Valero Energy Corporation (VLO) Q1 2013 Earnings Report, Transcript and Summary

Welcome to the Valero Energy Corporation Reports 2013 First Quarter Conference Call. My name is John, and I'll be your operator for today's call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. Please note that this conference is being recorded. I will now like to turn the call over to Mr. Ashley Smith. Mr. Smith you may begin.

Thank you, John and good morning, and welcome to our first quarter conference call. With me today are Bill Klesse, our Chairman and CEO; Mike Ciskowski, our CFO; Joe Gorder, our President and COO; Gene Edwards, our Chief Development Officer; Kim Bowers, Chairman and CEO of CST Brands; Clay Killinger, CFO of CST Brands. And several other members of Valero senior management team. If you have not received our earnings release and would like a copy, you can find one on our website at valero.com. Also, attached to the earnings release are tables that provide additional financial information on our business segments. If you have any questions after reviewing these tables, please feel free to contact me after the call. Before we get started, I'd like to direct your attention to the forward-looking statements disclaimer contained in the press release. In summary it says that statements in the press release and on this conference call that state 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've described in our filings with the SEC. And so as noted in the release, we reported first quarter 2013 earnings of $654 million, or $1.18 per share. First quarter operating income was $1.1 billion versus operating loss of $244 million in the first quarter of 2012, or adjusted operating income of $367 million, excluding a $611 million non-cash asset impairment loss taken in the first quarter of 2012. The increase was mainly due to higher refining margins in the U.S. Gulf Coast, U.S. Mid-Continent and North Atlantic regions, plus lower refining operating expenses. Our first quarter refining throughput margin of…

Thank you. We will now begin the question-and-answer session. (Operator Instructions). Our first question comes from Doug Leggate from Bank of America Merrill Lynch. Please go ahead. Doug Leggate – Bank of America Merrill Lynch: All right, thanks everybody. I am going to take my two, if I may. Guys, can I ask you to clarify the $2 cost, the transportation cost at Quebec that you mentioned? Is that sustainable? Is it probably little bit for gathering and processing in the Gulf Coast? And can you maybe just help us, what is to make it simple for us, what is the advantage when you actually landed in Quebec versus your prior feedstock? And I’ve got a follow-up.

Okay, Doug, the $2 that we’re talking about is the transportation cost. It’s really the board flagship to take the crude from the port in Corpus up into Quebec. And I am trying to remember what the advantage was on a per barrel basis for running that oil. I think at the time we moved it, it was fairly even with the alternative, but I think what the guys found and Lane can speak to this, what the guys found when they ran the oil in that plant was it cracked very well and it was a strong yield.

That's right, exactly right. It had better yield than we had anticipated. Doug Leggate – Bank of America Merrill Lynch: All right, thanks for that. I guess my follow up is kind of a related question. We sort of move to some facilities in place over time to move crude to the West Coast, I'm just curious if you guys have got similar things in the works and actually you could fit in the context of how you see your deliberations over an MLP and ultimately how you would invest in infrastructure to maybe (inaudible), and I'll get down. Thanks.

All right, well Doug, relative to the supply in the West Coast, I mean we continue to look at the economics that move in pipeline barrels across. The number that we had is that we’re going to move those barrels into a U.S. port and put it on a U.S. flag vessel, or a (inaudible) vessel. The cost for the shipping becomes very high and so the alternative that we’re pursuing and perhaps we continue to look at that, but the alternative that we’re pursuing is to go ahead and do the rail economics and that's why we've got the train activity, we bought all the railcars and we were looking at rail terminals in Benicia and also down in Wilmington. And we find that taking it directly in to the refinery we have as good or not better economics that we would take it across in a pipe to the West Coast and put it on a U.S. flag vessel. Doug Leggate – Bank of America Merrill Lynch: Okay, have those qualified for a potential MLP drop downs over time?

Yes, they would. Doug Leggate – Bank of America Merrill Lynch: All right, great talking to you guys, thank you.

Thanks Doug.

Our next question comes from Jeff Dietert from Simmons & Co. Please go ahead. Jeff A. Dietert – Simmons & Co.: Good morning.

Good morning Jeff. Jeff A. Dietert – Simmons & Co.: Congratulations on the progress on CST and for optimally approaching the distribution. I had a question on the potential for an MLP, you’ve obviously got a lot of growth capital focused in the logistics area with Quebec and then an additional $200 million of logistics projects in the railcars and rail unloading facilities. Could you talk a little bit about the existing base of MLP qualifying assets and how realistic potential MLP might be?

Jeff this is Klesse. We’d say consistently hear that once we finish with retail spin, then we would look at the MLP. And that’ what we intend to do, and I have given in the past that we have an EBITDA base of 5,200 million. So I think at this point in time that’s where we’re going to stay. Jeff A. Dietert – Simmons & Co.: All right, all right, I understand. I was curious if I could have a quick follow-up, if you are seeing pricing differentials for domestic crudes in Houston given a Seaway and rapidly approaching Permian pipelines coming into the Houston area. Are you seeing those crudes trade at a discount to Louisiana, and by how much?

Well, it’s anywhere from $1 to $2, but we are seeing the crudes traded below LLS. In fact I don’t think we’re running the Light Sweet crude in the system, certainly in the Gulf it’s not trading at a discount to LLS. Jeff A. Dietert – Simmons & Co.: Are you expecting bottlenecks at Houston as these Permian pipes and then ultimately Keystone comes into the market?

I think that you’re certainly going to have ample supply of these crudes in the Gulf. As far as the bottlenecks, I think they’re working very hard to elevate that now. I guess we’ve got a long hard point start up that’s going to bring 75 a day and then up to 225 here very soon. Seaway is working on resolving their issues, and the host of other alternatives. I do think, we’re going to see ample supply throughout this heavy sour crude in the Houston market. Jeff A. Dietert – Simmons & Co.: Thanks, Bill. Thanks, Joe.

Okay.

Our next question comes from Robert Kessler from Tudor, Pickering. Please go ahead? Robert Kessler – Tudor, Pickering, Holt, & Co.: Good morning, guys. One quick follow up to that prior question, in terms of the price, average price delivered in the Corpus, say relative to Houston or relative to LLS. Is Corpus still below Houston, and if so, by how much?

It is. It is basically by a transportation cost over their. Robert Kessler – Tudor, Pickering, Holt, & Co.: So another $1.52 or more than that?

Yeah. Robert Kessler – Tudor, Pickering, Holt, & Co.: Okay. And then looking a bit longer term at Quebec City, after you come out from the turnaround and maybe on in through the end of 2013, assuming the price differentials and relative yields for the Eagle Ford crude, justify replacement with the alternate supplies, how big could that be, what portion of throughput at Quebec City could you be running from say, Texas based crudes by the end of the year.

Well, our license that we got was for 90,000 barrels a day. And so that’s the existing license that we have. But the crude as Lane said, we’re very well into refinery. I’d say to you though because obviously we’re involved in Line 9 reversal, and that refinery will be on all North American crude oil here within the year or so. Robert Kessler – Tudor, Pickering, Holt, & Co.: And then last one from me, just coming back to the say MLP-able CapEx, if I look at your 2013 budget, would it be fare to say that about $400 million at least of that would be MLP-able spend or what kind of number would you throw out there?

The number is more or like, it’s between $500 million and $600 million. It is what we have in our 2013 spend. Robert Kessler – Tudor, Pickering, Holt, & Co.: Okay, thank you.

Yeah.

Thank you.

And our next question comes from Roger Read from Wells Fargo. Please go ahead. Roger D. Read – Wells Fargo Securities : Hey, good morning

Hey, Roger. Roger D. Read – Wells Fargo Securities : Guess, I’d like to first hitch you on the operating cost, the $4 that you mentioned obviously higher natural gas. So just wanted to kind of confirm is that effectively the natural gas cost or is there something else going through, because obviously with the higher throughput expected in Q2, with kind of on a per barrel basis maybe see that a little lower than Q1.

Yeah, that’s a key part of that increase.

Hey, this is Lane Rigg, the only other part to that is, that Quebec which is one of our lower operating cost refineries, is in a big turn around that you have their capacity at lower operating cost. Roger D. Read – Wells Fargo Securities: Okay, all right, that’s helpful. And then, understood that and very helpful with the Light Crude that you’re running on the Gulf Coast at discounted LLS, I was wondering if you could help us understand something what’s been moving around the light, heavy spread more or less from the beginning of this year through early I guess April or compressed and that’s widened a little bit since then, but we’ve heard different stories, that we’re were in and out of the market, Venezuelan crudes. I was just wondering what you all have seen along that line.

Yeah, all right. Well, relative and you’re really looking at Maya pricing when you’re talking about the heavy sour. But WTS strengthened with the longhorn of startup and essentially WTS realigning itself with WTI, you remember last year we had that huge discount of TS to TI and that certainly helped to expand that Maya discount. The other thing we’ve had is, WTI has strengthened relative to Brent and so, as that come in, you’ve had the whole heavy sour complex come in and draw closer to a WTI price crude. And then you got the final factor that’s the K factor has lagged and they’ve used that, PEMEX uses that to adjust the price of their crude to kind of keep it at a market parity with alternatives and they’ve lagged, and they’re limited as to how much they can move it in a month without going before the government to get approvals and so they’ve just lagged. Now, we know we’re going to get an improvement next month. So, this discount will improve further, but those are the three primary factors that affected the heavy sours. The medium sours have improved just recently, that’s really a result, I think of a lot more Middle Eastern crudes being into Gulf. And we had our guidance estimated and we’re from 8 million to 10 million additional barrels, we are in the Gulf during the quarter. So that helped that. And then, when you look at longer term, I think there is certain refineries in the Gulf that were going to end up running a lot more Arab crude than they would have Maya crude or a domestic medium sour crude and that’s going to put more of it back in the market. And just as a more general statement, anytime you end up with more crude in a particular market is going to put pressure on the entire complex because you’ll look at substituting. And since the extent that we move Midland barrels into the Gulf, and there is susceptible to Houston refineries and other refineries, you’re going to see additional pressure on both the medium and the heavy sellers. Roger D. Read – Wells Fargo Securities: Okay, thank you.

Our next question comes from Paul Cheng from Barclays. Please go ahead. Paul Cheng – Barclays Capital, Inc.: Hey, guys, good morning.

Good morning Paul. Paul Cheng – Barclays Capital, Inc.: Two quick question, one is a simple accounting question for Mike. After the 80% spinoff of the CST, the remaining 20% are you going to report them in terms of the P&L on the equity accounting or do you going to report that at course and only report P&L from May, if you receive any dividend?

No it will be on an equity and earnings basis. Paul Cheng – Barclays Capital, Inc.: In an equity earning basis. And that for the next several years, I think previously you guys were talking about somewhere in the $2 billion to $2.5 billion tie-off of CapEx and this year is higher. On a going forward basis, that with some of the new growth projects, should we assume that you’re going to be higher than that range now?

Paul, this is Klesse. We are higher this year because we do have quite a few logistics projects that we kind of discussed a few minutes ago. And they will carry over into next year some of them, but the guidance I have only given is the next year in $2.5 billion range, and except for some carryover of these type of projects, it will be in that $2 billion to $2.5 billion range with some carryover of logistics projects. The whole business today is about location, location, location, and if you don’t have the location you have to have logistics. Paul Cheng – Barclays Capital, Inc.: I totally understand. And a final one on maybe this is for Lane. Butane and naphtha, there is a lot of concern in the market that the debate is going to become increasingly abundant, and so itself become a (inaudible). So the question is that, do you guys already at this point in max in terms of how much you can grand, I presume Butane is going to restricted by the RVP and naphtha don’t’ know whether there is anything you can do in terms of increasing your net branding volume if the price is attractive?

So the question is the naphtha like that all refiners are seeing. And that’s correct. And you are seeing more what I’ll call low octane blend stocks coming toward the refiner from the NGL piece. So for us in particular yes, we are blending the naphtha where we have enough octane. Also what’s happening is as the price of naphtha which we expect what you said to occur as well you’ll go ahead and restart or increase your runs through your rate former. But even though we want to make hydrogen from natural gas the facts are because the naphtha pricing you may go ahead and run your reformer as well. So we are doing that and looking at that, and then it depends on what severity you actually run at your reform. And then of course the last option is that naphtha could potentially be exported. And we as everybody else in our industry, we will look at all of those numbers and pick the best course. And that’s what we are doing and I’m sure everybody else is. Paul Cheng – Barclays Capital, Inc.: Here we are standing, can you provide under what circumstances that you really choose one option, or that has too many moving part that can’t really give one rule of thumb.

Well you really have to run it through your models to be honest with you, but I suspect first option is the buoyant, the second option it will be to run our reformer. And the third and run it at different severities. And then the third option is meaning you just can’t get rid of it internally that the price will be the option will be to export. Paul Cheng – Barclays Capital, Inc.: Thank you

That’s all I agree.

Our next question comes from Sam Margolin from Dahlman. Please go ahead. Sam Margolin – Dahlman Rose: Good morning, thanks for the time. You touched on Maya, I just want to revisit it for a second, I mean it looks like the composition is really outmoded here, given the fact that all the components have a kind of dislocated from each other. In the past, you’ve had a lot of success pricing heavy barrels in the Gulf away from that benchmark. And you touched in a little bit with the pipeline capacity going into the Gulf maybe devoted a little more to the heavy side. I was wondering if you just provide a little bit more color on the opportunity set for heavy crudes underneath what we’re seeing on the Maya side

Well, I mean, we are seeing heavy crudes moves up right, we’re moving it by barge, we’ll be moving it by rail in the St. Charles. And we’re seeing some come down the Seaway that’s get consumed. Then you go back to the more tradition, there is going to be more there from the U.S. and actually from North America. Then you look into towards South America, the traditional sources. And we continue to be a large purchaser of crude from South American producers and even though those crudes have a Maya basis there is agreements that we haven’t place that vary the price on that. And so, we’ve been able to continue to get heavy sour crudes priced in if Maya prices are better.

Maybe I’ll add a little more for you. So when you look at the Mississippi River, we’re doing what others are doing. We are barging every crude down and also we are looking at rail facilities to bring into our St. Charles and those refineries. If you start to move west of course Keystone pipeline is being built to southern Lake and that’s where and Joe speaking of seeing more heavy crude come down. We expect to see heavy crude come into Port Arthur, as well as more in the Houston through all of the other pipelines and of course Keystone. Then you jump back and when there is a foreign imports, you have to look to Venezuela and what actually happens in Venezuela as we go forward, and when they have had and this is the truth, when they have operating issues with some of the upgraders things like that we get to see more of these type of oil that we can process in our hardware available. So you have all this moving parts, but generally speaking Valero wants more heavy sour crude oil in the U.S. Gulf Coast because we are a big border. Sam Margolin – Dahlman Rose: Okay. Thank you so much for the color. And just sort of as a follow-up Keystone potentially facing another delay here, but as a lot of investment moves into the rail side and that seems to be taking up a bigger and bigger share of uptick and these disadvantage basins, I was wondering if you had done any planning or thought about the raw bitumen element as well moving sort of away from WCS and getting it in as a raw material particularly if there is any local blending opportunities for you around your Gulf Coast system?

Of course. Sam Margolin – Dahlman Rose: Sorry, go ahead.

I’ll try to answer part of this. Of course we have, we still believe Keystone now (inaudible) with the Northern Lake XL, we still believe that we’ll be approved and it will be built. It’s a pipeline. This has nothing to do with the pipeline. It’s all about the oil sands. And just a little trivia here, the carbon, the greenhouse gas emissions from produce and California having crude are actually higher than it is for the oil sands and one coal power plant produces like 25% of the greenhouse gas emissions from the oil sands. I mean, this is all just ridiculous conversation that’s going on. But part of the railcars that we have purchased are insulated and coiled, so that we can move the raw bitumen just as other companies are trying to balance between WCS and Bakken and those type of crudes as well as the pure bitumen. And so we’ve try to estimate how we will supply our refineries down the road and have purchased our railcars accordingly and those railcars will be delivered to us really through the end of 2014. So they come to us every month. Sam Margolin – Dahlman Rose: All right. Thanks so much everyone. Have a great day.

Thanks Sam.

Our next question comes from Evan Calio from Morgan Stanley. Please go ahead. Evan Calio – Morgan Stanley & Co. LLC: Good morning, guys.

Good morning, Evan. Evan Calio – Morgan Stanley & Co. LLC: Yeah. Sorry if I missed some of the opening comments, but, I mean can you provide any additional color on hydrocracker issue at Port Arthur in the quarter and whether it rolled over into the second quarter, and just confirm you remain on track for the St. Charles start up.

Well, hi, Evan. This is Lane. So we had an emergency shutdown valve that we, it wasn’t working properly. So we had to remove it and had to shift off. We found there was a manufacturing error in the valve and actually we’re able to take one from St. Charles or St. Charles projects who are essentially carbon copies of one another and put it in place and so this was all like and actually, this was really sort of a March conversation. So now we’re running fine and don’t expect this to have any implications for the second quarter.

And we’re so lost to seal on a compressor when we had a power failure sort and…

Yeah, the initiating event for when this – we had a (inaudible) compressor trip on a lost field and that caused this emergency shutdown valve to close and then it wouldn’t open.

So those have been repaired and that part of the project is going just fine as Ashley said and at St. Charles it’s going to be late second quarter. We’ll get oil in the year, but we’ll really be starting up in July. And we are having in a sense of difficulties getting this job done, but it’s not through lack of effort. Evan Calio – Morgan Stanley & Co. LLC: Okay. Got it. I know you guys quantified potential RIN exposure year-on-year. I was just curious if there was any strategy to mitigate that number? I noticed Diamond Green start up. So obviously going to give you incremental, more valuable diesel RINs and, I don’t know, but building new terminals to blend anything else that you’re doing that could mitigate that potential cost.

Evan, we’re looking throughout the system to just find every opportunity that we can to blend more. We continue to look at the economics on every export cargo to decide if ARB is better to keep it here to go ahead and put it on the water considering the cost of the RIN. We’ve adjusted product yields throughout the quarter and we’ll continue to do that. For example, we produced more jet when it was economic to do that, but the economics don’t favor that today. So we moved back and then we’ve got a very aggressive effort to try to support, change to the regulations as they are and you may want to talk more about that, those activities. But, I mean, we are working those issues in every way we can just to try to make this problem less of a problem for us. I think we’re still very comfortable with the estimates we’ve given you for this year and that’s $500 million to $750 million range. But the squeeze that we’ve had that’s driven the prices up where they are is going to be with us unless we get some kind of relief.

I think what I would here is the way Joe is describing this is what RINs have become as part of our cost to manufacture and then in our decision making. So if you have a $0.60 RIN or whatever it is, $0.50, $0.60, $0.70 today, it becomes, gets into our cost to manufacture and then it works through all our modeling, so that that helps you drive your LP economics and that’s really the point here. It gives you more of an incentive in this, for instance, to make jet fuel and diesel or whatever, and that’s how it works through the modeling. Evan Calio – Morgan Stanley & Co. LLC: Great. Then lastly, if I could, and I know you’ve benefited from some distressed event cargos that were in the market last couple of quarters. So maybe you’ve seen that, and are you still seeing some volume there or have they have been pulled back given kind of MA is back up and running? That’s it.

Well, yes. I think we continue to see them from time to time. And it’s certainly not ratable, Evan. So it’s really kind of hard to say whether it’s more or less than it has been or when that might change, but they’re is still available. Evan Calio – Morgan Stanley & Co. LLC: Got it. Appreciate it, guys.

Our next question comes from Blake Fernandez from Howard Weil. Please go ahead. Blake Fernandez – Howard Weil: Hi, guys. Good morning. I had a balance sheet question for you, I suppose. Ashley mentioned the debt reduction of $300 million of notes later this quarter. Obviously you have some cash coming in about $850 million or so. From the retail spin, Bill, I know you had talked about maintaining a more flexible balance sheet post the spin off of retail. Can you give us a sense of once you get the cash in hand and then pay off the notes that you referenced, how should we think about additional debt reduction from here?

Well, for just the question on debt reduction, this is all the debt that we are maturing this year. So that will leave Valero with about $6.6 billion of long-term debt. Next year we have about $200 million of maturing debt. I would assume we’re going to pay that off. The year after that we have $500 million in the next year. That, at least today I would tell you we would pay off. So that takes out quite a few years, and that’s the maturing debt. As far as calling debt, we do not have any debt that is economic for the company to call. So, that’s to your question. I think you asked me a little broader question and that is I don’t know where you came in the call, but so far this year we’ve brought over 9 million shares of our stock. We’ve been out of the market obviously the last few weeks as we have to be. We’ll be out of the market for a while here while this settles out with CTS, but we think our stock is still undervalued and we, as Ashley said in this comments, we’re returning cash to our shareholders. Blake Fernandez – Howard Weil: Perfect. Thank you on that. The follow-up question I had for you on the kind of the incremental hydrocracking expansions. I’m just trying to see if I can get a sense of how that may potentially impact the overall company-wide yield. I know you guys had some charts in your slide pack showing the changes in distillate yield over time. I’m just trying to get a sense. Does this have a kind of order of magnitude impact to change the overall yield?

Yeah, the numbers that we’ve shown you in our presentations after the two hydrocrackers would take us up to about 39% of the total distillate yield. And I’ve mentioned in the past that when we finish these expansions and do our conversion at [Morro] we’ll be into the low-40s%, I’ve used as 42%, 43% of our yield. And really for Valero, we’re kind of unique then at that point because we’ll have a gas to distillate ratio of about 1:1, which is very unusual for a U.S. refining company. Blake Fernandez – Howard Weil: Perfect. Thank you, Bill.

Our next question comes from Chi Chow from Macquarie Capital. Please go ahead. Chi Chow – Macquarie Capital, Inc.: Great. Thank you. This may relate to Evan’s prior question, but in the first quarter it looks like your realized margin capture rate in the Gulf Coast was strong again, even with the high levels of maintenance. Did you realize the same dynamic in the fourth quarter with capturing the stranded heavy barrels or was there something else that drove the capture rate?

Chi, the biggest driver, the single biggest driver by the addition of the new hydrocracker at Port Arthur and that’s just a high margin unit. And after that we saw some nice discounts on some of the distressed heavys and some of the things we’ve benefited from in the fourth quarter, but the number one by far was adding the hydrocracker. Chi Chow – Macquarie Capital, Inc.: Okay. How much heavy Canadian crude did you bring down in process versus prior quarters?

It was about the same, Chi. I mean, we were in the 45 to 50 range on average, in other word, periods there that we had much higher volumes and we’re expecting those volumes to ramp up going forward. but it wasn’t materially different than fourth quarter. Chi Chow – Macquarie Capital, Inc.: Okay. Thanks, Joe. And then, on the RIN issue, Bill, can you give us an update on any discussions that Valero or other industry groups have had that you’re aware of with the EPA on any relief from the RFS mandate and how any of these [slobbing] efforts are going?

Well, I can give you some color. I was in Washington last week with a group of other refiners and a couple of majors. Our industry is united here in trying to get awareness that the RINs issue when it was $0.05 a RIN was one conversation and when it rapidly increased to over $1 and has fallen back here, it’s another whole issue. We met with as an industry here. We met with several Congressmen, some Senators. They all realized that the RFS is broken and needs to be fixed. There is no cellulosic to speak up. I think somebody is going to make a little this year. The advanced is kind of alluded price that you ought to buy. Brazilian sugarcane ethanol and export corn-based ethanol is kind of alluded (inaudible) so people realize that. As far as the White House and the EPA, they both realized as well, we met with them that there is an issue, but I’m not going to say that anything is going to be solved here in the short run. Chi Chow – Macquarie Capital, Inc.: Okay. Do you believe these discussions, when do they gain steam again? Is it dependent on rent price cost inflation or is that winning the next battle kind of wages or is it maybe late this year when the EP actually takes a look at the obligations for next year, then you spent some time in?

Well, theoretically we don’t hit the blend wall this year anyway, theoretically… Chi Chow – Macquarie Capital, Inc.: Right.

So this is more of a precursor of things to come. You don’t hit the blend wall next year. There is a realization that E-15 is not the solution. When the EPA tested E-15 they really only tested the machine systems. The facts are on the API ran tests and out of the three major carburetor fuel pumps in the cars today one of them failed 11 out of 12 times. So, there is now this awareness, AAAs has come out that’s going to these higher ethanol percentages will not work in the car fleet. I think 95% of the car fleet is not warranted or so for a higher ethanol content. So, I think what you have is an awareness that this has to be addressed. There is going to be or scheduled to be hearings. I think it’s in the House Energy Committee here later this summer, but it’s like all things in life, squeaking wheel gets degrees, and when something starts squeaking whether it’s high rent price, high gasoline prices, high something, there will be a lot more attention. Chi Chow – Macquarie Capital, Inc.: Okay, just one question on E15. Does the EPA acknowledge that that is not a solution or are they still with the mindset that their tests are valid that they conducted on the vehicles, any sense there?

I would not have an answer. They are aware that there is this large, where they aware that the cars manufacturers had not changed their warranties and they are aware of this fuel pump issue. So, but I don’t know if they’ve said anything else. Chi Chow – Macquarie Capital, Inc.: Okay, okay, great, well thanks Bill, I appreciate the comments.

Yeah.

Your next question comes from Paul Sankey from Deutsche Bank, please go ahead. Paul B. Sankey – Deutsche Bank Securities, Inc.: Yeah, Bill, I’m so sorry, I mean, I hate the subject myself, believe me, but it seems like we have to going to get into 2014 before we get a resolution on this and that’s when the crisis, it has to become a crisis essentially before we get a solution.

Well, I suppose that’s right. Paul B. Sankey – Deutsche Bank Securities, Inc.: Okay.

Now, I do say, there are going to be hearings, and there is an awareness that there is a problem growing that is of significance. So, you do have awareness, the rest of this is, I am just an engineer working in an oil company, refining company here, you tell me about politics. Paul B. Sankey – Deutsche Bank Securities, Inc.: Well, as you know we look to you as the spokesman of the industry Bill, with this regards what Washington is going to do and I think you’ve been quite clear on this. I am just worried that the EPAs poorly, arguably prefers high gasoline prices for efficiency reasons and the politicians aren’t concerned because the gasoline price is relatively low.

Well, I would not disagree with the second part of that, I would not put where it’s in the EPAs mouth that they run high gasoline prices. Paul B. Sankey – Deutsche Bank Securities, Inc.: Okay, certainly change the subject. You’re pursuing obviously that the organic projects that you have, is there anything on M&A asset market transactions. Obviously you’ve been busy with the CST thing, but is there anything to say about any other potential changes to your asset base at refining level I know you’ve referenced pipelines and trains? Thanks.

Paul, this is Gene. There is pretty slow activity on the M&A right now. I think the issue is the U.S. refineries almost everybody is making money now or they still be making money in the future as these cheaper crudes become available. So that’s really not allowed on the market to couple the where on the market got pulled off, that’s just probably aware off. And then Europe there is some things for sell over there, which you got to look at the European situation as they become the marginal player in the world without the cheap crude, and without cheap natural gas. We got to be top tier basically to be a survivor in Europe. So there is limited activity obviously right now in the whole western hemisphere. Paul B. Sankey – Deutsche Bank Securities, Inc.: Great stuff. And then finally from me on export, can you, there is some concerns that the new capacity in the Middle East and other additional supply globally may threaten the export story. Do you guys have a view on that? Thanks.

Well I think as the [Saudi] refinery comes online part of its parts will clearly be directed to the Houston Mediterranean and into the Med. Clearly some of the Indian Reliance players have moved that way as well as moving to South East Asia. You also have some Chinese projects that are coming online. But I think you have to come back to lease the U.S. Gulf Coast capability here to be very, very competitive. And so if you look at our natural gas cost relative to other refiners, if think about the crude and at least the differentials that Joe spoke to earlier against world markets, there is no doubt in our mind. Even though we’ve had now I will ask about Brent and other things happening that eventually all less is going to go below Brent. We really do believe that this is what’s going to happen. So our crude situation, pricing is very strong. And then you look to new refinery construction, the Brazilian refinery that I guess is going to get done some time here, they’re now up to 16 billion to 20 billion for a 230,000 barrel a day refinery. I think any, and those economies are growing whether it’s Mexico, Colombia or Brazil. So any of these guys that have talked about building a refinery like Ecuador, I just find it personally extremely hard to believe that those countries will spend money to do that. So I think that U.S. Gulf Coast can compete very well into those markets and I think we’ll still send this to Northern Europe. So I think we’re competitive. I think the markets are there for us and U.S. still is a huge market that consumes product as well. So I think you have to have the export markets otherwise U.S. refinery operating rate is going to drop significantly. Paul B. Sankey – Deutsche Bank Securities, Inc.: Yeah, we tend to agree, Bill and it’s worth noting that the market cap of your company is not far from what that one refinery this system is going to cost in Brazil is going crazy. Anyway thanks a lot.

It could build one - you could still we’re not for sale, but you could buy all of the Valero for about 1.5 refineries, crazy. Paul B. Sankey – Deutsche Bank Securities, Inc.: Yeah, thanks Bill.

And our next question comes from Faisel Khan from Citigroup. Please go ahead. Faisel H. Khan – Citigroup Global Markets Inc.: Thanks, just quick question on the McKee turnaround is, when the turnaround is complete is that going to result in any increasing your distillate processing capacity or sorry distillation processing capacity or that’s still a second quarter 2014 event is that right.

(inaudible) we have a little bit of because the unit was sort of not performing at its best, as went into the turnaround so we’re gaining some capacity back on crude distillation we’re putting in this energy efficiency project, which allows to improve the yield of diesel off the unit, but yes the expansion that we spoken about the last year call and investor relations is really is in the 2014. Faisel H. Khan – Citigroup Global Markets Inc.: Okay

Okay, we’re waiting on the Greenhouse gas permits.

Yeah, we do not have the permit is the reason. We have to get our permit. Faisel H. Khan – Citigroup Global Markets Inc.: Okay, what is the turnaround time for permit, when did you guys filing when did you, when would you expect to get a permit.

I don’t know when we file. But, the way it’s going now because Texas is not issuing the Greenhouse Gas permit because we have this dispute going now, this is Texas. Faisel H. Khan – Citigroup Global Markets Inc.: Okay.

I’ll tell you it’s two years. Faisel H. Khan – Citigroup Global Markets Inc.: Okay, understand.

Just like California, just like the East Coast. Faisel H. Khan – Citigroup Global Markets Inc.: Okay, got it. Thanks guys.

Not true, that’s not true for some other states.

And our next question comes from Ed Westlake from Credit Suisse. Please go ahead. Edward G. Westlake – Credit Suisse Securities LLC: Hey, two questions, first one is going to be around turnaround schedules and the second one is on your self help. Just on the turnarounds, it feels as if you are still doing quite a heavy amount of turnarounds in the system in the first half of this year, is 2013 characterized as a sort of a heavy year, and then it gets a bit better for '14 or '15 or just give us some color potentially.

This is Lane again, it is a little heavier than I would say our average year is, and we don't have any really big turnaround other than finishing this Quebec turnaround up here in June literally for the rest of the year. Next year is a little bit more towards our average turnaround, which as you know, so we give (inaudible) it's about $600 million year on, somewhere between $400 million and $600 million a year, we are on the $600 million a year side, we’re a little bit lower than that next year, but with the range of turnaround work. Edward G. Westlake – Credit Suisse Securities LLC: That's helpful, and then just on these crude topping facilities, $250 million I guess is the average, any idea or sort of a pay back period for those types of things, and they really sort of looking at splitting off the light ends and then exporting the light ends or moving them around the system.

The pay back, of course we make sure it depends on your assumption as to the crude pricing. Edward G. Westlake – Credit Suisse Securities LLC: Yes all right

They have IRS in the over 30% there. And it's based on our assumption as to these discounts, but then the second piece of your question, no they are not. The two that we’re looking at Corpus Christi and Houston. Today those two refineries are short crude fractionation, we buy stuff. So at Houston we have a very large cracker, we buy feed for the cracker. What we are doing in Houston is by building this crude topper fractionator we’ll make our own feed for our conversion units down straight. Historically in the business, you didn’t really make any money on crude fractionation, you made money on conversion units. So we have a couple of refineries including Wilmington for instance that has a lot of conversion, not a lot of crude fractionation, because it was economic to buy feedstocks. If you are in a world where you have depressed crude oil prices relative to the feedstocks see that there is an incentive to make your own feedstocks and that’s what we’re early doing at both points. Edward G. Westlake – Credit Suisse Securities LLC: And then doing some math, I mean these hydrocrackers expansion that’s about another 50,000 barrels a day. So slightly under the $0.5 billion that you might get from the current hydrocrackers you get the 30% payback on these crude top facilities some crude up in Quebec. And then you’ve got that maybe $19 million depends on the TI Brent for McKee, I mean all adds up to another sort of $750 million to $1 billion of potential EBITDA improvements and say 2015 as the next round kicks off. Is that a fair reading?

It’s a fair reading in the sense of you have to make your own assumptions, but as to these differentials making more distill, what’s the distillate crack. But these are why we’re doing those projects we think they fit exactly with how the markets are shaping up. Edward G. Westlake – Credit Suisse Securities LLC: Thanks, guys.

Our next question comes from Arjun Murti from Goldman Sachs. Please go ahead Arjun Narayana Murti – Goldman Sachs & Co.: Thanks. In your release you mentioned intention in certain refineries to increase the front end flexibility to process more light sweet crude I apologize if I missed any of your remarks. But any quantification of capital requirements and incremental light sweet crude runs from those efforts

Yeah, Arjun this is (inaudible) we’re just talking about these front end, the topping projects. Arjun Narayana Murti – Goldman Sachs & Co.: Yeah.

So that Corpus and at Houston that Bill is explaining, were crude short first with the downstream and they’re $220 million to $280 million a piece and incremental crude is, I guess Houston 90 day and Corpus is…

70.

70 a day, 70,000 barrels a day.

But we have other things going on just and I’m going to tell you just like everybody else in where we’re pushing out medium type crude oils throughout our system to put, be able to handle more of the light crudes. And so, we can run in our system now. I think it’s 680,000 barrels a day. I know we have…

Yeah.

680,000 barrels a day of lighter sweet crudes in our system and we have other projects underway to debottleneck here change and exchange there, move some of the light ends over here and we have quite an effort going on in our engineering groups because we believe this oils is going to be discount. Arjun Narayana Murti – Goldman Sachs & Co.: And I guess the big thing was to ensure you kind of don’t lose on utilization, the op cost don’t go crazy. It sounds like you’re that’s the purpose of these projects, you can maintain utilization rates and the op cost will still look reasonable.

Well, the purpose is to make money. Arjun Narayana Murti – Goldman Sachs & Co.: Yeah.

And so we’ll run and outpace, I would not say to you in other words if we’re making more money and our operating costs go up for a barrel basis, I guess I say so why. Okay. So we would be focused on a) we have to hit ex-op cost. What we would want to do is make more money overall. Arjun Narayana Murti – Goldman Sachs & Co.: That makes sense. Thank you so much

Our next question comes from Allen Good from Morningstar. Please go ahead. Allen Good – Morningstar Research: Good morning and thanks for taking me. I would run along. Just, I guess as a follow-up question as well on some of the indicated investment for the increase in the export ability as well. Can you remind me what your current export ability is now and where you see that moving to over the next two or three years?

Yeah, I mean, I think if you look at gasoline today you’d say we could accommodate 225,000 barrels a day and we’ll feel like take that up to 250,000 barrels a day or more going forward. And then diesel, it’s about 280,000 barrels a day, and that goes up to 400,000 barrels a day to 425,000 barrels a day with some of the projects we’ve got underway and the projects we’re really focused on tankage, some typing, some dark work. The tankage would allow for additional segregation, which will enable us to keep higher quality, distillate it, segregate it in and then we can capture the premium when we export. Allen Good – Morningstar Research: Okay, great. And then second question. I know two years ago when you did the Pembroke acquisition, you made mention of advantage of some Atlantic Basin opportunities and maybe even exporting back across to the U.S. Given all the changes that we’ve seen here in the crude [part] in North America and the potential for some of the lighter discount crudes to move to the East Coast, do some of those exports options Atlantic Basin still exists for Pembroke and is that acquisition quite stack up now compared to how it was a few years ago given all the changes we’ve seen?

Yeah, I think your comments are fair. But we’re making money in Europe, in U.K in our business. We’ve been able to move gasoline into East Coast. We moved gasoline to Quebec. We shift some gasoline to Brazil. The distillate is going back still towards Europe. So, yeah, I think we have a very sound Atlantic Basin strategy when you consider Pembroke, our Quebec City refinery and then our Gulf Coast operations. So, but yes, the best place in the world to refine today is the U.S. Gulf Coast and, so that’s got to be true, but I don’t why. I think our position is good. Allen Good – Morningstar Research: Okay. Great. Thanks.

Our next question comes from Robert Kessler from Tudor Pickering. Please go ahead. Robert Kessler – Tudor Pickering Holt & Co. Securities, Inc.: Hi. Thanks for the follow-up. Bill, just a friendly push on the heavy-light differential commentary. I get your point that about the probable near-term widening and the heavy-light spread and the “K” factor lag and everything, but just to push you a bit for some color of the spot spread today between, say, LLS and MAYA up 5 bucks. You mentioned in the past that 8% differential is needed to justify marginal coking economic. So can we make a simple extrapolation and say that some of your cokers are technically under water for just that in today or can you correct me in that assertion?

Okay. So the numbers you say are fine. And I’d said really eight would be floor, you probably need 10 and 12. Part of it gets into what you’re comparing at against, whether it’s against Brent, LLS or this now our cookers under water.

Other events of break in, if we can make asphalt, it’s actually – if you have the ability to market asphalt versus an open coker you’d be marketing asphalt, but versus fuel you would coke LLC. So that’s sort of that, but we’re right there. We’re right at the breakeven on the coker.

So your observation is correct Robert Kessler – Tudor Pickering Holt & Co. Securities, Inc.: And if margins, the heavy-light spread does not widened like you expect, would you considered reduced throughput of the cokers?

Sure.

Sure. I think well, Lame, maybe if you couldn’t him very well. If we can make asphalt with some of our plants like Corpus, we’d make asphalt. Then if you have a spare coker, we are looking, now if you have a spare coker if you have optionality and then you look at our fuel oil economics. And so we would balance those as well. Robert Kessler – Tudor Pickering Holt & Co. Securities, Inc.: Okay, thank you.

Yes, you can spare your coker, it would be, yes, you’re right. Robert Kessler – Tudor Pickering Holt & Co. Securities, Inc.: Thank you very much.

Our last question comes from Paul Cheng from Barclays, please go ahead. Paul Cheng – Barclays Capital, Inc.: Hi, a real quick follow-up. Do you have a estimate, what is the opportunity cost related to the downtime in the first quarter for Venezuela and Wilmington, as well as the Texas City, Corpus Christi and the [Port Arthur] into the two different numbers.

You want the number for… Paul Cheng – Barclays Capital, Inc.: What is the opportunity cost related to the downtime in your Gulf Coast system and in your West Coast system in the first quarter.

Yeah, hang on, we’re going to get there, hold on one second. Including turnaround activity, yeah, I’m going to have to break this out.

It could be unplanned downtime.

Yeah, so Paul, on the West Coast it was about $31 million, of unplanned downtime and the Gulf Coast it was about $30 million, and do you have the turnaround numbers? Paul Cheng – Barclays Capital, Inc.: I mean, those are opportunity costs, right? It’s not the actual repair cost. It’s the opportunity cost?

Yeah, that’s what we call it (inaudible).

Yeah, lost margin. Paul Cheng – Barclays Capital, Inc.: Okay.

And so, that’s just on the unplanned downtime, plus you want the impact of turnarounds? Paul Cheng – Barclays Capital, Inc.: Yes, please.

Okay, so you’re at.

We don’t have that number.

It’s actually a pretty big number. This looks like it’s over – for the Gulf Coast over $200 million and then West Coast is about $25 million. Paul Cheng – Barclays Capital, Inc.: So, that means that in the West Coast is $25 million right, Gulf coast is $200 million you say?

That’s in that ballpark, yes. Paul Cheng – Barclays Capital, Inc.: Okay. So, that means that West Coast, the total downtime you estimate your opportunity cost is along in the $56 million and in the Gulf Coast it is as high as $230 million?

That is a rough estimate based on market margins and impacts due to the turnarounds and unplanned outages. Paul Cheng – Barclays Capital, Inc.: Okay, very good, Thank you.

Okay.

We have no further questions at this time.

Okay, thanks John. And thank you for joining our call today, please visit our website or contact investor relations for this call information.

Thank you ladies and gentlemen. This concludes today’s conference. Thank you for participating. You may now disconnect.