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 open for your questions following management's prepared remarks. If you'd like to ask a question, please press star and one on your touch-tone phone. You can remove yourself from the queue by pressing the pound key. 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 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 will 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, remained 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 on 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 $60.75 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 should be 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 Aromax unit 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 could see full-year RIN expenses in the $150 million-$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.
I'll turn the call over to Tom.
Thank you, Erik, 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 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 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 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 would be pleased to take any questions.
In a moment, we will open the call to questions. The company requests that all callers limit each turn to one question and one follow-up. You may rejoin the queue with additional questions. If you'd like to ask a question, it's star and one on your touch-tone phone. Our first question comes from Roger Read with Wells Fargo. Please go ahead. Your line is open.
Yeah, thanks. Good morning. Solid quarter there, guys. Just to jump in here. I guess two things really stand out. 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's pretty easy to understand from our point of view. The other thing to hit on, if we could gasoline inventories and gasoline cracks, because while I agree with you on the IMO was certainly a headwind for the equities here, I think fundamentally gasoline has people a little unsettled. If you could give us some thoughts on that.
Yeah. Well, I'll take a couple of those and pass on to Erik, one on the story on the rail situation. Look, the differentials for both WCS, Syncrude, and frankly, Canadian Sweet, have all moved out to be very beneficial. Much of that is driven for or has been exacerbated in this quarter because of the significant amount of downtime that is occurring and still occurring in PADD 2. Predominantly, it's had a contagion spread into Syncrude. Obviously, Toledo.
Tom, excuse me real quick there. I don't know if it would happen to everybody else, but it went totally blank there for about the first part of your answer.
Okay. Let me repeat it for everybody then. When we look at the differentials, particularly the North American differentials coming out of Canada and Bakken. Can you hear me now, Roger?
Yes, absolutely. Thanks.
All right. They obviously were a massive tailwind for us. Those spreads were exacerbated by the high level of turnaround activity in PADD 2 in the quarter, which is continuing. They will likely narrow in some, but they are underpinned by the lack of takeaway capacity coming out of Canada. That is not just WCS. It is now spread because of some shifting and sourcing of crudes to Syncrude. We expect. 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 from turnaround at either mid or end of the month. They will stay wide, and we expect to be able to benefit from them.
Frankly, we're seeing those advantages in Delaware in a big way, Erik will talk about the rationale behind the rail cars. We are running, as Matthew 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 the pricing. Then we'll see what happens just going forward. 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. Let me take the gasoline distillate. We too are, as I mentioned, are looking at the gasoline inventories. They always cause concern.
I'm not as quite as concerned as I was three weeks ago, and that's simply because the markets are starting to move. The arb is closed completely from Europe. The arb is closed 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. 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 last night a draw. That has to be watched closely. Basically, we just came out of a negative crack environment yesterday in New York Harbor. We're a whopping $0.50 positive crack.
We're watching it, and if the products, if gasoline goes into the tank, you don't make any money. 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 at 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. That's what we'll watch. I'm not quite as concerned on the gasoline side as I was three weeks ago. Frankly, distillate and IMO coming at us is again, a very positive for us. Erik, would you handle Roger's third question?
Sure. 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. 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. 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-$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 diffs? I know you guys run sort of a base load of like five 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 to 10 a day on occasion of Bakken into Toledo. Right now, that is not the crude of choice in Toledo because we can source the Canadian crudes, the Canadian Sweet, and Syncrude. 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 10,000-11,000 barrels a day of Bakken by rail into Delaware. 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. Obviously, there is no pipe takeaway constraint on Bakken.
You can get it with DAPL, get it down to the Gulf Coast of the U.S. 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. 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, and Bakken looks very attractive. The fact of the matter is, the Canadian heavies to our East Coast look even more attractive, orders of magnitude more attractive. We're constantly trying to maximize our access to barrels. These differentials exist for a reason, and that is because they're somewhat trapped. Rail is not unlimited. It's not simply how many rail cars 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. The Bakken looks good, and we'll take that where we can. The fact of the 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 were favorably early on in rail. These are not contracts you can get into. The supply chain, as he mentioned, you can't get in and get out in a day. You have to make some long-term commitments, and 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. I guess on PBFX, obviously, you guys know one of your competitors bought in their MLP. Just wondering, any thoughts around the value of PBFX as a standalone entity, and whether you would look to do something with the IDRs potentially soon or anything about improving the cost of capital there?
Yeah, I would say, as we've said in the past, we're constantly looking at the market. I guess I would say a 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. I would expect, while 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. It's a dynamic situation. 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.
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 gonna 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? If so, was there any hedging impact in the third quarter? I know you don't want to probably give too much in the way of numbers. In the past, you've said that. 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. Relatively de minimis in relation to the $331 million of EBITDA.
Okay. As you look at things now, are you considering future hedges, or was that more of a one-time situation?
I don't think that's something that we're going to address on 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. 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 project, in terms of CapEx?
We do not have final board approval for our 2019 capital spend. 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-$75 million on both the high and low side. Another couple of hundred million to $250 million of general maintenance, regulatory safety spend. Obviously we have some discrete projects that we've announced. We're going to spend, call it roughly $40 million for the hydrogen plant hookup at Delaware City. That's on our nickel. 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. We'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. 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 has corrected down to sub 28, which is typically a number that allows margins to improve. 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.
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 in that we are sourcing more of domestic crude, SJV crude, obviously some Canadian crude into Torrance than we have been when we first took over the facility. Our crude differentials on landed cost of crude is now several dollars under ANS, maybe $2 or $3 better than it's been historically, maybe in the last year. 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 in addition to it? My question is how much, broadly speaking, could we do on crude sourcing there, given, I think if I remember correctly, about 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. Just wanted to get your thoughts there.
Yeah, it's a good question. As I said, the president of the Western division is sitting in the room here, so he'll watch what I say. 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. Just as importantly, we've started gathering systems. We're bringing in small volumes of other valley crudes or California domestic crudes. 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 has given us a better landing cost to 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 look like they've been under pressure. We know what's happening on the East Coast as well with Northwest Europe, and this all ties into the gasoline situation. 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. Are you reading through any sort of run cuts maybe in Asia? 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 and the regional markets. Is that the right way?
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 arb 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 certainly don't have economics to run Brent-based crudes. 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. 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 are 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. The advantage that we have, of course, is yes, we have heavy crude, more complex refineries in the East Coast. With the crude differentials and the land, of course, the crude that we have coming in, we actually can make money as long as the diesel crack holds up. Those refiners that can't, I think will have to take steps to cut production, and that's the only way they're going to get the gasoline to rebound. I see that coming. We'll see what happens.
Do you see that on the West Coast as well? I think the East Coast market, you gave some great color there. Insofar as Asia puts pressure on the PADD 5 gas crack, do you see some of that stepping off? There had been.
Absolutely. 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. Then you will see the corresponding cuts. We may be headed for that as the high RVP season goes. If indeed, right now we've got pretty good gasoline inventories in PADD 5, if that starts to move up, most likely we'll see rate cuts.
Great. Thanks. Just one last sort of housekeeping question on Chalmette on the coker. I apologize, you guys have disclosed this previously, could you remind us sort of what the maybe IRR or the capital return hurdle on that coker is so we could sort of get a sense of how you're thinking about incremental cash flow on the restart?
Yeah. If you look at the coker, what I would describe as a mid-cycle environment, you're probably over $40 million of EBITDA. Like everything else, if you look at a post-IMO market, you're more than double that. One of the things that's extraordinary about this project is the fact that a year from today, it should be operational. 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 looks extraordinary in an IMO market.
All right, great. Thanks for the time, gentlemen. Appreciate it. I'll turn it over.
We'll take our next question from Paul Sankey with Mizuho. Please go ahead.
Morning, all. I hate to raise this, but there was reports on Reuters of an accident at Delaware City yesterday. Could you just update us on that?
Yeah, 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. So I'm not going to get into the specifics there. The reporting was wildly inaccurate yesterday. In regards to operations, there's 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's a knee-jerk or whatever response from Washington. I guess in the context of that, you're also committing to a coker project, which I assume has 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. Really, when you look at this, the politicians will do what the politicians do. 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 75% of the sulfur emissions from transportation fuel. 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 U.S. and other places in the world require a 0.1 sulfur in the ports as the ships come in, the ECA ports, and are concerned about whether or not this is too much, too fast. I think it's going to go, and I think it's going to go 2020.
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. In fact, that will likely be the case. This industry is well-known for figuring out how to respond to the market demands. 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.
That did influence us to a certain extent on the restart of the coker. As Matt said, that coker was shut down for reasons that were associated with the busted marriage of the joint venture. It shouldn't have been shut down. We are 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. 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. We're happy about that.
The fact that the coker is on the ground, it literally is a bird on the ground for us. Whatever the economics are for a new build coker, the economics associated with this project are twice as good because it comes at half the cost.
Yeah. 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 is doing a turnaround.
Right.
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. It's basically saying, okay, it was protected, it was under nitrogen, 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.
This really, Paul, this was 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. 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. 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. 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 an IMO. There's more talk of some refining assets coming into the market. 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's 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, of 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. That's an objective. We already have that in PADD 1. We are likely not going to get it in PADD 2 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. Therefore we go to PADD 3 into PADD 5, and they are strategic areas for us. We are looking, 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 tea kettle. They believe IMO is going to be an advantage for them. The bid asks are a bit wide. That being said, there are some things that we're focusing on or looking at because the strategy hasn't changed. I do think that IMO creates a wider bid ask and makes getting the deal done a little bit more problematic.
Yeah. No, that makes a lot of sense. Second question is a little bit more tactical. Tax rate, just in general, what 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. 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. Again, this goes to just geographic diversity of the system. We think on a longer term basis, our 27% guidance is pretty good guidance.
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. One of your predictions was that the situation could deteriorate. 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 a bottom and come back. If you look at Venezuela, their refinery utilization, I guess I saw a number last week, is down to 17%. 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. They're selling crude not because their production is up. They're selling crude because they're not consuming it. They turn around and they 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, they've got these debt calls coming in. The fact that they settled, quote, "with ConocoPhillips," it 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 of this gets settled, and I would hope that would be earlier, because the people of Venezuela frankly deserve better.
Yeah. Thanks, guys. Appreciate the time.
We'll go next to Matthew Blair with Tudor, Pickering, and Holt. Please go ahead. Your line's 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? 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 were looking at the optimization opportunities in Torrance now to the rest of our system with a primary emphasis on Chalmette. We've already seen some payouts on that. We're 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. That's really 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. 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 jet product, 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. That probably has maybe six months and may involve a little bit of capital, nothing big. There are very good opportunities, not to the extent that we saw in Torrance. Because Torrance was an isolated system. We could get into different markets, Arizona and Vegas, but probably about half of that.
There's a lot of opportunities yet to be coming in optimization at Chalmette.
It'll feather in over the next rolling four quarters. As Tom mentioned, we've achieved some of it. In many respects, it can be quick-hit 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 start seeing marked improvement in Chalmette.
Sounds good.
In terms of WCS by rail, it's a modest amount. We can get some down there, it's not in overly significant quantities.
Got it. In terms of modeling out 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? 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 on a daily basis. If you look before this latest move on differentials coming out of Canada, routinely, Syncrude would beat the Canadian Sweets. There's been times in the last quarter or the last six months where, in fact, that has inverted. We're going to run a significant amount of Syncrude and try to source in even more Sweets. 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 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. That's after the PADD 2 refineries come up. 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, 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 crack.
Thanks, guys.
Our next question comes from Doug Leggate with Bank of America Merrill Lynch. Please go ahead.
Hey, guys. Good morning. This is Kaleon for Doug. I've got an IMO question. Let's say that 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? What I'm hoping that you'll 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, we make about $500,000-$600,000 a day of gasoline and distillate together out of our system. You can assume that we can swing the volumes 10% between the pool. If we go to a max distillate, by the way, we are at max distillate pretty much everywhere, maybe not there yet. We're probably there even in California because of these wide margins. We're in a max distillate mode. In the forecast or 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. If demand doesn't crater, ultimately that max distillate, as you get into the gasoline season, is going to be a factor, right?
As we move into April or March of next year, pretty much everybody goes into full gasoline mode in anticipation of the driving season. If you don't do that because you have such good margins on diesel, you're likely going to have a shortage in gasoline unless demand craters. That's one scenario, and that's why many people in IMO think that the gas crack's going to go up, not to the extent that 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 the equation 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?" I made the point before.
We can take a valve and shut it on the material coming off of the Torrance high-pressure hydrotreater and turn 105,000 barrels a day of cat feed into compliant fuel, a 0.5 fuel. We're not going to do that, but everybody who has a high-pressure hydrotreater has that knob to turn now. 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 onto a cat cracker." Especially if you don't have really good gasoline margins, and you'll make the compliant fuel coming off the hydrotreater. There's lots of different knobs that the refiners have. In our system because of our complexity, we have more knobs than most.
A lot of moving parts, guys. Really appreciate the insight. That's all I had. I'll leave it there.
Our next question's from Roger Read with Wells Fargo. Please go ahead.
Okay. I'm sorry, guys. My question's 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 will take it offline. Tom, have you guys talked about how much is the volume that you're railing in Q3, both Bakken and WCS into the Northeast market and what you expect in Q4? More importantly is that, how much more that you think you can ramp it up yet? Look like both Bakken, recently that has been not able to clear the market, means that the well capacity is not sufficient to clear yet. Is that what you're seeing? 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're going to run 65,000-70,000 barrels a day of WCS in by rail into the East Coast, and that's our plan going forward with the differentials that we see. The limitations on takeaway capacity, as you're well aware, they're not going to be overcome in the near term. It's going to take several years. 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 8,000-10,000 barrels a day WCS into Torrance. The Bakken is more of an interesting one.
With DAPL, I've always was surprised that Bakken was so tight in terms of its market price to TI because you got to transport it down to the Gulf Coast in the U.S. and pay all these tariffs, but that was sunk cost. Certainly, Bakken has moved out significantly. We are railing some Bakken in, 10,000-12,000 barrels a day. 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, wherever. You got to have the rail cars, 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's no doubt about that.
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's trading $3 under Brent. You're out of the money. We've been down that path before. We're not going to do that.
Tom, just curious that, is the rail operator this time around, they are really resisting to ramp up the capacity if you don't sign any long-term contract?
Yes.
In the past, it seems like that is a little bit easier there for that discussion.
Yeah, I think that's exactly the point, Paul. Maybe the first time around, it was incremental business to them. "Yeah, okay. We'll do this." 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 arb. Fortunately for us, with what we've done, we were in early, and we've got our contracts in place for what we're doing. 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, 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. We're doing that successfully, and we'll trim around the edges on when we can on sourcing more crude. 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 contracts that are three, four, five years with the rail, with the loading facilities, 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 mean that your WCS volume is under long-term contract?
We have it termed up for. Not all of it. We continue to go out into the hinterlands and look for crude. Yeah, part of this thing is making. We don't want to go in there and have all these rail cars, then find out we can't buy the crude. 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 rail cars to be able to move the barrels and unit trains. Of course, we have our unloading facilities. 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 Alberta into the Northeast? Also, what is the 10, 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. 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, there are different load ports that will. Not ports, but places, $16-$18. Really nothing's changed in the Bakken. It's $10-$12 to get the Bakken in.
If you really want to do much more than the 10,000 to 12,000, I suppose that the $10 to $12 is not going to cut it. That's why you're not doing it.
That's correct. We'd have to go out and enter into new leases on rail cars and to get more loading space, and we would not to be able to replicate that at a $10 to $12.
Any kind of rough idea how much is that today if you want to ramp it up?
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. We're not ready to do that because we don't think that Bakken by rail has got the longevity that WCS has.
I see. Thank you.
It does appear we have no further questions. I will 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. Everybody have a great day.
This will conclude today's program. Thanks for your participation. You may now disconnect.