Good day, everyone, and welcome to the PBF Energy First Quarter 2016 Earnings Conference Call and Webcast. At this time, all participants have been placed in a listen-only mode. And the floor will be opened for your questions following management’s prepared remarks. Please note this call maybe recorded and I will be standing if you should need any assistance. It is now my pleasure to turn the conference floor over to Colin Murray, 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. A copy of today's earnings release, including supplemental financial and operating information 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 that 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. As also noted in our press release, we'll be using certain non-GAAP measures while describing PBF's operating performance and financial results, as we believe these metrics are useful, but they are non-GAAP measures and should be taken as such. It is important to note that we'll discuss adjusted fully converted earnings information and results excluding special items. Our GAAP net income or GAAP EPS figures reflect the percentage interest of PBF Energy Company LLC owned by PBF Energy Inc. We think adjusted fully converted net income and EPS are meaningful metrics to you because they represent 100% of the operations on an after-tax basis. As a result of rising hydrocarbon prices, during the first quarter of 2016, we generated a non-cash lower of cost or market, or LCM, after-tax benefit of approximately $36 million. And our comments today will exclude this special items from the discussion of our results. I will now turn the call over to Tom Nimbley.

Good morning, everybody, and thank you for joining us on today's call. The first quarter was always challenging for the refining sector as a whole and for PBF in particular as we experienced significant unplanned downtime on our East Coast operations. The East Coast experienced approximately two weeks of unplanned downtime at Delaware City refinery as a result of a storm-related loss of power in late January and given the prevailing market conditions, we elected to accelerate the timing of the Delaware City coker and hydrocracker turnarounds, which were previously scheduled to begin in late March. As a result, Delaware City was without coking and full upgrading capacity for more than two months of the first quarter. We ran the lowest volume of heavy crudes on the East Coast since before 2012, which was a headwind to our overall capture rate as we consumed lighter and more expensive feedstocks. The downtime and coke and hydrocracker turnarounds impaired our ability to convert our typically advantage slate of heavy and medium crudes into saleable clean products at Delaware City and also resulted in a higher yield of low-value products as can be seen by the roughly 8% swing between clean products and low-value product yield on the East Coast versus the prior quarter. We estimate the margin loss of the planned and unplanned downtime at about $75 million for the quarter. Before moving to the other regions, I’d like to comment on Delaware City’s operations. As I said, they had a tough first quarter with the strong related downtime and advance in the turnaround. The team adapted to the accelerated timeline and completed the turnaround near the end of the first quarter. Unfortunately, coming out of the turnaround, a crack developed in the piping well at the hydrocracker. The unit underwent a…

Thanks, Tom. Today, we reported the first quarter operating loss of approximately $65 million, and adjusted fully converted net loss of $67 million, or a loss of $0.65 per share, on a fully exchanged fully diluted basis. This compares to operating income of approximately $151 million and adjusted fully converted net income of approximately $79 million, or $0.87 per share, for the first quarter of 2015. Adjusted EBITDA for the quarter was a loss of $5 million as compared to adjusted EBITDA of $202 million for the year ago quarter. As Collin mentioned a moment ago, these figures exclude the non-cash LCM benefit. For the first quarter, G&A expenses were approximately $38 million as compared to $36 million a year ago. Depreciation and amortization expense was approximately $56 million versus $48 million in 2015. First quarter interest expense was approximately $38 million, compared to $22 million, last year. PBF’s recorded effective tax rate for the quarter was approximately 43%. For modeling purposes, you should continue to assume a normalized rate of 40%. Refining and corporate CapEx was approximately $143 million and we ended the first quarter with liquidity of approximately $1.2 billion and consolidated net debt-to-cap of 30%. Our Board has approved the quarterly dividend of $0.30 per share payable on May 31st to shareholders of record as of May 13th. I’d like to take a moment to provide second quarter throughput guidance. We expect East Coast throughput to be 335,000 to 355,000 barrels per day. Mid-Continent throughput is expected to be 155,000 to 165,000 barrels per day and Gulf Coast throughputs should be 175,000 to 185,000 barrels per day. Also of note today PBF Logistics announced a distribution increase to $0.42 per common unit. As a reminder, PBF Energy now owns 49.5% of PBF Logistics, and 100% of the general partner and incentive distribution rights and we continue to benefit from participation in the second level of the IDR splits. PBF Logistics is scheduled to close its previously announced acquisition of the East Coast terminals from Plains All American tomorrow. After some initial investment by PBF logistics, the terminal should provide additional opportunities for PBF Energy to market its products in the greater Philadelphia market. Subsequent to the end of the first quarter, PBF Logistics completed its first follow on equity offering and raised approximately $53 million in total gross proceeds to fund the pending acquisition and for general corporate purposes. This represents our third successful capital markets transaction since October of last year and collectively we have raised over $900 million of debt and equity. We continue to focus on managing the balance sheet to put ourselves in a position of maximum flexibility for 2016 and beyond. Given the volatility in the markets, our opportunistic strategy has generated sufficient liquidity for PBF Energy and PBF Logistics to fund three strategic transactions over a seven month timeframe. Operator, we completed our opening remarks and we’ll be pleased to take any questions.

Thank you. [Operator Instructions] Your first question comes from the site of Paul Sankey from Wolfe Research. Please go ahead.

Hi, guys. A high level question, if I could. We have good demands, very good demands to oil products in the U.S right now and okay demand globally. I was just wondering what your perspective is on why margins was so poor in Q1 and why they’re kind of struggling along now? Thanks.

I think good question, Paul. I think first of all margins, we did say before in the previous call that particularly in the Mid-Continent. We expected there to be kind of a return to the norm for the refining sector in the Mid-Continent would be RBOB have been closed with the pipelines and the order has been built. And in fact I think that’s what happened and certainly in the Mid-Continent, we obviously saw reduced demand as that’s typically happened in that area and that resulted in a poor crack and in tandem with the higher Syncrude price actually impacted us pretty good. And then, of course, on the distillate side coming into the first quarter, we were coming out of the warm winter very high inventories and that was a concern. In fact we took steps to reduce our distillate production because it was not economic. That seems to have started to turnaround. And certainly in the last several weeks, two weeks does not make a trend. We’re seeing an increase in distillate demand and crack is responding accordingly. Right. And then could you just to continue Tom and talk a little bit about the outlook for summer because again I would have expected things to be tightening up better than they are where you’ve talked a lot in the past about the Octane stories. So could you just give us your latest view on how we workout into driving season?

Yes, we still are bullish gasoline and bullish octane and in fact over the last several – I’d say again, last several weeks, maybe even a week, the PBOB spread in New York, RBOB has widened out. It’s now north of $6. It had been down as low as $4. The driving season really hasn’t hit that hard yet. So, I suspect that we will get a continued strength in gasoline cracks per se and that the PBOB or the premium gasoline spreads versus conventional oil or CBOB will remain strong and I don’t really see that changing.

And our next question comes from Phil Gresh with J.P. Morgan.

Hi, good morning.

Good morning.

Actually color on the opportunity cost in 1Q obviously through April, you’ve been going through some repairs as well. Do you have any general sense of maybe what the impact is we should think about for what we’ve seen in April?

Yes, the only real impact has been that unscheduled or re-shutdown if you will of the hydrocracker after we had started up and streamed it. We haven’t quantified what profit opportunity, but my guess it’s going to be somewhere in around $10 million for the month of April.

Okay, got it. That’s helpful. And then just two questions on Torrance, one I know you still expected to close in 2Q, it does seem like its there have been some hiccups here recently with the restart process. So any color you might have on that. And then secondarily as you look at the cash and the balance sheet or available cash kind of ex-marketable securities at PBFX, how you’re thinking about the funding for the transactions at this point if you have any color there?

Yes, I’ll take the first part and ask Eric to handle the second part of your question. Obviously, the big hurdle that ExxonMobil had –was cleared when the South Coast Air Quality Management District gave them the permission to start the restart they’re on a process we’re going through that they are being very methodical I can assure you and we deployed that, so the timing will be set, by basically two things, one, they get the unit up and running and as I said they are in a process of doing that, but they are – they have a very well pulled out program on how to do that. And then very importantly once they get the units lined out at the optimum rates, so high rates that would start the restart criteria period in 15 days, we will not take this facility, I want affirm that again over until, we are satisfied that its in good operating condition. Erik

I think on the funding side Phil. So we have roughly $725 million worth of total funding to achieve once we close that would be roughly $525 million to spend on the assets and we’ve estimated based on current pricing about $200 million of net working capital. So assume, we’re probably going to keep at any given time, anywhere from $200 million to $500 million of cash on our balance sheet. And as we did with the Chalmette transaction we would borrow under our ABL our working capital facility. And then ultimately that would be the first thing that we start to deliver and pay down as we go.

And our next question comes from Roger Read with Wells Fargo. Please go ahead.

Good morning.

Good morning.

Given here some of the bigger things were handled there but can you talk about the change in cash here in the first quarter and how that may or may not come back in the second quarter given all the expenses related to the turnaround as well as just changes in product prices here?

Yes. I think that the biggest change overall that we saw change in – I guess in cash is going to be roughly $143 million of the call it $200 million of cash. That was spent during the first quarter was as a result of turnaround then normal a 100 of that – 110 was related to the Delaware City. So what we’ve done is that’s essentially, we did brought that forward from Q2. I think at this point we’re looking to cash from operations to come back from a net working capital change, right there is really only about $20 million of working capital change during the quarter.

Okay, that’s helpful, thanks. And then, the other question I would have is thing about the financing of Torrance into some degree even if Chalmette, Logistics dropdowns how does the market look here you raised distribution for PBFX I say you did but PBFX raised its distribution, so obviously it’s feeling better about its cash position here. what’s the outlook on timing and magnitude of the dropdowns of the logistics assets with those two refineries the closed and pending one.

I think look Plains, our Plains transaction is scheduled to close tomorrow. So that provides a bit of cover here as we go through the end of the year with PBF Logistics in terms of potential incremental distribution increases. And really the timing of dropdowns is not solely dictated by the market, but the access to the equity capital markets is extremely important for PBF Logistics. We don’t feel like we have a gun to our head to do anything. We’ve provided distribution growth guidance at the logistics level. We feel pretty confident with what we have. And I think ultimately it’s going to come down to if the market is available and it makes sense let’s go ahead and pull the trigger, but we don’t feel like there is any real need to go out and jam a dropdown into a market that’s still, still today it feels a little bit uneasy. We were successful with our capital markets raise, but we got in and out in a day and we think that’s the way to do it as we go forward.

Our next question comes from Neil Mehta with Goldman Sachs.

Good morning, guys.

Good morning.

So first question is on Chalmette and Torrance. So relative to the EBITDA that you projected at Chalmette. I think it was $260 million and Torrance at $360 million. As you’ve been able to spend more time with these assets and as market conditions have evolved here. How do you think about those numbers relative to where you discussed in last October.

Actually we’ve taken one at a time, Chalmette, as we said, we’ve had been profitable in both of the quarter since we rounded. They did have a small turnaround shutdown of their coker during the first quarter and still we were able to produce a profit. The short answer, we feel very comfortable with the numbers that we’ve talked about last October late last year on Chalmette. I believe we got a stronger crack now in the Gulf Coast, we expect to see that, it to continue contribution. The reason I say we feel comfortable is the more we look at it, the more we see it, we’re very pleased with some of the things that we’ve already started to do have done executed and what it lays in front of us. We’ve made in inroad in the commercial area. Remember that this facility was basically in integrated asset Big Oil, it was there to serve the upstream both [indiscernible] and to a certain extent ExxonMobil. We’ve entered new businesses already we’re into the asphalt business in Chalmette. We’re going to be up to kind of 12,000 barrels a day asphalt production in June with better net backs than they were selling back in bottoms to their system refineries were holding down the wholesale chain and trying to get better net backs. We’ve entered the export markets both on gasoline and distillate and that was one of the strategic objectives that we had. So all in all from a commercial standpoint and new market standpoint we’re moving pretty rapidly to capture more benefits, better benefits better net backs. I referenced, we found when we went into really got our hands on our refinery they’re spending a lot of money on the merge because they have logistics constraints on the docks…

Thanks, Tom. Thanks for that answer. The second question I had is related to rent expense. And just what type of rent expenses should we be assuming, once Torrance comes on line as the run rate for you guys, I’m just trying to size the year-over-year impact or what a good run rate number is for rents?

What we would say Neil is currently we are running at about $65 million a quarter in total rent expense that excludes the Torrance acquisition. And I think what – we’ve included the rent expense and we need a little bit of time to sit down and review about this plan that Tom referenced in terms of exactly how things are going to unfold, once the commercial team is fully in place out on the West Coast. And we’ll be able to provide some more color, but we’ve got some fairly conservative estimates baked into that $350 million – $360 million EBITDA number for Torrance.

And our next question comes from Chi Chow from Tudor, Pickering, Holt. Please go ahead.

Thanks, good morning.

Hi Chi.

Growth is obviously a key component of your strategy. Do you think you need to observe Torrance and then make for the progress at Chalmette before you consider any additional acquisitions going forward here? And do you have any general thoughts on the state of the acquisition market right now in refining?

Well the first part of the question, we are going to make sure that we absorb time. So I feel that we’ve gone very well on Chalmette. And hopefully with our – putting our team out there so much in advance and hiring people that will fill the holes, it is our expectation, everybody understands that Torrance has not run, as well as it should have or could have in the last several years. That is primary – priority one for us is to make sure that the fact that we don’t have those problems and we put our resources there. But we are comfortable that we’ll be able to do that in a reasonable period of time, such that it shouldn’t really impact our ability do another acquisition, if there’s an attractive acquisition that comes forward. They stated to market. And again, we look at assets we are going to continue to be acquisitive. We have some strategies in place that we’re following. It all depend on what becomes available and what the bid-ask is. But we see the opportunity still being somewhat favorable. There’s still lot of pressure on majors because of the decline in flat price and a need to shore up their balance sheets and one of the ways they may well do that is to buy best assets, including assets and refining. I don’t think the majors are going to be acquisitive at all. One other thing is that is obviously we’re watching a little bit is what’s going on with the announcement on motiver [ph] and how that thing is going to play out. That could result in some things going on as well. But the short answer is if we have an attractive opportunity that shows up in the second half of the year, we would feel comfortable pursuing it and that’s where it is.

I think too Chi we would also just continue to manage our balance sheet to make sure that we’re in a position that we can execute if any opportunities do arise.

Thanks for that. And then I guess question on Toledo actually, Tom you mentioned in your remarks that the Syncrude pricing was a little bit less favorable in the quarter. I know you run a good percentage of Syncrude at that plant. Are there options or projects you’re looking at to optimize the crude slate to maybe change up the fleet and squeeze up a little bit more on there margin there going forward?

Yes so on the margin there is, I don’t mean – I mean on the increment kind we’re not going to obtain a position to I say we’re not going to run Syncrude, because as you are well aware it is a pretty good size or percentage of our fleet. But we in fact, I think we’re spotting the rails some Bakken into Toledo because the economics actually favor it. There’s some other crudes that we’re bringing in or Syncrudes that are not as expensive as the other crudes. And of course we have the crudes from Michigan that we’re trying to get as much off and we’ve been able to ramp them up to about 15,000 barrels a day. So the short answer is yes, we’re looking at making sure that we have some knobs to turn if indeed we get to a point where our upgrades go down and the Syncrude price goes 5 to 6 bucks lower. But we’re not going to completely displace or even usually reduced the amount of Syncrude we’re running unless something really ever it happens.

Thank you, our next question comes from Brad Heffron from RBC Capital Markets.

Hey, good morning everyone. I guess going back to an earlier answer I was curious you mentioned at Chalmette you guys have moved into the export market. Can you talk about what the volumes for the quarter were there and where they’re going?

No, I won’t, I don’t want to tell you where they’re going because counter parties have requested that to not disseminate that information. What I can’t tell you and it’s early in the game. We did a gasoline export cargo and I think that was the first time in many, many years that gasoline was exported over the dock out of the Chalmette. And I think that was a 300,000 barrel cargo and we’re looking to do a second one here in short order. On distillate we did 420,000 barrel cargo that we loaded out during the month of February or March I can’t recall. And again that knob is open, so will be looking to do more of that. We’re pleased, we have some work to do though as I said the dock constraints at Toledo and – I’m sorry, Chalmette and the and the tankage constraints all limiting and therefore an opportunity and we intend to figure out a way to solve that and further our ability to take advantage of the export market.

Okay, thanks for that color. And then at Delaware City, I was wondering if there’s any update on the hydrogen plant there and if the attractiveness of that project just changed target and the weakness in distillate.

The overall economics of a plant they haven't changed at all really. You remember this is a – to a very large extent, is a natural gas, gas to liquids project. That you buy a natural gas and you're pumping it into obviously clean products. So the $80 million or so annualized EBITDA remains something that we think is real. One of the real benefits of that hydrocracker, hydrating unit and therefore increased hydrocracker rate at Delaware City is that you’re not turning distillate into gasoline or one other things are there and we hope to be able to do take very low valued slurry oil from the cat unit that is basically begin solid as discount into the heavy fuel oil market and turn that into diesel by cracking it. So the EBITDA contribution and the economics remain robust. The question that we’re looking at now is in terms of how do we fund it? Erik, do you want to give any color on that?

What I would say Brad is we're still working through a couple different pieces about how the potential plant gets funded but we have received all the permits required to go ahead and construct the facility. We were a little bit, I would say the timing changed a little bit during Q1 as a result of the turnaround being accelerated and we're kind of back attacking the project now.

Thank you [Operator Instructions] And we will go next to site of Jeff Dietert from Simmons. Please go ahead.

Good morning.

Good morning.

I was hoping you could talk in a little bit more detail about your capability to shift towards maxing gasoline and not over supplying the distillate more here. We aren’t seeing some improvement in demand there. But could you talk about what your capabilities are? There’s been some discussion about running distillates through the cat cracker could you talk about that effort?

Sure, I will try to keep it in sync here, but basically for our four refinery system ex Torrance, you should assume that we have swing production capability of about 50,000 barrels a day between the four refineries. So that’s all I’m saying here is there's overlap in the molecules if you will between distillate and gasoline and dependent upon the economic incentives. We could go as if we had a weak test, very weak test with market and a strong gasoline market we could swing 50,000 barrels a day of production from distillate into gasoline and if the converse was true we could go the other way. Now how was that 50,000 barrels a day, what does it come about is really just two simple parts of it. This is a little bit simplistic but its pretty much on the money. One is simple fractionation you just change the cut points and to tap the various towers that cog up all the stuff that we run. And basically, for example on the crude-tower you can take, you can change significant profile and drop naphtha into distillate. So naphtha into jet fuel you can do the same thing on the cat cracker fractionation towers, so about half of that 50,000 barrels a day just comes from changing the temperature profiles and moving barrels, draw them off into distillate cut versus a gasoline cut. The second half is what you started to allude to is you can do the same thing and drop distillate molecules and to get the gas oil streams. And therefore then that becomes a feedstock to your conversion units particularly a cat cracker. If the cat cracker is already running full or you think you’re running at the optimum rate. You would increase the available fee to the cat cracker. You make the same amount of gasoline effectively but you reduce distillate make and you have to back out feedstock because the cat cracker example in this – in this example runs out of room. So you need to back out, PGO gas oil purchases are crude. So that’s the way it comes out. Q – Unidentified Analyst: Got you, make sense. And then looking at your throughput guidance before the second quarter it looks like you’ve got pretty healthy runs schedule for 2Q as well. So are you shifting some of that distillate through or have those economics moderated for the second quarter?

We’ve moderated at some, but we are still basically in more of a high percentage gasoline modes and distillate modes, but there is about 15 or 20 different steps I try to make it very simple but some of them, you would reverse early and another dependent upon what the spread is between gasoline and distillate and as the distillate margins have improved, we are looking at that. At the same time I think I said before we watch what’s whether or not we are actually selling the product or if its going into tank. If its going into tank. You worry about are we going to get ourselves into a situation where the inventory is building and you have the type of things that happened so, we will watch the distillate inventories and gasoline inventories but to see if recent trend in distillate continues and demand keep following or not and that will dictate obviously how we play this.

We’ll go next to the site of Ed Westlake from Credit Suisse. Please go ahead.

Yes, two operational questions and then I’m going to come back to the balance sheet. Thanks for time this morning. And just on the East Coast system, I mean, obviously very disruptive in the first quarter, you have to run into different types of crudes. But now that you're running more normally, I mean, still you’ve got inland sweets. And then you got waterborne sweets maybe just talk a little bit about which one looks better and capture rates say versus a year ago where Bakken was in the money.

Yes, if you take a look at the East Coast and the key here is, if you get Delaware and Paulsboro well in the first quarter but they have the operations right. And that's the primary focus, if we do that and then obviously as you know that effectively Paulsboro is 100% medium sour to heavy sour refinery. We’re not running any light sweet crude oil in the Paulsboro refinery running 100% of the mediums and heavies. Delaware city will run about 40,000 barrels a day at Bakken is what the LP is controlling, it’s slightly better than what we see for waterborne sweets, to answer your question. Commercial has been able to get some Bakken at a reasonable number. And that Bakken is really be in line to pull very heavy crudes and make kind of a dumbbell blend. The blend to allow us to run 16 degree API stuff, some of the stuff that's coming from Venezuela. So we won't be running very much sweet crude, we've said before we believe that that frankly is an advantage but PBF for East Coast relative to the refineries that don’t have the option. And have to run 100% sweet crude. We expect to run about 40,000 barrels a day. Have you got the second part of this question on what capture rate might be I don’t have in front of me.

That's fine. The first part was very helpful. Just on the availability then of waterborne mediums and Venezuelan crudes on the one hand, you've had Delaware agreement or lack of Delaware agreement on the other hand people are concerned about stability in Venezuela. I mean can you give us some color as to how hard you were being approached by sellers of those cargoes right now?

We continue to be able to buy the crudes at attractive prices. We’ll say there's a lot of crudes still out there. There is a lot of hype on Delaware and everything else and there's a lot of money running into the markets but there is a lot of crude out there. Iran is ramping up. So we have had no problem getting crudes from South America. We still continue to get our crude from Venezuela that is obviously somewhat unstable situation. But it's not having an impact on us right now. And we’ve been running some M100 and things like that, that will come back into the marketplace is economic. So right now we have no issues on our side.

And then just in Torrance, I mean is there ability to switch that grade to something a little bit heavier and how to get some cash that way.

Torrance, basically Torrance just runs every period. We are looking at it, but the refinery ones of 16 degree API grew. We’re going to be looking at railing coal into California. We have a contract with Exxon. Let me say heavy Canadian crude include in bitumen into California and that’s going into Bakersfield and down real pipe. So it’s not doesn’t require a new facility. ExxonMobil I believe is actually doing some of that as we speak, now of course that their oil coming out of the Edmonton facility with Kinder Morgan. But our preliminary analysis shows that to be economic and of course Torrance is a kind of refinery that can chew that up. It’s actually coal was actually a leading crude compared to what they are actually running in a Torrance facility. So I think we’ll be able to make some progress there, but it’s a little early in a game and until we really get insight and really play with it, we don’t know for sure how much we can do that.

We’ll go next to Blake Fernandez with Howard Weil. Please go ahead.

Guys, good morning. Tom, I need to keep going back on the Chalmette exports, it doesn’t sounds like you want to get too detail. But I’m just curious do you know, if there is a reason why Exxon wasn’t previously exporting from the facility with it. Is it just logistics based and kind of tying all with that, did your EBITDA guidance kind of contemplate the opportunity to export or with that potentially would be incremental?

We always had a strategy but we didn’t put anything in there. For that, so to the extent that we’re – they will execute this there would be some upside one of things I can’t tell you Blake is, and if it gets back to the maybe some of the disadvantages that had – the JV had because of difficulties. There is a marine vapor recovery unit there, which you need to certainly export gasoline. That was a disrepair and they stop exporting and having to export it for a long period of time. We went in there and we’ve put some money into it. We’ve got the marine vapor recovery unit running. That is open the door for the exports. There is more work to be done. But I think that’s probably the biggest reason. It was in a priority for the joint venture.

Got it, okay. And the second question back on the rail, obviously Bakken is kind of out of the money these days. I’m just curious longer term, how should we view that is that just kind of some cost or is there an opportunity maybe to lower the actual transport cost to where once the market finally turns back around maybe you’re all kind of changes as a result of lower costs or is there an opportunity to maybe even access other basins besides the Bakken just kind of longer term, I’m wondering how to think about that?

Well, a couple of things on that. I’d say, we look at both the Bakken and the Canadian and longer term question is, who knows what’s really going to be, what the situation will be a year from now. But certainly on the Canadian side, if Motiva or the Saudi put a bunch of Saudi crude into Motiva and start going down the path of trying to use that to – U.S. facilities or other facilities to monetize their crude. That could pressure up WCS. So, WCS could easily come back I think. Right now you’re spot on, there’s no economics in rail and Bakken. We have some unique economics as I said because it has pull on some of the heavier crudes. But we absolutely want the option to continue and to your point, we have been aggressively working with every counterparty in the supply chain on a rail side, see how we can get the cost down, whether it’d be doing something with our own cost, subleasing cost that we’ve got to lend, obviously working with the railroads on freight costs and their commitments. And we continue to see some success there and we’re going to continue to do it. So we believe we certainly think there’s an advantage to have the option.

We’ll go next to Doug Leggate from Bank of America. Please go ahead.

Thanks, good morning everyone. Guys and my good question to begin with, given what’s going on with gasoline margins or gasoline supply or other. It seems the imports seem to uptick a little bit higher year-to-date, I’m just wondering in Northeast in particular. So I’m just wondering in your region, what do you seeing from a macro perspective in terms of how weak margins globally are hitting the imports coming into the U.S.? Just wondering your thoughts on continued headwind.

Well, we certainly have seen some increase in gasoline imports over the last several weeks. Obviously at the same time, the New York harbor crack is remains a rather robust. And it is a good number that’s approaching $20 a barrel with some PBOB. I think the forecast that I’ve seen from my pioneers and everybody else is that there’s going to be some probable increase, not increase, but continued higher levels of imports into the East Coast. But frankly, sometimes that’s offset by reduction in movement of colonial that we’ve seen because of their exporting – the Gulf Coast is exporting a lot of gasoline. So we will see what happens, but right now we don’t see – two strong headwinds there are some, certainly there was 700,000 or 800,000 barrels of gasoline brought in the last year – last week and most of that is coming through – all of its base would come at Northeast.

Okay. I appreciate the high level question, Tom. My second one is really more specific to you guys. I just wanted to make I understood correctly. So the disruptions in the first quarter, was there any impact in Q2 or we fully – should we fully expect a more normal capture rate in your Northeast versus your benchmark in the second quarter?

The only thing that will expand into Q2, we said $75 million, let me just give you a little detail on the color of the $75 million in the first quarter. And that was basically about $26 million associated with the power outage of the hard shutdown that we had. It is about $40 million of delays on the turnaround because we didn’t execute it as well as we should have. And then the balance was moving the turnaround up further into the quarter. Beyond that Doug, we did have this politically incorrect, infinite mortality on the hydrocracker and it shut back down after we put it on stream. And as I said, that looks to be some where around a $10 million hit in the month of April.

[Operator Instructions] We’ll go next to Fizal Khan from Citigroup. Please go ahead.

Thanks, good morning, just a few questions. And if I go back to Jeff Dietert’s question and ask it more simplistically. Excluding Chalmette this summer, can you produce more gasoline than you did last summer?

Yes, certainly we could because last summer obviously we had pretty robust – more robust ULSD cracks as well. So I’d have go look at exact marketplace time. But my guess would be, yes, we could certainly take the steps that I’ve talked about and produce more gasoline at the expensive distillate.

Okay, got you. And then, but, I’m looking that your East Coast OpEx roughly 480 barrel, I compare that to other Gulf Coast refineries large scale Gulf Coast refineries, it looks like there’s still a large gap. What – I mean, what it can take to bring that per unit cost down? Is it reviving some of the idled capacity or is it something else?

I’m sorry. Are you talking about Chalmette itself?

Yes, that’s right.

Okay. Certainly bringing the idle capacity up will help. But as I said, we’ve got somethings that – we reduced OpEx versus what they’ve been incurred previously running. We think there is still some more room there. Candidly as we go forward, there is probably some further things that we could do and staffing and use some contractors or third-party people. We think we’ll get it done pretty close to what I – 150,000 barrel a day Gulf Coast refinery should be. It is certainly advantages that the breakdown Port Arthur Refinery that because of just their size, economies and scale. But we’ll get it done under $0.15 to $0.20 in probably in the next year just by doing some of the things that we have on our play.

Okay, thank you. And then a last question for me. Your comments around them on that could be rail to some curl into Bakersfield. Is that a new phenomenon that you are talking about, a new sort of initiative you are talking about doing or is that something that’s already being done today?

It has already being done. Exxon obviously at the Caulfield.

Sure.

Now, I think it moving both by [indiscernible] and by – and the way it is – it basically comes down by rail into Bakersfield and then it goes to the Plains, Plains pipeline that gets delivered to the power pipeline as well as I’m being correct to here, to get it delivery to the refinery. So that if we don’t require permits, we don’t require a new investment to do this, we just have to see the economic work. And there would be lend, that this refinery is not going to run 30,000 barrels a day list, but there is certainly probably 10,000 or 12,000 barrels a day that we would look to bring into the slate if the to be economic stays as they’re today.

Great. Thanks a lot. I appreciate the time.

And at this time, we have no further questions. I would like to turn the call back over to Mr. Tom Nimbley for any closing remarks.

Thank you very much for your attention today and everybody have a great day.

I would like to thank everybody for their participation on today’s conference call. Please feel free disconnect your lines at any time.