PBF Energy Inc
NYSE:PBF
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PBF Energy Inc
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Good day, everyone, and welcome to the PBF Energy Third Quarter 2018 Earnings Conference Call and Webcast. At this time, all participants have been placed in a listen-only mode, and the floor will be opened for your questions following management's prepared remarks. Please note this call is being recorded. And it's now my pleasure to turn the floor over to Colin Murray of Investor Relations. Sir, you may begin.
Thank you. 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 describe in our filings with the SEC. Consistent with our prior quarters, we will discuss our quarterly results excluding a non-cash 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 an operations perspective, we had a 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 our 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, remain relatively flat versus the second quarter and continue to reflect strong demand. West Coast cracks were somewhat seasonally weak, driven by gasoline margins as 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 costs on the West Coast. Normalizing for the natural gas prices, our refinery operating expenses averaged 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 plant 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 should in service by this time next year. Importantly, this coker project will be completed in less than a third the time and less than half 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 on 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 have 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 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 LTM 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 rent expense for the third quarter totaled $34 million. At the current rate, we can see full-year rent 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 an 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, 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 refining equities as a result of posturing (00:10:10) around the implementation of the impending standards. Following their meetings last week, the IMO affirmed both the timeline for implementation of the new standards and the carriage ban on high-sulfur fuel oil.
Despite recent speculations 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 in a 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'll be pleased to take any questions.
Our first question comes from Roger Read with Wells Fargo. Please go ahead. Your line is open.
Yes, thanks. Good morning and solid quarter there, guys.
Just to jump in here, I guess two things really standout, crude differentials, and if you could kind of give us an idea what the railcar cancellation was given that crude does seem favorable and you'd want more rather than less railcars, so, 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 the IMO, it 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 the rail situation. But the differentials from both WCS, Syncrude and, frankly, Canadian sweet, have all moved out to be very beneficial. Much of that is driven or has been exacerbated in this quarter because of the significant amount of downtime that is occurring and still occurring in PADD 2. But predominantly, it's (00:13:05-00:13:13) spread into Syncrude. Obviously, Toledo...
Tom, excuse me, real quick there. I don't know if it happened to everybody else, but it 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. Thanks.
All right. They obviously were massive tailwind for us. They were exacerbated – those spreads were exacerbated by the 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 shifting 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 (00:14:18). We expect that to be the case going forward, perhaps not at the differentials we see now when BP Whiting comes back up and turnaround 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 (00:14:49) 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 the 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, are looking at the gasoline inventories. There is cause of concern (00:15:28). I am not as quite as concerned as I was three weeks ago and that's simply because the markets are starting to move. The office closed (00:15:36) completely from Europe, the office closed (00:15:40) from 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 (00:16:00). But that has to be watched closely. There is no doubt that the gasoline – that base that we just (00:16:10) came out of a negative crack environment yesterday in New York Harbor where a whopping $0.50 (00:16:13) 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've 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 three weeks ago and, frankly, distillate, and IMO coming at us is again a very positive for us.
Erik, would you handle Roger's third question.
Sure. So, Roger, I think the answer on the rail car fleet is relatively straightforward. While we absolutely want to continue to increase barrels coming in via rail, it 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 rail car 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'll see we took a $44 million (00:17:38), $45 million charge for the quarter.
All right. Appreciate it. Thank you.
We'll take our next question from Brad Heffern with RBC Capital Markets. Please go ahead.
Hey. Good morning, everyone. Just as a sort of follow-up to the last question. Can you give your thoughts on Bakken dips and I know you guys run sort of a base load of like 5,000 to 10,000 barrels a day of 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 5,000 to 10,000 barrels a day on occasion of Bakken into Toledo. But right now that is not crude of choice (00:18:30) in Toledo because we can source the Canadian crudes, the Canadian sweet and Syncrude, but we do run some Bakken and that is an economic crude in Toledo most of the time when we have good cracks.
We are running somewhere around 10,000 barrels, 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 pipe takeaway constraint on Bakken. You can get it (00:19:07) down to the Gulf Coast in the United States. So, these wide spreads I think perhaps might be impacted by the fact that there's so much capacity offline in the Midwest we'll see. And what was the third...
I'll just make a comment in regards to the Bakken. Clearly, we're trying to run the most economic barrels we can in Bakken looks very attractive. But the fact of the matter is the Canadian heavies to our (00:19:35) 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 heavies look that much better. And so, we're certainly maximizing that.
I'll just make one 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 we mentioned, you can't get in and get out in 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 would 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 I'm 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 standalone entity and whether you would look to do something with the IERs (00:21:15) 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 little bit more in terms of we appreciate obviously what Valero did. 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 like – well, 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 where 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 not only for PBFX but PBF will be a beneficiary as well. So, it is a mix of things going on, some 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.
Okay. I'll turn it back. Thanks.
Our next question comes from Phil Gresh with JPMorgan. Please go ahead.
Hi, good morning. My first question just on the WCS to the East Coast, I believe earlier in the year, Erik, you had talked about hedging some of that. I was wondering are those hedges still on? And if so, was there any hedging impact in the third quarter? And I know you don't want to probably give 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?
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 more of a onetime situation?
I don't think that's something that we're going to address in this call. Look, 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 a 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 magnitude every year, given a five-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 hook up 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, do 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 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 the knock-off effect of what's going on in crudes and that we are sourcing more domestic crude, SJV crude, obviously some Canadian crude into Torrance than we have been when we first took over the facility. And our crude differentials, our landed 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.
Thanks, Tom.
Our next question comes from Prashant Rao with Citigroup. Please go ahead.
Hi. Good morning. Thanks for taking my questions. Just sticking on Torrance for a second on the crude sourcing and crude differential aspect of that, the WCS that you're bringing in incrementally, is that replacing any of the locally-sourced California crudes or is that an 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 remember correctly, that half of your crudes are non-local 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'll 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 dip has widened out, the crude sourcing we're doing is giving us a better landed cost of crude in Torrance than we've seen in some time.
Okay, that's helpful. Thanks. I guess sticking on the coasts, more broadly speaking from a global perspective. Singapore cracks have been – Asia cracks looked like they've been 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 than 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 in Asia? And then maybe the same question for the East Coast, for Northwest Europe, in response to those margins that might help to support the coastal assets for PBF in the regional markets, is that the right way – and sort of to get your thoughts around the timing around how that interplay works would be great.
Okay, it is exactly the point. The fact is as I said the office completely closed in (00:29:43) Europe. I think imports were down sub-400,000 barrels a day last week. We'll see what the numbers say today. You certainly don't have economics to run Brent-based crudes. This is – 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 the gas prices that's sitting in the Gulf Coast. But if you're an 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 landed cost of crude that we have coming in, we actually can make money as long as the diesel crack holds up. But those refineries that can't, I think we'll have to take steps to cut production and that's the only way they're going to get gasoline to rebound, and so I see that coming, we'll see what happens.
Do you see that on that on the West Coast as well? I'm sort of – I think the East Coast market you gave some great color there, but as far – insofar as Asia puts pressure on the PADD 5 gas crack, do you see some of that stepping off because they've been...
Yes, absolutely, and in fact as 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, and 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 (00:31:55) if it move up we'll see – most likely we'll see run cuts (00:31:57).
Great, thanks. And just one last sort of housekeeping question on Chalmette on the coker. I apologize if you guys have disclosed this previously. But could you remind us sort of what the – maybe the IRR (00:32:11) or the capital return hurdle on that coker is so we could sort of get a sense of how you're thinking about extra incremental cash flow on the restart.
Yes. If you look at the coker in what I would describe as a mid-cycle environment, you're probably over $40 million of EBITDA. But like everything else, if you look at it in a 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 it should be operational. So, whatever your views are on sort of the post-January 1, 2020 market, it simply looks very, very attractive. It looks good in a normalized market and it looks extraordinary in a IMO market.
All right, great. Thanks for the time, gentlemen. Appreciate it. I will turn it over.
We'll take our next question from Paul Sankey with Mizuho. Please go ahead.
Good morning, all.
Good morning.
I hate to raise this, but there was reports on Reuters of an accident in Delaware City yesterday, could you just update us on that?
Yes, Paul. And 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 can't get into specific injuries with specific people obviously. We have the highest concern and the highest care going for the individuals. And so, I'm not going into the specifics there, but the reporting was wildly inaccurate yesterday. And in regards to operations, there is no impact to our operations.
Understood. Thank you, Matt. The potential impacts I think that we're looking at with IMO, I guess the concern of the market is that prices are driven so high that there is a 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 has some assumptions obviously about pricing in 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, that there is a – the politicians will do what the politicians do. But when you look at it at 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 (00:35:09) 75% of the sulfur emissions from transportation of fuel. So, it's the right thing having cleaned up the sulfur levels in distillate and gasoline to take this step. It's a little bit interesting that the United States and other places in the world require a 0.1 sulfur in the ports as the ships come in, the eco ports, 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 ban 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 (00:36:01) 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'll 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 the restart of the coker.
But as Matt said, that coker was shut down for reasons that associated with the busted marriage of the joint venture. It shouldn't have been shut down. We had 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's an upside on crude differentials of $1 or $2 it's somewhere between a good and a great project and we're happy about that.
The fact the coker is on the ground (00:37:15) ground for us and whenever the economic are for a newbuild 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's another $20 million, $25 million of additional safety enhancements that we're doing since the unit's been down to make it safer. But it's basically saying, okay, it was protected, it was under nitrogen (00:37:47) but they shut it down to avoid doing a turnaround. For us to start it up, we have to do the turnaround and it's almost maintenance (00:37:55)
Just really, Paul, this is one of the key pieces that was attractive around the Chalmette acquisition for us a few years ago is 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.
Great. Thanks, guys.
We'll take our next question from Neil Mehta with Goldman Sachs. Please go ahead.
Hey, guys. Thanks for taking the question. So, first question is just around your views on M&A. You've 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. But 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 is how to price in IMO (00:39:06). But there is more talk of some refining assets coming into the market, so just curious on your firsthand perceptive 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 our wheelhouse in terms of taking the asset, growing the business. We have been on the record that part of our strategy is to have more than one refinery in a region that we operate in. It's a cheap form of insurance, to be honest, if you have that. So, that's an objective. We already have that in PADD 1. We'll likely not going to get it in PADD 2, 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.
So, therefore, we go to PADD 3 and to PADD 5 and they are strategic areas for us. We are looking – but I think you hit it correctly, as we approach IMO, everybody who owns a refinery has figured out a way to say that it's going to be advantaged because of IMO. That could be a heavy refinery, a complex refinery, it could be a teakettle. But they believe IMO is going to be an advantage for them. So, the bid-asks are 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.
No, no, that makes a lot of sense. The 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'd say the same thing. I think the situation has continued 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 then 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 to do – I don't really know what they have to do, but the reality is these debt calls (00:42:59) coming in, the fact that they settled the quote (00:43:04) with ConocoPhillips was a step in the right direction. It would seem to me that they've got to get those deals, those counterparty issues resolved and then they can move on to 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 a country with huge natural resources and there will be a time when all that is get settled and I would hope that would be earlier because the people of Venezuela, frankly, deserve better.
Thanks, guys. Appreciate the time.
We'll go next to Matthew Blair with Tudor, Pickering & Holt. Please go ahead. Your line is open.
Hey, good morning, guys. 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 plant-wide optimization effort, when would you expect to see the benefits roll 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 took priority. That effort is not completely done in Torrance, but we're at the point now that we shifted the resource base and the key people that we're looking at the optimization opportunities in Torrance now to the rest of our system with the primary emphasis on Chalmette.
We've already seen some pay-outs on that. We are sourcing isobutane in cheaper. We've reduced octane giveaway and the gasoline pool rather significantly, 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 some additional crude sourcing. 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 it has a relatively low light product yield and there's a couple of opportunities that we're looking at to increase – get back into the jet business and to increase the production of ULSD out of light cycle oil. That is going to take some time (00:45:41) maybe six 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 because Torrance was an isolated system and we can get into different markets – Arizona and Vegas – probably about half of that. So, there's a lot of opportunities there yet to be coming in optimization of Chalmette.
It will feather in over the next rolling four quarters. As Tom mentioned, we've achieved some of it. In many respects, it can be quick projects but the entire leadership down there has embraced the exercise. And like I said I would expect the capture rate, which is clearly dependent on crude differentials and some other things but things that they can control, you'll start seeing marked improvement in Chalmette.
Sounds good. And then...
And then 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 if we look at Canadian lights and Syncrude (00:47:34) if you look before this latest move on differentials coming out of Canada, routinely, Syncrude would beat the Canadian sweets. Now, there's been times in the last quarter or the last six months where, in fact, that is inverted (00:47:49). But we still run – we're going to run a significant amount of Syncrude and try to source in even more sweets. So, there's no real change in what the raw material mix is going to be going forward.
I think the reality is there's the difficulty in sourcing the crude because of some of the things that are going on in Canada, prorations (00:48:15) 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, you'll turn a crude overhang into a products overhang. If that's the case then that we would normally run 140 or 145 (00:48:52) in Toledo. If it isn't, we'll try to source more crude and take care of the – take the opportunity to get more (00:48:58).
Thanks, guys.
Our next question comes from Doug Leggate with Bank of America Merrill Lynch. Please go ahead.
Hey, guys, good morning. 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 that you'll talk about is the flexibility of your cat feed? And how does this all tie in to 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 (00:50:00). So, if we go to a max distillate, by the way, we are at max distillate pretty much everywhere, maybe not there yet (00:50:09) in California because of these wide margins. So, we're in a max distillate mode. And in the forecast, the scenario you paint which is definitely a possibility if we carry this forward and you have these wide spreads between gasoline and distillate, that's what you would expect. The whole industry will run max distillate.
Now, if demand (00:50:35) ultimately that max distillate as you get into the gasoline season, is going to be a factor, right, because you won't – 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 going to have a shortage in gasoline unless demand craters (00:51:00). That's one scenario and that's why many people in IMO think that gasoline prices are going to go – the gas cracks 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 a distillate.
The other part of your question is this is real with the 3 million barrels a day of increased demand for a low-sulfur fuel oil, ultra-low sulfur fuel oil, whatever, people say how are you going to be able to do that, make that. Well, I've made the point before, we can take a valve and shut it on the material coming off the Torrance high-pressure hydrotreater and carrying (00:51:40) 105,000 barrels a day of cat feed into compliant fuel, of 0.5 fuel, and we're not going to 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, the price of the low-sulfur fuel oil, the point 0.5 fuel oil comes up high enough that you'll go ahead short runs on to a cat cracker (00:52:08) especially if you have – don't have really good gasoline margins and you'll 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.
Lot of moving parts, guys. Really appreciate the insight. That's all I had. I'll leave it there.
Next questions from Roger Read with Wells Fargo. Please go ahead.
Yes. I'm sorry guys, my question has been answered. Appreciate it.
Okay.
Thanks, Roger.
We'll go next to Paul Cheng with Barclays. Please go ahead.
Hey, guys. Good morning.
Good morning, Paul.
I have to apologize first because I come in late so you may have already addressed it. If so, I would take it offline. Tom, have you guys talked about that how much is the (00:52:59) 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 (00:53:16) both Bakken recently that has been not able to clear the mark (00:53:22) that means that the well capacity is not sufficient to create yet (00:53:27). 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 70,000, 65,000, 70,000 barrels a day of WCS and 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, as you are well aware, they're not going to be overcome in the 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 (00:54:16) with DAPL, I'm always surprised that Bakken was so tight in terms of market price to TI (00:54:25) because you've got to transport it down to the Gulf Coast in the United States and pay all these tariffs, but that was on cost. It's appears – and 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 long-term contracts, which is really what you need to do on a supply chain as you know. You've got to have the load space someplace 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've got to get it to your unloading area. We have the unloading area, there's no doubt about that. But we would be reluctant to enter into a long-term commitment, going out three or four 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 $3 on the Brent and right on the money (00:55:24) and we've been down that path before. We're not going to do that.
Tom, just curious that is the well 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 past (00:55:44) a little bit easier there for that discussion?
Yes, I think that's exactly the point, Paul. Maybe the first time around it was incremental business to them. Yes, okay, we'll do this. And then now it's a big business and if they're going to go ahead and make the commitments, put on more engines, more crew, more staff, to go ahead and change their – they may take on less grain or whatever in order to do this, well, they want a longer-term commitment and they want a bigger piece of the (00:56:14).
And fortunately for us with what we've done, we were in early, and we've got our contracts in place (00:56:23), 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 on 100,000 barrels a day of Bakken into Delaware City, you're going to have to enter contracts that are three, four, five years with the rail, with the loading facility, and the MVCs on that are going to be prohibitive and we're just not ready to take that leap on something like Bakken.
Tom, does that means that your WCS volume is under long-term contract?
We have it termed up for – not all of it. We continue to go (00:57:19) and look for crude. But, yes, part of this thing is making – we don't want to go in there 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 show us 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 facility. So, on the WCS side, for the near future, we're in good shape.
Can you share with us then what is your cost (00:57:49) move from Alberta into the Northeast? And also that what is the 10,000 barrel, 12,000 barrel per day currently you move in (00:57:57) 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 (00:58:08) contracts are in place, that we're railing in WCS somewhere – dependent upon where we're loading the crude is different load ports (00:58:20) 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 barrel to 12,000 barrel, I supposed that the $10 to $12 is not going (00:58:36). That's why you're not doing it.
That's correct. We'd 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 a $10 to $12 or we could do...
How much is that today if you want to ramp it up (00:58:57)?
Actually, the biggest issue, Paul, is that you could probably get it done, but you'd have to commit to doing it for five years. And we're not ready to do that because we don't think that Bakken by rail has got the longevity that Bakken by – that WCS has.
I see. Thank you.
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 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.