat feed, and how does this all tie into your view of 2020 margins?

Okay. The last piece of the question, I'm sorry, you said, view of what feed?

Cat feed.

Oh, cat feed, okay, good. First of all, the simple answer to -- we make about 500,000, 600,000 barrels a day of gasoline and distillate together out of our system, and you can assume that we can swing the volumes 10% between the pool. So if we go to a max distillate, by the way, we're at max distillate pretty much everywhere, maybe not there yet -- we probably there even in California, because of these wide margins. So we're in a max distillate mode. And in the forecast that -- the scenario you paint, which is definitely a possibility. If we carry this forward, we have these wide spreads between gasoline and distillate. That's what you would expect. The whole industry will run max distillate. Now if demand doesn't crater, ultimately that max distillate as you get into the gasoline season is going to be a factor, right, because you won't be -- as we move into April or March of next year, pretty much everybody goes into full gasoline mode in anticipation of the driving season. And if you don't do that because you have such good margins on diesel, well, then you're likely to going to have a shortage in gasoline and less demand craters. That's one scenario and that's why many people in IMO think that gasoline prices are going to go -- the gas crack is going to go up not to the extent the diesel crack is, but it's going to go up because you're going to unmake gasoline and turn it into distillate. The other part of your question is, this is real -- it would be 3 million barrels a day of increased demand for a low sulfur fuel oil -- ultra-low sulfur fuel oil or whatever. People say how you're going to be able to do that, make that. While I made the point before, we can take valve and shut it on the material coming off of the Torrance high-pressure hydrotreater and carrying 105,000 barrels a day of cat feed into compliant fuel or 0.5 fuel. And we're not going to go do that, but everybody who has a high-pressure hydrotreater has that knob to turn now. And you can -- you might well see people say, "Hey, if the price of the low sulfur fuel oil or the 0.5 fuel oil comes up high enough that you'll go ahead and short runs on to a cat crack, especially if you have -- don't have really good gasoline margins and you will make the compliant fuel coming off the hydrotreater. So there's lots of different knobs that the refiners have. In our system because of our complexity, we have more knobs than most.

Next question is from Roger Read with Wells Fargo.

I'm sorry guys. My question has been answered. I appreciate it.

We'll go next to Paul Cheng with Barclays.

I have to apologize first because I come in late so you may have already addressed it, so I would take it offline. Tom, have you guys talked about that how much is the volume that you're rolling in, in the third quarter, both Bakken and WCS into the Northeast market? And what do you expect in the fourth quarter? And more importantly is that how much more that you think you can ramp it up not like what Bakken recently that has been not able to create a market, means that their well capacity is not sufficient to clear yet. Is that what you've seen? And if that's the case, how quickly we can ramp up those capacity?

Matt talked to that briefly, but let me just reinforce it, Paul. We ran -- we're going to run 65,000, 70,000 barrels a day of WCS in by rail and to the East Coast. And that's our plan going forward with the differentials that we see. And the limitations on takeaway capacity is you're well aware, they're not going to be overcome in near term, it's going to take several years. So we would expect to continue to do that, and we're doing that today and it is helping our East Coast system. In addition, we rail in 8,000 to 10,000 barrels a day WCS into Torrance. The Bakken is more of an interesting one. This is really -- with DAPL -- always surprised that Bakken was so tight in terms of market price to TI because you got to transport it down to the Gulf coast in The United States and pay all these tariffs, but that was on course. It appears -- certainly, Bakken has moved out significantly. We are railing some Bakken in 10,000, 12,000 barrels a day. And we'll try to do incrementally more, but we are not going to enter into a long-term contract, which is really what you need to do on a supply chain. As you know, you got to have the loading space some place in either Canada or in North Dakota or wherever. You got to have the railcars, you have to have the contracts with the rails and then you got to get it to your unloading area. We have the unloading area, there is no doubt about that, but we would be reluctant to enter into a long-term commitment going out 3 or 4 years to move 40,000 barrels a day of Bakken because we could get to a month from now and all the Midwest refineries are up and running, and we could be back to where Bakken is trading to $3 under Brent and you're out of the money, and we've been in that path before and we're not going to do that.

Tom, just curious that if the rail operator this time around, they're really resisting to ramp up the capacity if you don't sign any long-term contract because in the [indiscernible] that is a little bit easier for that discussion?

Yes. I think that's exactly the point, Paul. Maybe the first time around it was incremental business to them. "Okay, we'll do this." And then now it's a big business. And if they're going go ahead and make the commitments, put on more engines, more crude, more staff to go ahead and change there, they may take on less grain or whatever in order to do this. While they want a longer-term commitment and they want a bigger piece of the [ark], and fortunately for us, with what we've done, we've entered early, and we've got our contracts in place for what we're doing, but if you want to go out and do significantly more, you're going to have to pay up for that. We sat and talked about this ad nauseam and our view was let's focus on where the biggest bang for the buck is and that is WCS crude out of Canada to our system and we're doing that successfully, and we'll trim around the edges on when we can on sourcing more crude. But if you want to do something big like we were doing before when we were railing in 100,000 barrels a day of Bakken into Delaware City, you're going to have to enter into contracts of 3, 4, 5 years with the rail, with the loading facilities and the MVCs on that are going to be prohibitive and just not ready to take that leap on something like Bakken.

Tom, does that mean that your WCS volume is under long-term contract?

We have been termed up for -- not all of it, but we continue to go out into the hinterland and look for crudes, but yes, part of this thing is, we don't want to go in and have all these railcars and then find out we can't buy the crude. So we've termed up or we've got deals in place to source the barrels. We've got deals in place to load the barrels. We have the railcars to be able to move the barrels in unit trains, and of course, we have our unloading facilities. So on the WCS side for the near future, we're in good shape.

Can you share with us then what is your cost all in to move from [port] into the Northeast? And also that what is the 10,000, 12,000 barrel per day currently you're moving Bakken, what's the cost?

We've talked about. We don't particularly like to give you an exact cost, but we've talked before that we can move and really nothing has changed and the contracts are in place that we're railing in WCS somewhere depending upon where we're loading the crude. It's different load ports that are not ports but places $16 to $18 and really nothing has changed in the Bakken, it's $10 to $12 to get the Bakken in.

But that if you really want to do much more than the 10,000 to 12,000, I suppose that $10 to $12 is not going to cut it, that's why you're not doing it?

That's correct. We have to go out and enter into new leases on railcars and get more loading space, and we would not be able to replicate that at $10 to $12. And you could do...

How much is that today if you want to round it up?

Actually, the biggest issue for us that you could probably get it done, but you'd have to commit to doing it for 5 years. And we're not ready to do that because we don't think that Bakken by rail has got the longevity that Bakken -- or that WCS has.

And it does appear, we have no further questions. I'll return the floor to Tom Nimbley for closing remarks.

Well, thank you, everybody, for attending the call. We had a good quarter. And we hopefully will look forward to the next call when we can give good results. Thank you, and everybody have a great day.

And this will conclude today's program. Thanks for your participation. You may now disconnect.