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PBF Energy Inc (PBF -0.61%)
Q3Â 2018 Earnings Conference Call
Oct. 31, 2018, 8:30 a.m. ET
Contents:
- Prepared Remarks
- Questions and Answers
- Call Participants
Prepared Remarks:
Operator
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.
(Operator Instructions). Please note this call is being recorded. It's now my pleasure to turn the floor over to Colin Murray of Investor Relations. Sir, you may begin.
Colin Murray -- Head Of IR
Thank you, Keith. Good morning and welcome to today's call. With me today are Tom Nimbley, our CEO; Matt Lucey, our President; Erik Young, our CFO and several other members of our management team. A copy of today's earnings release including supplemental information and guidance is available on our website. Before getting started, I'd like to direct your attention to the safe harbor statement contained in today's press release.
In summary, it outlines that statements contained in the press release and on this call which express the company's or management's expectations or predictions of the future are forward-looking statements intended to be covered by the Safe Harbor provisions under federal securities laws.
There are many factors that could cause actual results to differ from our expectations including those we described in our filings with the SEC. Consistent with our prior quarters, we will discuss our quarterly results excluding a 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.
Matthew C. Lucey -- President
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 operation's 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 in the West Coast did improve over the course of the quarter. Going through each of the assets and staying on the West Coast, Torrance continues to perform well, reliability was good.
Operating expenses were up this quarter as a result of particularly high natural gas cost on the West Coast. Normalizing for the natural gas prices, our refinery operating expenses 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 the 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 aromatics units set for late November.
With that, I'll turn the call over to Erik.
C. Erik Young -- Chief Financial Officer, Senior Vice President
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 to $175 million range as compared to our 2017 expense of approximately $300 million.
Consolidated CapEx for the quarter excluding acquisitions was approximately $103 million which includes $82 million for refining and corporate CapEx and $21 million incurred by PBF Logistics.
During the quarter, we generated approximately $412 million of cash, including $267 million from operations. This resulted in quarter ending liquidity of more than $2.2 billion and in excess of $1 billion of cash. Importantly, our consolidated net debt-to-capitalization was 24%.
Lastly, we are pleased to announce that our Board has approved a quarterly dividend of $0.30 per share. Also of note, today, PBF Logistics announced its 16th consecutive quarterly distribution increase and provided additional details on its growth plans.
I encourage you to listen to their earnings call later this morning. Now, I will turn the call over to Tom.
Thomas J. Nimbley -- Chairman of the Board, Chief Executive Officer
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 remained 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 (inaudible) effects which should benefit our entire system.
Looking ahead, we believe our high complexity refining system is well prepared for the upcoming Marine diesel fuel standard shift with IMO 2020.
As we have said in the past, PBF has more coking capacity on a percentage of throughput than all, but one other independent refiner. In the past month, we've seen a bit of turmoil in the refinery -- refining equities as a result of posturing around the implementation of the impending standards.
Following their meetings last week, the IMO affirmed both the time line for implementation of the new standards and the carriage ban on high sulfur fuel oil. Despite recent speculations surrounding IMO 2020, out-year differentials for both high sulfur feedstocks and high-value distillates remains robust and relatively unchanged.
Our strategy in this environment as always, is to put our assets into position to succeed by running them well and in a safe, reliable and environmentally responsible manner. By executing this very disciplined strategy, our assets will be profitable and our employees and shareholders will benefit.
Operator, we've completed our opening remarks and will be pleased to take any questions.
Questions and Answers:
Operator
And in a moment, we will open the call to questions. (Operator Instructions). Our first question comes from Roger Read with Wells Fargo. Please go ahead, your line is open.
Roger D. Read -- Wells Fargo Securities LLC -- Analyst
Okay, thanks. Good morning and solid quarter there guys. Just to jump in here. I guess two things that really stand out. Crude differentials and if you could kind of give us an idea of what the railcar cancellation was given the crude does seem favorable and you'd want more rather than last railcars, so may be 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 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?
Thomas J. Nimbley -- Chairman of the Board, Chief Executive Officer
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 the 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 -- (Technical Difficulty) had a contingent spread into Syncrude. Obviously, Toledo --
Roger D. Read -- Wells Fargo Securities LLC -- Analyst
Tom, excuse me. Real quick there. I don't know if it had happened to everybody else, but you went totally blank there for about the first part of your answer.
Thomas J. Nimbley -- Chairman of the Board, Chief Executive Officer
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?
Roger D. Read -- Wells Fargo Securities LLC -- Analyst
Yes, absolutely, thanks.
Thomas J. Nimbley -- Chairman of the Board, Chief Executive Officer
Alright. They obviously were a massive tailwind for us. They were exacerbated -- those spreads were exacerbated by high level of turnaround activity in PADD 2 in the quarter which is continuing and they were likely now our income (ph), but they are underpinned by the lack of takeaway capacity coming out of Canada and that is not just WCS, it is now spread because of some shipping and sourcing of crudes to Syncrude.
So we expect that we did benefit, we had a very good quarter in Toledo, we were able to capture all of that because we ran well, we expect that to be the case going forward, perhaps not at the differentials we see now, when a BP widening comes back up and turn around at the either mid or end of the month, but they will stay wide and we expect to be able to benefit from them.
And frankly, we're seeing those advantages in Delaware in a big way and Erik will talk about the rationale behind the railcars, but we are running as Matt says, we ran notionally 70,000 barrels a day of heavy Canadian crude in Delaware, that is a big event 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 railing crude into the East Coast and being the money (ph) for probably the next several years. And let me take the gasoline distillate though, we too are as I mentioned are looking at the gasoline inventories, they're always cost concerned, 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 office closed completely from Europe, the office closed in the Gulf coast, there will be barrels moving up, but the Gulf coast is going to have massive incentive to move barrels into the export market and not up to New York harbor, and we're seeing evidence of runs cuts in Europe, we had a gasoline draw last week, I don't particularly put any stock in the APIs, but the APIs indicated, yes, last night (ph), a draw.
But that has to be watched closely there is no doubt that the gasoline, but basically, we just came out of a negative crack environment yesterday in New York harbor where -- of a whopping $0.50 positive crack. So we're watching it, and if the products, if gasoline goes into the tank, you don't make any money.
So if that's the case, then I think the industry really has to take that in hand and make cuts if necessary, I said to you before, you will never hear us say at PBF that we're going to run a 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 out is again a very positive for us.
Erik would you handle Roger's third question?
C. Erik Young -- Chief Financial Officer, Senior Vice President
Sure. So Roger, I think the answer on the railcar fleet is relatively straightforward, while we absolutely want to continue to increase barrels coming in via rail, 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 railcar leased fleet, we decided that probably taking a portion of those that weren't really being utilized in crude service and didn't have an alternative use for us, it was better to go ahead and terminate those leases early.
As a result you will see we took a $44 million, $45 million charge for the quarter.
Roger D. Read -- Wells Fargo Securities LLC -- Analyst
Alright, I appreciate it. Thank you.
Operator
We'll take our next question from Brad Heffern with RBC Capital Markets. Please go ahead.
Brad Heffern -- RBC Capital Markets -- Analyst
Hey, good morning everyone. Just as a sort of follow-up to the last question. Can you give your thoughts on Bakken (inaudible), and I know you guys were in sort of a base load of like 5,000 barrels to 10,000 barrels a day at Bakken, but is there any desire to ramp that up overtime?
Thomas J. Nimbley -- Chairman of the Board, Chief Executive Officer
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 five to 10 a day on occasion of Bakken into Toledo.
Right now that is not -- it's crude of choice in Toledo because we can source the Canadian crudes, the Canadian sweets 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 or 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, you obviously -- there is no tight takeaway constrained on Bakken. You can get it now, (inaudible) get it down to the Gulf coast in the United States.
So these wide spreads, I think, perhaps might be impacted by the fact that there is so much capacity offline in the Midwest we'll see. And obviously the third --
Matthew C. Lucey -- President
I'll just make a comment with regards to the Bakken. Clearly we're trying to run the most economic barrels we can and Bakken looks very attractive, but the fact of the matter is the Canadian heavy 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 unloaded it, but the Bakken looks good and we'll take that where we can, but the fact of matter is, the Canadian heavy look that much better and so we're certainly maximizing that.
Thomas J. Nimbley -- Chairman of the Board, Chief Executive Officer
I'll just make one point adding to what Matt said is, we've been down this path for many, many years. We are early on and we're favorably early on in rail, but these are not contracts you can get into, the supply chain as you mentioned, you can't get in and get out the day.
You have to make some long-term commitments and we be -- we are focusing on WCS because we feel like we've got a longer runway on how long those differentials 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 and to the East Coast and then have the differential compress that would be a mistake that we simply are not going to make.
Brad Heffern -- RBC Capital Markets -- Analyst
Okay, appreciate all the color. And then, I guess on the PBFX, you know, obviously you guys know one of your competitors bought in their MLP, so just wondering any thoughts around the value of PBFX as a stand-alone entity, and whether you would look to do something with the IRs (ph) potentially sooner or anything about improving the cost of capital there?
Matthew C. Lucey -- President
Yeah. I would say as we said in the past we're constantly looking at the market, I guess, I'd say a little bit more in terms of, we appreciate obviously what the rail 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, 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, so it's 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.
Brad Heffern -- RBC Capital Markets -- Analyst
Okay, I'll turn it back, thanks.
Operator
Our next question comes from Phil Gresh with J.P. Morgan. Please go ahead.
Phil Gresh -- J.P. Morgan -- Analyst
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, I know the hedge is 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?
C. Erik Young -- Chief Financial Officer, Senior Vice President
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 is 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.
Phil Gresh -- J.P. Morgan -- Analyst
Okay. And as you look at things now, are you considering future hedges, or was that more of a one-time situation?
C. Erik Young -- Chief Financial Officer, Senior Vice President
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 being getting into what we are going to do I think is not the right answer.
Phil Gresh -- J.P. Morgan -- Analyst
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?
C. Erik Young -- Chief Financial Officer, Senior Vice President
We do not have final board approval for our 2019 capital spend, but directionally what we would say is we're probably going to have order of magnitude every year given the 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.
Phil Gresh -- J.P. Morgan -- Analyst
Okay. Great. Last question for Tom. Just your thoughts on the West Coast, we have obviously seen the cracks fade here, it tends to happen seasonally around this time of the year of course, but I noticed that your guidance for utilization is quite high for the fourth quarter, so did you have a strong view on the cracks out there?
Thomas J. Nimbley -- Chairman of the Board, Chief Executive Officer
Well, we'll watch the California crack as we will the whole system, the cracks in the summer as we talked about were actually seasonally low. We had inventories approaching 30 million barrels of gasoline, that's a number that's too high for PADD 5. That is corrected down to sub 28, which is typically a number that allows margins to improve and we actually have seen that in the -- during the third quarter, certainly in the month of September and October, the cracks have been relatively good although gasoline is coming off now as we've had the change in the RVP season.
But one other thing to think about in California, we have a tailwind at least for the moment that we have not had for some time and it's really had a knock-off effect of what's going on in crudes, and that we are sourcing more of domestic crude, SJV crude, obviously some Canadian crude into Torrance than we had been when we first took over the facility.
And our crude differentials, our lending cost of crude is now several dollars under ANS maybe $2 or $3 better than it has been historically, may be 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 into 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.
Phil Gresh -- J.P. Morgan -- Analyst
Thanks Tom.
Operator
Our next question comes from Prashant Rao with Citigroup. Please go ahead.
Prashant Rao -- Citigroup -- Analyst
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, those assets 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 can we do on crude sourcing given that I think if I remember correctly about half of your crudes are non-local California heavy there, and those discounts have been widening versus the NS (ph) Q-o-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?
Thomas J. Nimbley -- Chairman of the Board, Chief Executive Officer
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 will 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 it's going to be limited by the supply chain there.
But just as importantly, we've started gathering systems, we're bringing in small volumes of other valley crudes or California domestic crudes, and what we're doing with that is backing out less attractive waterborne crudes and that has helped us, in addition to the fact that the midway ANS diff (ph) has widened out, the crude-sourcing we're doing is giving us a better lend in cost of crude in Torrance than we've seen in some time.
Prashant Rao -- Citigroup -- Analyst
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 it's happening on the East Coast as well with Northwest Europe and this all ties into the gasoline situation.
But, Tom to sort of may be 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 in general (ph).
Is that, are you reading through any sort of run cuts maybe in Asia and then may be 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 a right way, and sort of to get your thoughts around the timing around how those, how that interplay works would be great.
Thomas J. Nimbley -- Chairman of the Board, Chief Executive Officer
Okay, it is exactly the point. The fact is, as I said, the office completely closed from Europe, I think the 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 crude, this is a -- and I'll get to the point, this is really a problem for a 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 a too much of a problem even with the gas prices that are sitting in the Gulf coast, but if you are 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 an European refiner and you're running a 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 and more complex refineries in the East Coast. So with the crude differentials and the lend in cost of crude that we have coming in, we actually can make money as long as the diesel frac holds up, but 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, and so -- I see that coming.
Prashant Rao -- Citigroup -- Analyst
Do you see that on the West Coast as well? I'm sort of, I think the East Coast market, you gave a very decent, great color there, but as far, and so far as Asia puts pressure on the PADD 5 gas crack, do you see some of that stepping off, because they have been --
Thomas J. Nimbley -- Chairman of the Board, Chief Executive Officer
Yes. Absolutely. And in fact part of what happened is, I think Matt mentioned the imports into PADD 5 had an impact on the inventories, and therefore, an impact on the cracks and then you will see the corresponding cuts -- and we may be headed for that as the high RVP season goes, but if indeed right now we got a pretty good gasoline inventories in PADD 5, but if that starts to move up, we'll see -- most likely we'll see rate cuts.
Prashant Rao -- Citigroup -- Analyst
Great. Thanks. And then 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 -- may be the IRR or the capital return hurdle on that coker is, so that we can sort of get a sense of how you're thinking about the incremental cash flow on the restart?
Matthew C. Lucey -- President
Yes. If you look at the coker in what I would describe is a midcycle environment, you're probably over $40 million of EBITDA, but like everything else, if you look at the post-IMO market, you're more than double that. And so, one of the things that's extraordinary about this project is the fact that a year from today should be operational, so whatever your views are 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 IMO market.
Prashant Rao -- Citigroup -- Analyst
Alright, great. Thanks for the time, gentlemen. Appreciate it. Turn it over.
Operator
We'll take our next question from Paul Sankey with Mizuho. Please go ahead.
Paul Sankey -- Mizuho Securities -- Analyst
Good morning all. I had some (ph) raises, but there was reports on Reuters as an accident in Delaware city yesterday, could you just update us on that?
Matthew C. Lucey -- President
Yeah, Paul, normally quite frankly we wouldn't, except there was some extraordinary misreporting, and so we feel someone obligated. There was no explosion at Delaware City. There were unfortunately some contractor injuries yesterday while they were performing routine maintenance. There is no disruption to our plant or our operations, I'm not going to get into the specific injuries with the specific people obviously, we have the highest concern and the highest care going for the individuals, and so I'm not going to get into the specifics there, but the reporting was well being inaccurate yesterday, and in regards to operations there is no impact to our operations.
Paul Sankey -- Mizuho Securities -- Analyst
Understood. Thank you, Matt. The potential impacts I think we're looking at with IMO, I guess the concern of the market is the prices are driven so high that there is a need (ph) 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 is not tenable for the IMO not to be put through or rather than the market doesn't react to the point where it becomes sort of a crisis.
Thomas J. Nimbley -- Chairman of the Board, Chief Executive Officer
I personally think the IMO is going to stay the course, and really when you look at this, there is -- 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 maybe you know, 75% of the sulfur emissions from transportation 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 of interesting that the United States and other places in the world require 0.1% sulfur in the ports as the ships come in, the echo ports and they're 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 man through is going to help with compliance. There will be some market moves associated with this, I think we expect to see the diesel price go up and we expect to see heavy fuel oil pricing go down, therefore the clean, dirty spread goes up and that's the incentive to coke.
And in fact that will likely be the case. But this industry is well known for figuring out how to respond to the market demands and my own view is this will be a finite opportunity particularly on the distillate side. I think it will have more legs on the crude differentials because sulfur is again now the enemy and the longer-term sweet sour spreads on crude oils might stay wider by $1 or $2 a barrel.
And that did influence us to a certain extent on the restart of the coker, but 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 shutdown. We're contemplating starting it up, it's a good project in a non-IMO world and it's a terrific project with a $40 or $50 clean dirty spread, and if that goes away and returns to normal if there is an upside on crude differentials of $1 or $2, it's somewhere between a good and a great project.
We're happy about that.
Matthew C. Lucey -- President
The fact the cokers is on the ground, it's -- there is always a bird on the ground for us and whenever the economic are for a new build coker, the economics associated with this project are twice as good because it comes at half the cost.
Thomas J. Nimbley -- Chairman of the Board, Chief Executive Officer
Yes. It's important to note Paul that when we say it's $110 million and it is $110 million, but basically $72 million of that $110 million is doing a turnaround. So there is another $20 million $25 million of additional safety enhancements that we're doing since the units has been down to make it safer, but it's basically saying, OK it was protected, it was under nitrogen, but they shut it down to avoid doing the turnaround for us to start it up we have to do the turnaround and it's almost maintenance.
Matthew C. Lucey -- President
This really , Paul, this is one the key pieces that was attractive around the Chalmette acquisition for us a few years ago as we had a handful of idled units that were there, that were taken down very carefully. However the prior ownership group elected not to essentially do turnaround work. So for the long-term viability and flexibility of the Chalmette refinery, this is a great project that will allow us a lot more optionality and flexibility on crude and feed stock sourcing going forward.
Paul Sankey -- Mizuho Securities -- Analyst
Great. Thanks guys.
Operator
We'll take our next question from Neil Mehta with Goldman Sachs. Please go ahead.
Neil Mehta -- Goldman Sachs -- Analyst
Hey guys, thanks for taking the question. So first question 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.
So just your thoughts on Bid/Ask, I would imagine it's one of the factors that's really challenging around valuing assets in any transaction is how to price an IMO, but there's more talk of some refining assets coming into the market.
So just curious on your first hand perspective around the M&A markets for refining, and where you guys see yourselves in terms of your involvement around that?
Thomas J. Nimbley -- Chairman of the Board, Chief Executive Officer
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 real house in terms of taking the asset, growing the business, we've been on a 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 the insurance to be honest if you have that, so that's an objective we already have that in PADD 1.
We will likely not go in to get it to your point on Bid/Ask, I think base case with the Canadian situation and then IMO it would be hard to get a deal done. Now, so therefore we go to PADD 3 and to PADD 5 and they are some strategic areas for us. We're 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 advantage because of IMO.
That could be heavy refinery, a complex refinery, it could be a key cater (ph) 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're focusing on or looking at because the strategy hasn't changed, but I do think that IMO creates a wider Bid/Ask and makes it getting the deal done a little bit more problematic.
Neil Mehta -- Goldman Sachs -- Analyst
Yes. Now that makes a lot of sense. And second question is more -- 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 is -- could the number be a little lower than that?
Matthew C. Lucey -- President
No. 27% is probably right long-term number. Quite frankly during this past quarter it simply comes down to state tax, a portion went in, 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.
Neil Mehta -- Goldman Sachs -- Analyst
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 Venezuela in barrels but it certainly had an impact on the way we think about the light heavy in the Gulf Coast?
Thomas J. Nimbley -- Chairman of the Board, Chief Executive Officer
I think if we were having the panel today I would 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 US 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 turnaround and they sell the crude and then they have to buy the products in order to get the products consumption to fit demand in the country. I think that what they've got -- what they've got to do, I didn't really what they have do, but the reality is, they've got these dead calls coming in, the fact that they settled court 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 package. 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.
Neil Mehta -- Goldman Sachs -- Analyst
Thanks guys. Appreciate the time.
Operator
We'll go next to Matthew Blair with Tudor, Pickering and Holt. Please go ahead, your line is open.
Matthew Blair -- Tudor, Pickering, Holt & Co. -- Analyst
Hey good morning guys. You mentioned that Chalmette is 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?
Thomas J. Nimbley -- Chairman of the Board, Chief Executive Officer
Let me take the first piece. The optimization effort, I think we admitted that, the focus initially was clearly on Torrance and we had a massive effort there. And that's a priority. That effort is not completely done in 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, and 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 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 with some additional crude-sourcing and that's a big area especially given what's going on in Venezuela.
But one of the things that we really look at in Chalmette is it has a relatively low life product yield and there is a couple of opportunities that we're looking at to increase jet -- to get back into the jet business and to increase the production of ULSD out of lifecycle oil.
That is going to take some time, I guess, 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. Of course, Torrance was an isolated system, and we can get into different markets Arizona and Vegas, but probably about half of that.
So there is a lot of opportunities that are yet to be coming in optimization at Chalmette.
Matthew Blair -- Tudor, Pickering, Holt & Co. -- Analyst
It will feather in over the next rolling four quarters. As Tom mentioned we've achieved some of it, it's in -- in any respects can be quick pick 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 will see, start seeing marked improvement in Chalmette.
Sounds good. And then --
C. Erik Young -- Chief Financial Officer, Senior Vice President
In terms of WCS by rail, it's a modest amount. We can get some done there but it's not in overly significant quantities.
Matthew Blair -- Tudor, Pickering, Holt & Co. -- Analyst
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 may be 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?
Thomas J. Nimbley -- Chairman of the Board, Chief Executive Officer
Actually, the last part of your question is if we look at Canadian license Syncrude on a fairly basis, if you look before this latest move on differentials coming out of Canada, routinely Syncrude would be the Canadian sweets.
Now there has been times in the last quarter or last six months where in fact that is in verdict, but we still run we're going to run a significant amount of Syncrude and try to source an even more sweets.
I think, so there is no real change in what the raw material mix is going to be going forward. I think the reality is there is -- the difficulty in sourcing in crude because of some of the things that are going on in Canada, prorations on the pipe has got us to where -- we didn't anticipate being as wide as we were, we programmed in that we're going to run Toledo full assuming that it runs as well as it can, but that's after the PADD 2 refineries come up, then Toledo is likely going to go what the Midwest market does all the time which is when you don't need imports from PADD 2 and you're self-sufficient on your products, you're turn crude (inaudible) products over hang.
If that's the case then that we would normally run 140 or 145 in Toledo, if it isn't we'll try to source more crude and take care of the -- take the opportunity to get more out of the crack.
Matthew Blair -- Tudor, Pickering, Holt & Co. -- Analyst
Thanks guys.
Operator
Our next question comes from Doug Leggate with Bank of America Merrill Lynch. Please go ahead.
Clay -- Bank of America Merrill Lynch. -- Analyst
Hey, guys. Good morning. This is Clay (ph) 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 win, Marine bunker cracks are ripping. What is the ability of your system to minimize gasoline and maximize other products?
And what I'm hoping that you will talk about is the flexibility of your cat (ph) feed, and how does this all tie into your view of 2020 margins?
Thomas J. Nimbley -- Chairman of the Board, Chief Executive Officer
Okay, the last piece of the question, I'm sorry you said real of what feed? Oh, Cat feed, OK, good. First of all the simple answer to -- we make about 500,000, 600,000 barrels a day of gasoline distillate together, out of our system and you can assume that we can swing the volumes 10% between the pool.
So if you go to a max distillate, by the way we're at max distillate pretty much everywhere maybe not there yet, we've probably (ph) there even in California because of these wide margins. So we're in the max distillate mode. And in the forecast that 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 doesn't greater (ph), ultimately that max distillate as you get into the gasoline season is going to be a factor, because you won't be removed into April or March of next year pretty much everybody goes into full gasoline mode in anticipation of the driving season.
And if you don't do that because you have such good margins on diesel, well, then you're likely to going to have a shortage in gasoline and less demand in craters. That's one scenario and that's why many people in IMO think that gasoline prices are going -- the gas crack is 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 distillate.
So the other part of the equation is, this is real, with the 3 million barrels a day of increase demand for a low sulfur fuel oil or ultra low sulfur fuel oil or whatever, people say how you're going to be able to do that, make that while I made the point before, we can take a valve and shut it on the material coming off the Torrance high-pressure, high hydrotreater, and carrying a 105,000 barrels a day of cat feed, into complaint fuel of 0.5 fuel, and we're not going to go do that, but everybody who has a high-pressure hydrotreater has that knob to turn now.
And you might well see people say, hey if the price of the low sulfur fuel oil -- the 0.5 fuel oil comes up high enough, that you'll go ahead and sure runs on to a cat (inaudible) especially you have -- don't have really good gasoline margins and you will make the compliant fuel coming of the hydrotreater, so there's a lots of different knobs that the refiners have in our system because of our complexity we have more knobs than most.
Clay -- Bank of America Merrill Lynch. -- Analyst
Lot of moving parts, guys. Really appreciate the insight. That's all I had, I'll leave it there.
Operator
Next question is from Roger Read with Wells Fargo. Please go ahead.
Roger D. Read -- Wells Fargo Securities LLC -- Analyst
I'm sorry guys. My questions have been answered. I appreciate it.
Matthew C. Lucey -- President
Okay. Thanks Roger.
Roger D. Read -- Wells Fargo Securities LLC -- Analyst
We'll go next to Paul Cheng with Barclays. Please go ahead.
Paul Cheng -- Barclays -- Analyst
Hey guys, good morning. I have to apologize first, because I come in late, so you have already addressed it, so I would take it offline. Tom have you guys talked about that, how much is the warning that you're routing 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 (inaudible) both Bakken recently that has been not able to clear the market means their rail capacity is not sufficient to create it. Is that what you've seen? And if that's the case how quickly we can ramp up those capacity?
Thomas J. Nimbley -- Chairman of the Board, Chief Executive Officer
Matt talked to that briefly, but let me just reinforce it Paul. We ran -- we're going to run 65,000, 70,000 barrels a day at 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 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 in more of an interesting one, it really would dapple, I'm always surprised that Bakken was so tight in terms of market price to TI, because you got to transport it down to the Gulf Coast and The United States and pay all these tariffs, but that was on cost.
It appears -- certainly Bakken has moved out significantly. We are railing some Bakken in 10,000, 12,000 barrels a day, and we'll try to do incrementally more, but we are not going to enter into long-term contracts which is really what you need to do on a supply chain, as you know you got to have to load space in some place in either Canada or in North Dakota or wherever. You've got to have the rail cars, you have to have the contracts with the rails and then you got to get to your unloading area.
We have the unloading area, there is no doubt about that, but we will be reluctant to enter into a long-term commitment going out 3 years or 4 years to move 40,000 barrels a day at 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 straightened to relapse under Brent and you (inaudible) money, and we've been on that path before, we're not going to do that.
Paul Cheng -- Barclays -- Analyst
Tom, just curious that is the rail operator this time around they're really resisting to ramp up the capacity if you don't sign any long-term contract, because in the past, you said that it's a little bit easier for that discussion?
Thomas J. Nimbley -- Chairman of the Board, Chief Executive Officer
Yes. I think that's exactly the point, Paul. Maybe the first time around it was incremental business to, OK we'll do this, and then now it's a big business. And if they're going go ahead and make the commitments put on more engines, more crude, more staff, to go ahead and change 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 art.
And unfortunately for us with what we've done, we're in early and we've got our contracts in place to what we're doing, but if you want to go out and do significantly more you're going to have to pay up for that. We sat and talked about this, ad nauseam, and our view was let's focus on where the biggest name for the buck is and that is WCS crude out of Canada to our system and that we're doing that successfully, and we've had trim around the edges on when we can on sourcing more crude, but if you want to do something big like we were doing before when we were railing in 100,000 barrels a day of Bakken into Delaware City, you're going to add that to your contracts, 3, 4, 5 years with the rail, with the loading facilities and the NVCs on that, you're going to be prohibitive and just not ready to take that leap on something like Bakken.
Paul Cheng -- Barclays -- Analyst
Tom, does that mean that your WCS volume is under long-term contract?
Thomas J. Nimbley -- Chairman of the Board, Chief Executive Officer
We have it termed up for not all of it but we continue to go out and (inaudible) and look for crudes, but yeah, part of it, we don't want to go in there and have all these railcars and find out we can't buy the crude. So we've termed up or we've got deals in place to source the barrels, we've got deals in place to load the barrels. We have the railcars to be able to move the barrels in unit trains and of course we have our unloading facilities.
So on a WCS side for the near future we're in good shape.
Paul Cheng -- Barclays -- Analyst
Can you share with us that what is your cost (inaudible) to move Alberta into those Northeast? And also that what is the 10,000, 12,000 barrel per day currently you're moving Bakken, what's the cost?
Thomas J. Nimbley -- Chairman of the Board, Chief Executive Officer
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. It's different load ports -- 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.
Paul Cheng -- Barclays -- Analyst
But that if you really want to do much more than the 10,000 to 12,000, I suppose that $10 to $12 is not going to cut it, that's why you're not doing it?
Thomas J. Nimbley -- Chairman of the Board, Chief Executive Officer
That's correct. We'd have to go out and enter into new leases on railcars and get more loading space and we will not be able to replicate that $10 to $12.
Paul Cheng -- Barclays -- Analyst
How much of is that today if you want to round it up?
Thomas J. Nimbley -- Chairman of the Board, Chief Executive Officer
Actually the biggest issue Paul is that, you could probably get it done but you would have to commit to do it for five years, and we're not ready to do that because we don't think that the Bakken by rail has got the longevity that Bakken by -- or WCS has.
Paul Cheng -- Barclays -- Analyst
I see, thank you.
Operator
And it does appear we have no further questions. I'll return the floor to Tom Nimbley for closing remarks.
Thomas J. Nimbley -- Chairman of the Board, Chief Executive Officer
Well, thank you everybody for attending the call. We had a good quarter, and we hopefully will look forward to the next call when we can give good results. Thank you and everybody have a great day.
Operator
And this will conclude today's program. Thanks for your participation. You may now disconnect.
Duration: 60 minutes
Call participants:
Colin Murray -- Head Of IR
Matthew C. Lucey -- President
C. Erik Young -- Chief Financial Officer, Senior Vice President
Thomas J. Nimbley -- Chairman of the Board, Chief Executive Officer
Roger D. Read -- Wells Fargo Securities LLC -- Analyst
Brad Heffern -- RBC Capital Markets -- Analyst
Phil Gresh -- J.P. Morgan -- Analyst
Prashant Rao -- Citigroup -- Analyst
Paul Sankey -- Mizuho Securities -- Analyst
Neil Mehta -- Goldman Sachs -- Analyst
Matthew Blair -- Tudor, Pickering, Holt & Co. -- Analyst
Clay -- Bank of America Merrill Lynch. -- Analyst
Paul Cheng -- Barclays -- Analyst
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