PBF Energy Inc (PBF) 2016 Q1 法說會逐字稿

Good day, everyone, and welcome to the PBF Energy first-quarter 2016 earnings conference call and webcast. (Operator Instructions). Please note, this call may be recorded, and I'll be standing by if should you 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, Erica. 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 describe in our filings with the SEC.

As also noted in our press release, we will 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 will 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 these 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 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 2 weeks of unplanned downtime at the 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 coker and hydrocracker turnarounds impaired our ability to convert our typically advantaged slate of heavy and medium crudes into salable 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 storm-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 weld at the hydrocracker. The unit underwent a normal shutdown; repairs have, in fact, been completed as of last night; and the hydrocracker is expected to be restreamed this weekend.

Given the prevailing market conditions, the Toledo and Chalmette refineries operated well under the circumstances. The Toledo refinery saw a 30% decline in its market crack, and the Syncrude-WTI differential widened significantly versus the fourth quarter. As we mentioned on our year-end earnings call, with gasoline margins approaching zero, we optimized our production in response to the market conditions. Currently, mid-continent cracks have recovered from their first-quarter lows.

Chalmette continued to operate well despite facing similar market pressures as our other refining regions. Chalmette has delivered positive results for the two quarters of our ownership, and we continue to explore opportunities to further enhance its profitability, including opportunities around Chalmette's logistical assets. We are also seeing the benefits of our more selective crude purchasing efforts for the refinery, and our commercial team has been successful in establishing new, high-end netback outlets for Chalmette's production.

In November of last year, we began the process of evaluating the optimal configuration of the refinery, given the potential of the currently idled units, consisting of a hydrocracker, naphtha hydrotreater, a reformer, and a light ends recovery plant. We have undertaken projects to evaluate the restart of several idled units, which would convert unfinished naphtha that is currently being sold out of Chalmette to high-octane reformate and ultralow-sulfur gasoline blending naphtha. We expect that this project could enter service late in 2017.

We have also begun the initial scoping work for a new crude tank which should reduce our demurrage and provide opportunities for additional waterborne finished product sales. We are continuing to explore a variety of options for the idle hydrocracker and will provide further updates as we proceed.

Before commenting briefly on the market, I would like to provide an update on the pending Torrance acquisition. Our expectations for closing the transaction remains consistent with our initial announcement, which was closed during the second quarter. As we have mentioned previously, the acquisition will only close once ExxonMobil has proven the refinery to be fully operational.

Going into the second quarter, we believe the outlook for clean products remains mixed. Year-over-year clean products demand is up approximately 2%, and average vehicle miles traveled statistics are up over 3% since 2014. We expect that demand will remain strong for gasoline in 2016. Distillate, however, is a bit more of a concern, and the current inventory overhang may take longer to resolve itself. However, certainly with the agricultural demand increasing over the last several weeks, things are improving.

Despite that, PBF is currently taking steps to increase gasoline yield and manage distillate yield by optimizing unit operations to meet market demands.

With that, I will turn the call over to Erik.

Thanks, Tom. Today we reported a first-quarter operating loss of approximately $65 million, an adjusted fully converted net loss of $67 million for 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 Colin 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 reported 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 a quarterly dividend of $0.30 per share, payable on May 31 to shareholders of record as of May 13.

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 throughput 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 terminals 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 transactions 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 time frame.

Operator, we've completed our opening remarks, and we'd be pleased to take any questions.

(Operator Instructions). Paul Sankey, Wolfe Research.

High-level question, if I could. We have very good demand for oil products in the US right now, and okay demand globally. I was just wondering what your perspective is on why margins were so poor in Q1, and why they are struggling along now. Thanks.

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, with the [obbs] having closed, with the pipelines and the arteries being built. And in fact, I think that's what happened, and certainly in the Mid-Continent. We obviously saw reduced demand, as is typically happens in that area, and that resulted in a poorer 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 turn around. And certainly the last several weeks -- two weeks does not make a trend -- we are seeing an increase in distillate demand, and the crackers responding accordingly.

Right. And then could you just 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. You've talked a lot in the past about the octane story. So could you just give us your latest view on how we work out 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 RBOB-PBOB spread in New York harbor 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 continued strength in gasoline cracks, per se, and that the PBOB -- or the premium gasoline spread versus conventional, or CBOB, will remain strong. And I don't really see that changing.

Phil Gresh, JPMorgan.

Actually, the 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 lost 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 expect it to close in 2Q, though it does seem like it's -- 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 on the balance sheet or available cash, ex-marketable securities at PBFX, how you are thinking about the funding for the transaction at this point, if you have any color there.

Yes, I'll take the first part, and ask Erik 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 are in the process of going through that. They are being very methodical, I can assure you, and we applaud 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 the process of doing that. But they have a very well-thought-out program on how to do that.

And then, very importantly, once they get the units lined out at the optimum rates or the high rates, that would start the restart criteria period, the 15 days. We will not take this facility, I want to affirm that again, over until we are satisfied that it's 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 will be roughly $525 million to spend on the assets. And we have 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 delever and pay down as we go.

Roger Read, Wells Fargo.

I guess 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 turnarounds, as well as just changes in product prices here?

Yes, the biggest change overall that we saw -- change 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 turnarounds. Then nominally $100 million of that, $110 million, was related to Delaware City. So, what we've done is that's essentially -- we just 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. There's 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 thinking about the financing of Torrance, and, to some degree, even of Chalmette. Logistics drop-downs, how does the market look here? You raised the 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 drop-downs of the logistics assets with those two refineries, the closed and pending one?

I think, look, 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 drop-downs 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 is 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's any need to go out and jam a drop-down into a market that still today 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.

Neil Mehta, Goldman Sachs.

So, the 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 of $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 them last October?

Actually, I'll take them one at a time. Chalmette, as we said, we've had -- been profitable in both of the quarters since we've owned it. 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 talked about last October, or late last year, on Chalmette. We've got a stronger crack now in the Gulf Coast. We would expect to see that continue the contribution. The reason I say we feel comfortable is the more we look at it, and the more we see it, we are 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 inroads in the commercial area. Remember that this facility was basically an integrated asset; big oil. It was there to serve the upstream of both PDVSA and, to a certain extent, ExxonMobil. We have entered new businesses already. We're into the asphalt business in Chalmette. We're going to be up to 10,000 to 12,000 barrels a day of asphalt production in June, with better netbacks than they were selling vacuum -- bottoms to their sister refineries. We're moving down the wholesale chain and trying to get better netbacks.

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 netbacks. I referenced -- we found, when we went into -- really got our hands on the refinery, they're spending a lot of money on demurrage because they have logistics constraints on the docks and some tankage limitations.

We're going to put in, as we did in Toledo, a tank -- a 450,000 barrel crude tank which we think is going to reduce demurrage significantly; and just as importantly, reduce dock occupancy to allow us to move more products over the dock, where we think we're going to get better netbacks than going into the pipe. And, frankly, on the idled units, I referenced the one thing that we're now focusing on as a high priority because it affects Tier 3. It could be a solution for Tier 3, but also provide margin.

So, as I said, Chalmette -- of course, they shut all these pieces of equipment down -- makes a lot of unfinished products that they sell into the marketplace. They sell 7,000 to 10,000 barrels a day of unfinished naphtha. We're going to look to start up this reformer and its attendant hydrotreater, and gas plant there that is going to take that naphtha, plus probably some additional naphtha from either crude or purchased naphtha, and run it through the reformer, turn it into octane, produce a low sulfur blending stock.

The important thing about the octane, the question came up earlier, is Tier 3 is going to destroy octane for the industry, simply because of the way most people are going to get compliant is to increase the severity on the hydrotreaters to get the sulfur out. When you do that, you destroy octane. This project is going to replace that octane and we will not have that debit. In fact, we will have additional benefits in Chalmette. So, Chalmette we think is on track and has perhaps further upside.

We're still early in the game in Torrance. We haven't got our arms around -- we haven't been in the facility in terms of operating it. We're in there now working with the ExxonMobil people hand-in-hand. But again, we remain pleased with what we've been able to do on the commercial side. The commercial plans are being put together. We certainly feel comfortable with the 360 and the assumptions that we made. Once we close on Torrance -- and hopefully by the next earnings call, that will clearly be behind us and we'll be moving forward -- we'll give you much more fulsome update on how we think it looks. We're going to have business plan reviews for the site here in the next three or four weeks, so that will flesh that more.

Thanks, Tom. Thanks for that [fair] answer. The second question I had is related to RINs expense. And just what type of RINs expenses should we be assuming, once Torrance comes online, as the run rate for you guys? Just trying to size the year-over-year impact or what a good run rate number is for RINs.

What we would say, Neil, is currently we're running at about $65 million a quarter in total RIN expense. That excludes the Torrance acquisition. And I think what -- we've included the RIN expense, and we need a little bit of time to sit down and review the business 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.

Chi Chow, Tudor, Pickering and Holt.

Growth is obviously a key component of your strategy. Do you think you need to absorb Torrance and then make further 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 Torrance. I feel that we've done very well on Chalmette. And hopefully with 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 all our resources there.

But we are comfortable that we'll be able to do that and a reasonable period of time such that it shouldn't really impact our ability to do another acquisition if there's an attractive acquisition that comes forward.

The state of the 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 will all depend on what becomes available, and what the bid/ask is. But we see the opportunity still being somewhat favorable. There's still a lot of pressure on majors because of the decline in flat price and the need to shore up their balance sheets. And one of the ways they may well do that is to divest assets, including assets in refining.

I don't think the majors are going to be acquisitive at all. One of the things that is -- obviously we're watching a little bit is what's going on with the announcement on Motiva, 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 a 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 slate, and squeeze a little bit more out of the margin, there going forward?

Yes, on the margin there is. I don't mean -- I mean, on the [anchor of mankind]. We're not going to be in a position to say we're not going to run Syncrude, because as you are well aware, it is a pretty good-sized percentage of our play. But we, in fact, are -- I think we're starting to rail some Bakken in, into Toledo, because the economics actually favor it. There's some other crudes that we're bringing in, 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 of, and we 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 operators go down and the Syncrude price goes $5 to $6 over. But we're not going to completely displace or even usually reduce the amount of Syncrude we're running, unless something really aberrant happens.

Brad Heffern, RBC Capital Markets.

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 don't want to tell you where they're going, because our counterparties have requested that we not disseminate that information. So 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 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 a 420,000 barrel cargo that we loaded out during the month of February or March, I can't recall. And again, that harbor's open, so we'll 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, at Chalmette, and the tankage constraints are 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 was any update on the hydrogen plant there, and if the attractiveness of that project just (technical difficulty) given the weakness in distillate.

The overall economics of the plant haven't changed at all, really. Remember, this is a -- to a very large extent, is a natural gas -- a gas to liquids project. You mine 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 -- hydrogen unit, and, therefore, increased hydrocracker rates at Delaware City is that you are not turning distillate into gasoline.

One of the things we're trying to do there, and we will be able to do, is take very low valued slurry oil from the cat unit that is basically being sold as a 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, 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 back attacking the project now.

(Operator Instructions). Jeff Dietert, Simmons.

I was hoping you could talk, in a little bit more detail, about your capability to shift towards maxing gasoline and not oversupplying the distillate market. We are 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. And I'll try to keep it succinct 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 all I'm saying there 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 very weak distillate 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 is that 50,000 barrels a day, what does it come about -- is really just two simple parts of it. And this is a little bit simplistic but it's pretty much on the money. One is simple fractionation. You just change the cut points in the various towers that carve up all the stuff that we run. And basically, for example on the crude tower, you can take -- you can change the temperature profile and drop naphtha into distillate, or 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, and drawing them off in a 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 into the gas oil streams. And, therefore, then that becomes a feedstock to your conversion units, particularly your 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 feed to the cat cracker. You'd make the same amount of gasoline effectively; but you'd reduce distillate make, and you'd have to back out feedstock, because the cat plant, for example, in this example, runs out of room. So you'd either back out PGO, gas oil purchases, or crude. So that's the way it comes out.

Got you. Makes sense. And now looking at your throughput guidance for the second quarter, it looks like you've got pretty healthy runs scheduled 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 it some, but we're still basically in more of a high percentage gasoline mode than distillate mode. But there's about 15 or 20 different steps. I tried to make it very simple. But some of them you would reverse earlier than others, depending upon what the spread is between gasoline and distillate. And as the distillate margins have improved here, we're looking at that.

At the same time, I think I said before, we watch whether or not we are actually selling the product or if it's going into tank. If it's 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 happen? So, we will watch the distillate inventories and gasoline inventories to see if this recent trend in distillate continues and demand keeps holding, or not. And that will dictate obviously how we play this.

Ed Westlake, Credit Suisse.

Yes, two operational questions, and then I'm going to come back to the balance sheet. Thanks for the time this morning. Just on the East Coast system, obviously very disrupted in the first quarter, and you had to run and do different types of crudes. But now that you are running more normally, still you've got inland sweets, and then you've 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.

If you take a look at the East Coast, and the key here is to get Delaware to -- and Paulsboro; Paulsboro ran well in the first quarter -- but to have the operations run. And that's the primary focus. If we do that, then obviously, Ed, you know that effectively Paulsboro is a 100% medium sour, heavy sour refinery. We're not running any light sweet crude at all in the Paulsboro refinery. We're running 100% of the mediums and heavies.

Delaware City will run about 40,000 barrels a day of Bakken is what the OP has been pulling. It is 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 being run to pull very heavy crudes and make kind of a dumbbell blend to allow us to run 16 degree API stuff, some of this stuff that's come in from Venezuela.

So, we won't be running very much sweet crude. We've said before, we believe that that was -- frankly is an advantage. But a PBF East Coast system 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 the capture rate might be? I don't have it 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 a Doha agreement or lack of Doha agreement. On the other hand, people are concerned about stability in Venezuela. Can you give us some color as to how hard you are 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 crude still out there. There's a lot of high bundle 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 a somewhat unstable situation, but it's not having an impact on us right now. And we have even been running some M100 and things like that, that will come back into the marketplace as economic. But right now, we have no issues on that side.

And then just in Torrance, it is there ability to switch that grade to something a little bit heavier and perhaps get some cash that way?

Torrance is -- basically, Torrance just runs heavy, period. We're looking at it, but the refinery runs a 16-degree API crude. We're going to be looking at railing Kearl into California. We have a contract with Exxon -- or let me say, heavy Canadian crude, including in bitumen -- into California. And that's going in through Bakersfield, and down via pipe. So it doesn't require a new facility. ExxonMobil, I believe, is actually doing some of that as we speak. Now, of course, that's 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 the kind of refinery that can chew that up. It's actually -- Kearl was actually a medium crude compared to what they were actually running in the Torrance facility. So I think we'll be able to make some progress there, but it's a little early in the game. And until we really get inside and really play with it, we won't know for sure how much we can do, Ed.

Blake Fernandez, Howard Weil.

Tom, I hate to keep going back on the Chalmette exports. It doesn't sound like you want to get too detailed. But I'm just curious, do you know if there's a reason why Exxon wasn't previously exporting from the facility? Was it just logistics based? And tying on with that, did your EBITDA guidance contemplate the opportunity to export, or would that potentially be incremental?

We always had it as a strategy, but we didn't put anything in there for that. So, to the extent that we are able to execute this, there would be some upside. One of the things I can tell you, Blake, is -- and this just gets back to maybe some of the disadvantages that the JV had because of difficulties. There is a marine vapor recovery unit there which you need to certainly export gasoline. That was in disrepair, and they stopped exporting, and hadn't exported for a long period of time.

We went in there and we've put some money into it. We got the marine vapor recovery unit running. That has opened the door for the exports. There's more work to be done, but I think that's probably the biggest reason. It wasn't a priority for the joint venture.

Got it, okay. And the second question, back on the rail, obviously Bakken is out of the money these days. I'm just curious, longer-term, though, how should we view that? Is that just a sunk cost? Or is there an opportunity maybe to lower the actual transport cost to where, once the market finally turns back around, maybe you [are] kind of changes as a result of lower cost? Or is there an opportunity to maybe even access other basins besides the Bakken? Just longer-term wondering how to think about that.

Well, a couple of things on that. I say we look at both the Bakken and the Canadian. And your 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 Saudis put a bunch of Saudi crude into Motiva and start going down the path of trying to use that to -- US facilities or other facilities to monetize their crude, that could pressure up WCS. So, WCS could easily come back, I think.

Right now, you are spot-on. There's no economics in rail in Bakken. We had some unique economics, as I said, because it has pulled 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 the rails, so I can see how we can get the costs down. Whether it be doing something with our own cars, subleasing cars that we've got lent, 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.

Doug Leggate, Bank of America.

Guys, a macro question to begin with. Given what's going on with gasoline margins -- or gasoline supply, rather -- it seems that imports seem to have ticked a little bit higher, year to date. I'm just wondering -- in the Northeast, in particular -- so I'm just wondering in your region, what are you seeing from a macro perspective in terms of how weak margins globally are, are hitting the imports coming into the US? Just wondering if that's a continued headwind.

Well, we've certainly seen some increase in gasoline imports over the last several weeks. Obviously the -- at the same time, the New York Harbor crack remains rather robust, and is a good number that's approaching $20 a barrel, with some PBOB. The forecasts that I've seen from, like, PIRA and everybody else is that there's going to be some probably increase -- not increase, but continued higher levels of imports into the East Coast.

But frankly, sometimes that's offset by reduction in movements up Colonial that we've seen, because they are exporting -- the Gulf Coast is exporting a lot of gasoline. So, we'll see what happens. But right now, we don't see real -- too strong headwinds. There are some. Certainly there is 700,000, 800,000 barrels of gasoline brought in last week, and most of that is coming to the east -- all of its basically coming to the Northeast.

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

The only thing that will extend into Q2 -- we said 75 -- let me just give you a little detail on the call-out of the 75 in the first quarter. And that was basically about $26 million associated with the power outage and the hard shutdown that we had. It was about $14 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, though, Doug, we did have this politically incorrect infant mortality on the hydrocracker, and it shut back down after we put it on stream. And as I said, that looks to be somewhere around a $10 million hit in the month of April.

(Operator Instructions). Faisel Khan, Citigroup.

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 to go look at exact marketplace time. But my guess we'd be, yes, we could certainly take the steps that I talked about and produce more gasoline at the expense of distillate.

Okay, got you. And then when I'm looking at your East Coast OpEx of roughly $4.80 a barrel and I compare that to other Gulf Coast refineries, large-scale Gulf Coast refineries, it looks like there's still a large gap. What is it going to take to bring that per unit cost down? Is it reviving some of the idled capacity, or is it something else?

I'm sorry; you're talking about Chalmette itself?

Yes, that's right.

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

Okay, thank you. And then a last question for me. Your comments around the crude being railed from Kearl into Bakersfield, is that a new phenomenon that you are talking about doing -- a new sort of initiative you are talking about doing? Or is that something that is already being done today?

It has already been done. Exxon obviously had the Kearl Field.

Sure.

And now I think they're moving both by water and by -- and the way it is, it basically comes down by rail into Bakersfield and then it goes through a Plains pipeline that gets delivered to the [Par] pipeline, as well -- I'm being corrected here -- to get it delivered to the refinery. So, we don't require permits. We don't require a new investment to do this. We just have to see if the economics work. And there'd be a [lent]. This refinery is not going to run 30,000 barrels a day of this stuff. But there's certainly probably 10,000 or 12,000 barrels a day that we would look to look to bring into the slate if the economics stay as they are 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.

We'd like to thank everybody for their participation on today's conference call. Please feel free to disconnect your lines at any time.