PBF Energy Inc
NYSE:PBF
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PBF Energy Inc
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Good day, everyone, and welcome to the PBF Energy Fourth Quarter and Full Year 2017 Earnings Conference Call and Webcast. [Operator Instructions] Please note, today's conference may be recorded. It is now my pleasure to hand the floor over to Colin Murray of Investor Relations. Sir, you may begin.
Thank you, Erika. Good morning, and welcome to today's call. With me today are Tom Nimbley, our CEO; Erik Young, our CFO; and several other members of our management team. Copy of today's earnings release, including supplemental, financial and operating information, including throughput guidance for Q1 and the full year is available on our website.
Before getting started, I'd like to direct your attention to the forward-looking statement disclaimer 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 have described in our filings with the SEC.
Consistent with our prior quarters, we will discuss our quarterly results, excluding a noncash, lower-of-cost-or-market, or LCM, after-tax gain of approximately $119.3 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 Erik Young.
Thank you, Colin. In addition to the aforementioned LCM adjustment, we had 3 other one-time items that impacted our reported results. The Tax Cuts and Jobs Act provided a net tax benefit of $173.3 million, primarily related to the reduction in net deferred tax liability. We realized an after-tax net expense of $42.3 million related to the reduction in the TRA liability, and we recognized a $42.2 million after-tax unrealized derivative expense related to basis exposure for heavy Canadian crude that will be processed throughout 2018.
In discussing our fourth quarter and full year results, we will exclude the items related to LCM, the TRA and tax reform. For the fourth quarter, PBF reported income from operations of approximately $55.9 million and an adjusted fully converted net loss of $4.4 million or $0.04 per share on a fully exchanged, fully diluted basis. For the full year 2017, PBF reported income from operations of $434.7 million and an adjusted fully converted net income of $130.1 million or $1.14 per share, again on a fully exchanged, fully diluted basis.
For the quarter, our EBITDA comparable to consensus estimates was approximately $210 million. This figure excludes the impact of tax reform, changes to the TRA valuation, the LCM benefit and, again, the noncash unrealized $70 million derivative expense.
For the quarter, G&A expenses were $71.6 million. Depreciation and amortization expense was $82.8 million and interest expense was approximately $39.6 million. PBF's effective tax rate for the quarter was approximately 45.6%, which was impacted by the various adjustments related to tax reform.
In 2018, we expect to benefit from the Tax Cuts and Jobs Act and for modeling purposes, you should assume a new normalized tax rate of approximately 27%. This includes the new 21% federal rate plus various state taxes. Our RIN expense for the fourth quarter totaled $90.5 million. And for the full year 2017, our RIN expense totaled $293.7 million. We estimate that our 2018 RIN expense will be similar to 2017 at current pricing, but this could change materially depending on the actions taken by the EPA or Congress.
Total consolidated CapEx for the year was approximately $727 million, which includes $614 million for refining and corporate CapEx and $113 million incurred by PBF Logistics. We generated significant cash flow in the fourth quarter from both operations and working capital. As a result, we ended the year with liquidity of approximately $1.4 billion, including consolidated cash of $573 million and our consolidated net debt to capitalization was 35%.
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 13th consecutive quarterly distribution increase.
I'll now turn the call over to Tom.
Thank you, Erik, and good morning, everyone. PBF accomplished a lot in 2017. During the first 2 quarters of the year, we completed turnarounds at 3 of our 5 refineries, including the largest turnaround in our corporate history at the Torrance refinery. The improvements in strategic capital investments we completed across our refining system were critical to our operational success in the third and fourth quarters. As Erik mentioned, and as we highlighted in our press release this morning, there were several items from tax reform to derivative strategies, which were included in our fourth quarter financial results. But taken as a whole, we are pleased with our performance and the progress we have made. Overall, after completing turnarounds in 2017, our refineries ran well. Torrance performed very well since coming out of turnaround and has achieved the throughput levels we expected to see under our stewardship. The work to improve the facility is still ongoing. Beyond the physical improvements, our efforts to cultivate and reinvigorate the workforce had been evident in the increased reliability and consequently, the lower overall operating cost. Costs have come down on a nominal basis, and we are now seeing per barrel cost sub $7, which is what we expected to achieve when we acquired the plant. To put this in perspective, on a per barrel basis, this is over a 30% reduction in our average quarterly operating cost since we acquired the facility. We continue to see improved reliability and high throughput levels at our Chalmette refinery and are implementing practices to reduce operating expenses. There is a lot of upside remaining at Chalmette. And in the fourth quarter, we began to capture some of that opportunity. Last November, we completed the 625,000 barrel crude tank, and we've already begun to see the benefits it provides to Chalmette. The [ marriage ] costs have come down due to increased efficiency at our marine facilities. And more importantly, we have seen our product export capability almost double to over 50,000 barrels a day out of Chalmette.
During the latter part of 2017, global product inventory levels rebalanced, coming down from 5-year average highs to lows, which is indicative of continuing robust global demand. We expect to see a strong export market for clean products, especially to point south as it struggles with low refinery utilization and a solid demand outlook continue to draw our products to those markets. On the feedstock side, we will take advantage of any regional dislocations, such as what we are seeing with heavy Canadian differentials. We will continue to be opportunistic in pursuing other economic medium-to-heavy sour grades. While we will have routine turnarounds across our refining system in 2018, we feel that our assets are in position to benefit from favorable market conditions in the coming year. We expect to benefit from the tailwinds of tax reform, and we expect our employees to benefit from the tailwinds of tax reform. And looking further ahead, we believe our refining system is well prepared for the upcoming marine diesel fuel standard ship with IMO 2020. Pound-for-pound, PBF has as much coking capacity as any independent refiner, and we are looking at additional projects across our refining system that could potentially increase our advantage. We may even see some movement on the RFS, which could resolve a deeply flawed program that is plaguing merchant refiners. There is still a very active discussion involving parties on all sides, and let's just say this issue is still very much in play.
Operator, we've completed our opening remarks, and we would be pleased to take any questions.
[Operator Instructions] And your first question comes from Brad Heffern with RBC Capital Markets.
On the PBFX front, you guys announced a new 4-year plan there. I think $100 million in EBITDA. Can you talk about what some of those projects are? And then what the benefit potentially is to the refining system?
Absolutely. I think -- don't want to steal too much thunder from the PBF Logistics call at 11:00 a.m. Eastern Time today, but ultimately, these are all middle of the fairway projects, consistent with the drop-down inventory that exists at PBF. So it's a combination of pipelines and terminals and other -- excuse me, other assets that PBF today has sitting essentially at each of the refineries. So we've always talked about the ability for PBF Logistics to take advantage of the PBF Energy refining footprint, that geographic footprint. It all relates to crude and feedstocks coming in and products going out the back-end of the refineries.
Okay. I'll stay tuned for the PBFX call then. I guess, shifting to Torrance, it's seeming increasingly likely that the AQMD is going to have some sort of mitigation procedures that are required for the hydrofluoric acid use out there. Can you talk about where we are in that process? And maybe any thoughts about what the potential cost would be.
Well, we continue obviously to be very involved with the South Coast Air Quality Management District and all the stakeholders on this issue. Just as a backdrop, remember that HF is used in over 50% of the alkylation units in the United States. The Torrance alkylation unit has been in operation since 1966, with not even one off-site release of HF. Candidly or straightforward, Torrance may be the most advanced HF unit in the United States with the mitigation steps that have already been put in place. That being said, we've identified a number of other incremental steps that we have put in our budget that we will be implementing that will further mitigate any concerns, issues around MHF. The bottom line is, there's a lot of activity on this. Everybody is working together. All of the stakeholders are now working together. And we are optimistic that we actually will have a positive outcome.
And we will take our next question from Blake Fernandez with Howard Weil.
Question for you on WCS exposure, I guess, is the root of my question, but there's a couple of parts here. For one, I'm trying to understand, I guess, what your capability is to run WCS. But I guess, in connection with that, it sounds like there is a derivative loss. I'm trying to understand how much is actually hedged for 2018 where you actually have upside to the differential blowout.
I'll take the first part of the question. We ran, by the way, about 60,000 barrels a day of WCS in the fourth quarter. Bulk of that was being run at Delaware, but we also have the ability and have, in fact, run Canadian heavies at Chalmette and Torrance. And on a go-forward basis, we expect to continue to do that assuming the price differentials that we see today are anywhere near there stay in place. So -- and I might point out that part of the reason we're able to run that at those levels is to a certain extent we have been in the rail business continuously since 2012, '13, even when the economics weren't as pronounced as they are. We still had times that it was favorable, and we did bring in Canadian crudes. And we are a destination of choice in many ways, simply because we have a world-class rail facility that we installed at Delaware. And we can turn the cars quickly, which is very important to the rails and the other people, other parts of the supply chain. Now the second piece of the question, this is really simple. We didn't anticipate late summer when we had WCS at $12 or $13 onto Ti be in this position as all of a sudden that spread widened out as the production continued to come up in Canada and, of course, we had Keystone get shut down for a bit. But the bottom line here is, production has come up, and now we've reached the tipping point again where the barrel has to clear by rail. Pipes are full. And in doing that, we saw these spreads widen out pretty significantly. They continue to be wide at $30. And like to your point, all we simply did, we see an opportunity and we had to take advantage of that opportunity to lock in those basis differentials for 2018. I'm not going to say exactly how much we've locked in because that's competitive information, but you can see that by locking in the prices, as the differentials continue to widen out in the month of December that really contributed to the hedge loss, if you will, that we've talked about. And that will all come back when we clear the barrels and run the barrels in 2018.
Okay. Okay. Got it. Second question, it looks like you had a decent unwind of working capital here in the year-end and, I guess, my question is really around going forward into a turnaround season. If I recall, last year, the issue with cash depletion was really around the turnaround activity and the fact that you had some cost and, of course, the system was down. And so that was a big driver behind the recent cash balances were declining. I guess, what I'm asking is, do you think that's a likely scenario here as we head into spring turnarounds as well? Should we basically be looking for another, I guess, working capital build?
I definitely think there will be a working capital build throughout Q1 and into the early part of Q2, but we don't think it's going to be as material as it was in Q1 of 2017. I think we had talked about inventory build between $200 million and $250 million. We did, as you pointed out -- we got all of that back at the end of 2017. But you're going to have a bit of seasonality. I think we talked about that along with some of our peers, as you enter into Q1. We do have a fairly large turnaround cycle here at the end of Q1, beginning of Q2 primarily in Toledo and Chalmette. So ultimately, there will be a bit of a build, but we don't think it's going to be in the $200 million to $250 million range. It's probably going to be closer to half of that.
And we'll go next to Roger Read from Wells Fargo.
Well, the cash flow question was a big one. So kudos to Blake for getting that. But if you could talk to us a little bit more about maybe expansions on the WCS side. I mean, running 60; the diffs are really attractive here. As you look at Chalmette, maybe expansions on the East Coast or even the opportunities on the West Coast, where would you like to take that? Where do you think you can take it? And then also on the heavy side, can you talk to us about your exposure on Venezuela?
Okay. WCS first, I do want to point out, it's very much important for you all to understand, and I think we mentioned this in some of the previous calls, but remember, there is a lag on the delivery of the WCS. From the time we actually buy it, it's somewhere between 45 to 60 days. So we'll actually see these prices improving over the course of the quarter as they actually get run off. That being said, if we can procure a 60,000, 70,000, 75,000 barrels a day, if we can get 80,000 barrels a day, we have the capability of doing that. Of course, you have other parts of the supply chain that have to be able to move and lock step with that and that's the ability to load it at the load sites and move it over to rails. We're working with all the supply chain partners to do that. I said we ran almost 60,000 barrels a day in our system in the fourth quarter. We're going to run very close to that, I think, in the first quarter. And we will look for opportunities to increase that. I don't want to get into the details, but we're looking at a way of effectively using what is referred to as the loop track, which was the track that was predominantly in Bakken service when we had the stressed Bakken prices and actually loading some of the heavier crudes that we're getting out of Canada on that track. They're not quite as heavy as some of the bitumen. And so we think we'll be able to debottleneck that. Now regarding Venezuela, Venezuela is a very difficult situation. And you have all seen Rex Tillerson, Secretary of State, coming out indicating that perhaps he wants the -- the United States wants to take its position to try to catalyze a resolution for this problem because the people are suffering so much. We don't know for sure what's going to happen. We continue to get Venezuelan crude. A lot of that is coming through third parties now. We're not getting all of the grades that we had before. We're not getting as much as we had before. If indeed there's a further sanction against Venezuela, it's really not going to do a lot in the long-haul to change things, in my opinion. But it will have an immediate impact on trade flows. Venezuela can't sell crude to the Gulf Coast, to the United States. It will, obviously, have to go west to sell its crude. And then there will be a change in the flow from Middle East to fill those barrels into the U.S. So we are able to get the crude. There may be some short-term disruption if indeed the sanctions are put in place. I don't know that they will or won't. And I don't really think it's going to stop necessarily Venezuela's ability to sell their crude. They're just going to have to sell it in different spots.
Yes. And just maybe a quick follow-up on that. I mean, the crudes you have historically run from the Middle East, there will be no -- I mean, cost is one thing, but in terms of your confidence and what you can run through the facility on the East Coast, there's no concerns there, I would assume?
No. In fact, we've just rather seamlessly moved in to running a lot of other South American crudes. Remember, particularly, where we run the Venezuelan crude predominantly has been in Chalmette, but Chalmette runs a lot of -- a combination of light and sweet crudes and it depends on the differentials. So we replaced some of those Ven crudes with Castilla and some other heavy crudes that are very similar in character. And as I said, we're running WCS and Chalmette and we can run both.
We'll go next to the line of Paul Cheng from Barclays.
Just curious that Tom just -- Torrance fourth quarter result that we see, is that a good baseline or that it still have a lot of volatility we shouldn't really -- you see as a baseline yet?
Are you referring to its operating cost or the throughput or both?
Both. In terms of margin capture rate, comparing to the [indiscernible] so we're just trying to see that. I mean, because you just -- you guided for about a year and with a lot of volatility in this quarter. So are we at a point that the fourth quarter you feel comfortable with that yet? That's somewhat of a good representation. And if we have similar market conditions, this is a similar result.
I think -- short answer to your question to my mind is, certainly, we think the fourth quarter is indicative in terms of reliability improvements, throughput and then the corollary reduction in OpEx. Torrance is a powerful, powerful machine. You know that and I -- and frankly, we don't think we're all the way there. We think we have more upside. Where -- the whole key to this plant has been getting the plant to run safely and reliably. We've made an enormous investment in people now. We're continuing to do that in systems. And the results are starting to become evident. That has allowed us to capture the commercial opportunities that we knew were out there. We have great ideas, and we have implemented a lot of them. But you really can't capture them if the plant isn't running right. So we're in new markets. We're increasing our distillate capability. Short answer -- it wasn't a short answer because I'm pretty passionate about this is we believe that the fourth quarter is a good, good benchmark now, and we think we have more ways to improve as we go further.
Great. On your Northeast and the Gulf Coast margin, comparing to the -- you indicated that we loop. Seems like they deteriorated more than we thought. Is there any one-off items that have impacted in terms of the margin capture? I mean, after all in the third quarter, one would have thought because of the hurricane and rapid run up in margin, your margin capture way is going to be not in the optimal level in a rapidly rising environment. So we thought that in the fourth quarter you're going to be able to do a bit better, but you didn't. So is there something that we should be aware?
I think the biggest piece is going to be on the East Coast, the $70 million derivative exposure that we talked about. That's a pretax figure. The vast bulk of that is going to hit on the East Coast. So it's a bit skewed with the fourth quarter results. That's the primary driver.
But in the Gulf Coast...
In the Gulf Coast, the impact was -- there was an impact associated with -- we did shut down the high pressure gas or hydrotreater to do a catalyst change. We're starting to get down the [ life ] on that. So I forget how many days it was down, but there was a shutdown in the fourth quarter that impacted the capture rate.
I see. Can I just make a final observation? What I found is that over the last 25 years, it seems like a lot of companies trying to do hedging, whether it's on the product or on the spread. And I think more often than not, enough that they lost money. So I don't know whether that is really such a great idea anyway.
Let me just discuss that because you put it out on the table, but we do not -- we are, obviously, an independent refining company and our shareholders respect us. They go along the crack every day when they reinvest in PBF. So we don't really ever -- unless there would be enormous crack spreads to speculate on the crack side, what we do, do, however, is that we see an opportunity to lock in a cost, i.e., if natural gas prices got very low and we could lock in natural gas pricing at a better number than our budget; or in this case, when we see an opportunity to lock in the bases on crudes that we might run at a very -- what appears to be a very, very economic number, we'll go ahead and do that. So your point is well taken, but it is not betting on or speculating. It's really locking in something that's better than the budget.
And we'll take our next question from the line of Neil Mehta from Goldman Sachs.
Wanted to get your perspective on 2 regulatory items on the environmental front. The first is on IMO standards, which kick in, in 2020. Tom, at the conference, you had a perspective that, that was unique that you thought that it was going to be a big deal in 2020, but that wasn't potentially a sustained benefit, that it sounded that benefit could get competed away. So I want you to expand on that and what the mechanism could be that would cause that benefit to ultimately get competed away. And then you made a comment around the RFS, and the potential for some sort of favorable resolution there, so any more color there would be helpful as well.
Sure. On the IMO, obviously, we're very bullish on the fact that the IMO is coming into play. We -- I mentioned that we have a very high percentage -- 19% coking crack capacity to crude; very high. We're well positioned. We could handle the IMO if it was enacted tomorrow. We're going to continue to look for ways to advantage that. That being said, to your question, and the reason I said this is -- and it always gets to capital discipline in advance of IMO is if you believe the forecast, and some of the things that the pundits are saying, and the analysts are saying, including many of you folks, and I believe it, this will be somewhat of a seismic shift in 2 fronts. It's going to have an enormous pull on diesel, and a whole new market in order to blend to a 0.5 bunker fuel; and at the same time, will likely result in a very large volume of stranded resids from crude units that don't have cokers that run medium crude. And the long and the short of that is if the price of the diesel goes up and the price of resids go down, the clean dirty spread goes up, and you can make a lot of money if you run. The light heavy crude differentials will widen out. I think we all believe that it's going to be the case if it goes, and it's going to go. There's no doubt about that in my mind. That being said, if indeed, you have those types of incentives. Let's just say, the clean dirty spread goes from 30 today to 55, 60 or whatever, well, that's going to have people come in and try to say "Hey, how do we get take a good piece of this action?" And at that point, I think the probability that some of the ship owners will indeed go ahead and put scrubbers on their ships will happen. And you can do that over a 3- or 4-year period. I don't think this is 2020 alone, but I wouldn't bet that by 2025 there isn't a number of alternative ways being put in place to get to 0.5. On the RFS, look it is a big surprise. I believe that the RFS is completely broken. It's a completely stupid statute right now. It's not at all serving the intention that it was there for when it was initially put in place. It's just a hidden tax on the American consumer. I find it interesting that the United States government, President Trump, is now looking at perhaps increasing the gas tax, federal gas tax, in order to help fund an infrastructure program. Well, you know you got a fair amount of tax, hidden tax, in the gas price today if you believe most of the cost of RINs is into crack. And that's just being a hidden tax that's going to the ethanol people, it's going to speculators, and it's going to large integrated companies. You could actually take the RIN cost out and cap it, like Senator Cruz wants. And you probably get -- you'd get that amount of money out of the price of gasoline. So it's broke, and the reason I'm somewhat optimistic that it will really ultimately get fixed is this is not insignificant that -- what is going on now. You know about the governors asking for waivers. 27 refiners are asking for small refinery exemptions. PES's unfortunate circumstances of going into bankruptcy has put a major spotlight on this issue, and there's just no way that Washington, D.C. is going to be able to make this problem go away and sweep it under the rug. Sooner or later, they're going to have to come to an answer that creates a result. And I think that -- and as Senator Cruz has said, there are some win-win opportunities out there. We'll see what happens, but I do think there's a lot of discussion and there's a lot of different stakeholders are now becoming aware of really the situation. So I'm optimistic we'll see some result.
My follow-up is just the return of capital to shareholders, part of the reason the refiners generally have done well over the last couple of years. It's one of the factors in energy. They've been aggressive around either buying back stock or growing the dividend. And you guys have been in the investment cycle over the last couple of years, so haven't been as aggressive around this. But with Torrance now generally behind you, and a lot of easy wins at Chalmette behind you, are you in a position to grow the dividend and think about buying back stock or is it still too early?
Well, I'll tell you this, Neil, we're certainly in a position, and we believe we will be in a position with, as you say, the continued progress we're making in Torrance and throughout the system. And, of course, the benefits of tax reform that we are going to take advantage of that situation to buttress the balance sheet for sure. I don't know that we will consider a dividend increase. We pay a very healthy dividend right now. We certainly have the times where we award employees equity as part of the normal compensation program. We'll look to see whether or not it makes sense to buy back shares to at least not have that dilute the existing share base. We will remain very disciplined on capital. Capital is not a friend of the refiner, in my opinion. I'd rather spend money buying refineries than building new toys inside the refineries and that is a model that has worked well in the past. And as I alluded to earlier, we did not pay any employee -- virtually any employee of PBF a bonus last year because we did not perform adequately in 2016. So our employees will also participate in the benefit from some of the cash that we expect to be able to generate.
And we'll go next to the line of Phil Gresh from JPMorgan.
First question, if I just look at the East Coast, Erik, you had mentioned that the capture rate in the fourth quarter was impacted by the derivatives. I thought that the gross margin there was adjusted out for special items. Is that not true?
Not for the derivative exposure, no. So that's going to exclude primarily LCM and any other kind of one-time things that we would normally call out. So the only -- we're required by some GAAP requirements here to what we include in various different press releases and tear sheets, but no, it does not include the $70 million pretax expense.
Okay. Got it. I guess, a bit more broadly on the East Coast. My broader question is, the past 2 years, the capture rate there has been well below the prior 2 years. So it seems like if you can improve that, that would be back to the levels where you used to have it. That would be a big opportunity. But I'm just curious how you think about the challenges you've had there and what the opportunity is for an upside from here.
Yes. I think it's pretty simple. Other than the boilerplate of making sure the plants run and run in a safe and environmentally responsible manner. Particularly since OPEC and non-OPEC started with their cooperative agreement to cut back on how much crude was coming out of those regions, the light heavy spread has just moved in. And particularly, Delaware, but even in Paulsboro, there are medium-to-heavy crude refineries. And as the light heavy spread moves in, the capture rate is going to get impacted. The fact is how do you improve that? The easiest way to improve is do exactly what we did, lock in when we had the opportunity the basis to be able to deliver heavy crude out of Canada into places like Delaware at an economic and attractive number with a bigger crude discount. If we have the bigger crude discount, then we're going to wind up with a higher capture rate. And then as you go forward on that, ultimately, OPEC, non-OPEC will exit and what is going to come back on the market is going to be predominantly the medium-to-heavy grades. And you follow all that up with the IMO in 2020, which is basically 22 months away. I think we're going to be very well rewarded for the facilities we have in the East Coast.
If I were to just take the operating piece of that in 2017, it means you have an estimate of how much of the underperformance is related to operations in millions of dollars or anything like that you could share?
I'll have Erik get back to you. I didn't bring it with me. We do track LPOs, the biggest LPO in our system in 2017. It was a big number, by the way. It was almost $0.25 billion throughout the system, and it was all in the first half. And most of that -- $120 million of that is Torrance, and the rest was spread around the system, but I will say that Delaware City actually was -- had the second highest LPO, but I just can't recall the exact number.
Okay. No. That's helpful. Just coming back to the IMO 2020. You have given an estimate if you bring the coker on and just across your system, how much flexibility do you have to produce incremental diesel?
Actually, as I've mentioned, there's a couple of projects that we -- they're not huge projects that we're looking at to -- because of IMO that perhaps might not have made the hurdle. 2 of them are associated with increased diesel production. And frankly, one of them is in Toledo. We're going to put in a facility. There's some diesel that's captive in the -- and carbon black or the slurry oil that is produced over their cat cracker. We're going to strip that out with a little -- with an investment. That will make 3,000 or 4,000 -- or 2,000 or 3,000 barrels a day perhaps diesel. And then we've got a small project in Delaware -- in Paulsboro, I'm sorry, that will also allow us to increase diesel. The biggest project that we have, on the diesel side, is we are relooking at probably with third parties putting in a hydrogen unit in Delaware. Delaware is a very heavy coking refinery, but it actually could use more hydrogen. When you're a coking refinery, you need a lot of hydrogen to turn all that stuff that comes out of the cokers into clean fuels. So we're looking at putting that hydrogen plant in place and a hydrocracker debottleneck of 3,000 to 4,000 barrels a day, which will increase diesel. So net effect, maybe we'll get somewhere around 7,000 to 10,000 barrels a day of incremental diesel production. We're also looking at -- we do have an idle coker and we have an idle hydrocracker that we got when we purchased Chalmette. Right now, we're looking at the coker because that makes sense in advance of IMO 2020 to go ahead and restart that thing. We have an active effort under way to evaluate that as well.
Okay. Got it. Last question would just be, your comments in the press release about being positioned to benefit from opportunities in the market. Are you seeing M&A opportunities out there in 2018? Or is that just -- kind of just a broader comment?
That was a broader comment. My own view, we are going -- as you know, that is our model. We're acquisitive. We will look at everything and we still want to grow the company that way. But when you have something like IMO that is not that far down the road, you wind up in a situation to a certain extent that people who would be sellers think their refinery is worth a tremendous amount of money. And buyers look at whether or not they're going to be able to afford to pay that. And it really gets down our thinking as to what I -- I think it was Neil who asked the question. Somebody who's trying to sell a refinery is saying they're going to have a great benefit because of IMO. Well, they might. But I think it's going to be for a short period of time, and you better put that into your thinking. So it maybe that at least at this moment, there's not a lot of activity in the sector in this area.
[Operator Instructions] And we'll go next to the line of Prashant Rao from Citigroup.
First one, I just wanted to ask is a matter of sort of housekeeping here. As I look at the turnaround schedule, and I'm thinking in terms of Tier 3 sulfur standards and gasoline yields, could you give us like some color or update on where you would stand in terms of satisfying Tier 3 requirements? I see a couple of alky unit projects, which are not scheduled. Just wanted to get a sense of where you stand, and how much work you might need to do there this year or maybe potentially into the following year.
We really are in good shape on Tier 3. We will be spending some money this year to kind of complete the effort. We have -- I think it's mainly Chalmette that we have some cleanup work to do to finish. We've been using credits to be in compliance. But as part of our plan, we would put in some remaining investment -- I don't know if it's caustic scrubbing or what to get in compliance at Chalmette. So Tier 3 is not going to be an issue for us. You are correct that we do have one alky unit scheduled for a turnaround here in the first quarter. That's at Delaware City. Delaware City has more than one alkylation unit. So -- and Chalmette has got its cat cracker coming down and the alkylation unit will come down with that. General turnaround -- the turnaround activities for this year fall into 2 groups. There's -- Toledo will be shutting down its hydrocracker-related equipment reformer here at the end of the month and through March. And Chalmette, we'll be doing the cat cracker and the alky that I referenced around the same time frame. And then there's no activity until late third quarter. And that then shifts over to Paulsboro, and a minor -- relatively smaller turnaround at Delaware City.
Okay. That's really helpful. And then just one sort of broader market question. Maybe turning back to the Canadian crude issue. We've been seeing that spread start to pull in a little bit over the last couple of weeks. And we know that -- we've heard in the market that the Class I rails at least are playing hardball in terms of giving capacity. But in terms of how we should think about cost per barrel, not just necessarily for you, but for the broader market. Just any thoughts around how much more the rail cost per barrel could increase if the rails were to give capacity. Or maybe some color -- insight into where that state of negotiations is just from where you stand and what you're seeing in the market.
Well, we're obviously dealing with all parts of the supply chain. We think and we've said publicly that our cost, and this is really to the East Coast of the United States we are referencing, is going to continue to range between $16 and $18 a barrel. We don't see it -- that's the range. There's obviously more activity. The rails have indicated that they've got a lot of grain they're moving and iron ore and other things. But we expect our cost to be about $16 to $18. As I said earlier, I know you're asking a broader question, the cost to the Gulf Coast to the United States are going to be less. But you really don't have as much infrastructure built out in the Gulf Coast or the type of infrastructure you have to unload that we have in Delaware. So we're pretty confident we're going to be able to source in the crudes within that range, that transportation cost range I just gave you.
And we'll go next to the line of Matthew Blair from Tudor, Pickering.
Maybe just going back to the previous question on Tier 3. Tom, I think you mentioned in the past that you're expecting to see wider octane spreads as a result of Tier 3 just from the process of pulling all the sulfur out of the gasoline. We really haven't seen that come into play. So I was intrigued by your comment on using credits to comply so far with Tier 3. Do you have any sense on an industry-wide basis how much credits have been used? Has this been a big factor and would you expect wider octane spreads in, I guess, in the back half of 2018 and 2019 as these credits get used up?
Yes. I think -- again, the answer to -- do I expect octane to widen out? Yes, I do. And some of it is because you can't use -- that credit will be phased out. The predominant step of getting to 10 part per million to a certain extent, you scrub butane, stuff like that, but you continue to have to increase severity on your desulfurization units. You do get the sulfur out, but you destroy octane. That's just part of the chemistry. So Tier 3 is a good thing from an environmental standpoint and getting the sulfur out of gasoline, but it is a negative on octane destruction. The other thing that is going in is -- and you see this and we'll see it again, I'm pretty convinced of that, is with the now revisiting -- rebirth -- the resurgence of the shale oil development and production in the United States in the Permian, the Bakken, as you're well aware, I think a lot of those crudes are 45-, 50-degree API, have a very high concentration like straight run gasoline, like straight run gasoline which gets blended directly into the gasoline pool is sub-octane. And so it is a drag on to gasoline pool. And then what you have to do is figure out a way to how to get additional octane components, like reformate from a reformer to blend it up. So you got 2 things, the end of the credits and, therefore, you have to produce your own octane instead of buying something out in the marketplace and what, I believe, will be an increase in production of and running of light crudes. We saw that the last time when we had very heavy growth rates and we're trying to consume the light shale crudes in the U.S.
Got it. And then I'd also like to go back to Tom, your response on staying disciplined on capital. You mentioned that you'd rather buy refineries than build new units. As you look at the PBF portfolio, you have coking capacity on all the coast, but you don't in the Midwest, which arguably is the best place to have a coker, right, with pipeline access to discounted Canadian crude. So I guess, could you just walk us through the argument for not building a coker at Toledo? Is it just a capital constraint issue? Is there some sort of mechanical constraint at Toledo that would prevent that? Any commentary there would be helpful?
Yes. 2 things I would say. Even though Toledo doesn't have a coker, it is an interesting refinery and, in fact, it does not produce any fuel, except for the stuff that comes out of the cat cracker because the crude dye that it runs allows it to run what is called an atmospheric bottom stream cat cracking operation. So there is no fuel oil being produced. The stuff that comes out of the atmospheric crude unit goes into the cat cracker and converted to gasoline and diesel. That being said, obviously, if you are WoodRiver, if you are BP Whiting, you have big coking operations, and you have pipeline access to these very heavy crudes that are very heavy distressed and you are smiling. Now we could do -- to your question, does it make sense to put a coker in? It's almost impractical, because, unfortunately, Toledo is a sweet crude refinery. So it's not the question of just putting in a coker, you would have to revamp the entire plant. You'd have to put in additional sulfur handling, sulfur capability, tail gas units, you need more hydrogen. You just can't drop a coker in the middle of a light sweet crude refinery and just look at the capital cost of the coke. It would be an enormous project. And, again, I'm not prepared to go ahead and put that much capital in. Sooner or later, the pipelines will be built out of Canada, whether it would be Keystone XL or one of the other 2. And so just -- by the time we would take to even get that project permitted and built, I'd be afraid that the window would have been closed.
And we'll go next to the line Paul Cheng from Barclays.
Couple of quick follow-ups. Tom, you talked about those potential small projects that we need to IMO. Any kind of capital requirement that you can share?
I'll tell you this, Paul. We basically -- earlier this year, when the management team, the executive team did one of these little let's go, sit together and look at our strategic objectives in the short term and midterm, and we approved about $25 million of seed capital money in 2018, directly focused on the aggregate opportunities that we could have, much of that is around MARPOL. And when I say seed money, for example, we're going to spend money to look and see whether or not it makes sense to start up the coker. And if indeed, we conclude here that it does make sense to start up the coker, that will be a much larger investment. I don't know exactly what it will be, but that's what we have to determine in the short term. But we've approved some efforts now to go ahead and -- we've identified projects that we've already said we're going to do and those are the ones that I kind of referenced earlier, but there's a number of other projects we're doing. I will give you one that is absolutely essential in my mind. We can't look at the impact of IMO only inside the fence lines of refineries. There is going to be opportunities that come around with IMO. People are going to want to sell their stranded resid to U.S. coker feed. If you have a coker go down, you are going to want to have an ability to wire around that. So there's a bunch of logistics issues that I see that have opportunities to be able to bring hot coker feed into a refinery. It may be more economic buying coker feed than running crude. We don't know that. But those are the type of things we are studying to improve our life in preparation for the IMO.
Right. And just on the projects that you mentioned, I mean, what kind of investments we are talking about in the, say, maybe millions or $10 million that we're talking about, say, less than $1 million? I mean, just is there any kind of -- maybe a range that you can provide us so that we can get some understanding about the capital intensity we may be talking here?
Well, we can't give you a number now. I said we've approved the seed money in many of these areas. What we've already approved to implement is probably somewhere in the $10 million range across the whole system. Now there's additional monies that we've approved to actually study whether or not various steps should take place, but those estimates are underway. It's way too early for us to tell -- have an idea whether or not we're even going to proceed with them, but we certainly had a lot of engineering work in order to define not only the cost, but the profitability associated with those projects.
Okay. A final one. On Venezuela, how much is the Venezuela oil that you are running now?
We run about 40,000 barrels a day, I think, in the fourth quarter.
Oh, that's it. So even if they disappear tomorrow, that is not going to be an issue for you?
No. We -- look, there's lots of crude out there. As I said, we're running a lot of different crudes. So it's not really going to be a showstopper or tremendously a large issue for us. There are some crudes that we like that we were running, that we would like to have, but frankly we've been able to substitute for them effectively.
And we'll go next to the line of Phil Gresh with JPMorgan.
Just one last follow-up question. The G&A expense in the quarter was pretty high. Any color about what drove that and whether it's going to continue at this run rate?
I don't necessarily think it will continue at this particular run rate. We did have some essentially employee bonus accrual that occurred during the fourth quarter, and it surely gets accrued at the fourth quarter simply because that is where the final piece of the full year financials are finalized.
How do you think about a 2018 run rate?
I think -- excuse me, consistent with what we talked about before excluding any type of incentive in stock-based compensation, it's a little bit too early to tell on those various pieces, but probably in the 160 to 170 range, I think, consistent with what we've guided to before.
And we'll take our final question from Brad Heffern with RBC Capital Markets.
Just another follow-up on the MARPOL regulations. I was wondering on the other side, if you guys have any high sulfur bottoms that are potentially going to be stranded by the regulation. And if there's an opportunity to do any sort of upgrading with that.
Great question, and that's why I say we have -- we are sitting here with the catches waiting to recede. We have -- we don't make any fuel in Toledo. So there's no high sulfur or low sulfur material that's going into a fuel oil pool on a distillate fuel. And in the other 4 refineries, we have cokers and we have cokers that are large in size. We do not produce -- we do produce some asphalt, produce it out of Chalmette, and we produce it out of Paulsboro, but we don't produce any 3.5% fuel oil of any real volume unless there's an operating issue in a coker somewhere.
Thank you. And I'd like to turn the call back to Mr. Nimbley for closing remarks.
Thank you very much for your attention and participation in the call. And we look forward to having the next call with you with hopefully continued results -- good results and improvement in our system. Everybody, have a great day.
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