Welcome to the Valero Energy Corporation Reports 2013 Fourth Quarter Results Conference Call. My name is Sylvia, and I will be your operator for today. (Operator Instructions) Please note that this conference is being recorded. I will now turn the call over to Mr. Ashley Smith, Vice President of Investor Relations. Mr. Smith, you may begin.

Thank you, Sylvia and good morning to everyone listening to our earnings call today. With me today are Bill Klesse, our Chairman and CEO; Joe Gorder, President and COO; Mike Ciskowski, our CFO; Gene Edwards, our Chief Development Officer; and several other members of Valero's senior management team. If you have not received the 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. Slide 2 directs your attention to the forward-looking statement 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. So as noted in the release, we reported fourth quarter 2013 earnings of $1.3 billion or $2.38 per share. Excluding the $325 million nontaxable gain on the disposition of Valero’s retained interest in CST Brands, our adjusted fourth quarter 2013 earnings were $963 million, or $1.78 per share, which compares with fourth quarter 2012 adjusted earnings of $1.05 billion or $1.88 per share. For the full year 2013, we reported earnings of $2.7 billion or $4.97 per share. Excluding the aforementioned gain and special items related to our May 1 spin-off of CST Brands to Valero’s stockholders as detailed in the release, full year 2013 adjusted earnings were $2.4 billion or $4.42 per…

(Operator Instructions) We have Doug Leggate, BofA Merrill Lynch.

I’ve got a couple of micro questions. Actually, I'm hoping you can at least give your perspective on. The first one is that affects you guys in the Gulf Coast is the pricing of Maya. It continues as an indicator I guess of heavy sour in the Gulf -- it continues to trade fairly wide relative to LLS in particular. Are you guys seeing anything that is happening differently in terms of either flows out of Mexico or the [K-factor pricing that AMEX] is using? Any color on how sustainable you think this might be? I've got a follow-up question.

Doug, this is Gary Simmons. The Maya formula -- 40% of the Maya formula is based on WTS. And so I think a lot of what you are seeing the Maya formula is that they are basically chasing the Brent TIR. And so it got very narrow and then Brent TIR widened back out and Maya went with it. So we are seeing some additional production come to us. I think some of that was due to refinery turnarounds in Mexico. So we are getting some volume above our contract levels. But the pricing has been more tied to volatility in the Brent TIR than anything else.

Could you give a perspective, Gary, as to whether this is something that is just somewhat transitory, or does it change the way you think about your feedstock given -- all the talk is obviously on light sweet in the Gulf but heavy is going to trade out wide. How does the end product you are planning in terms of how you’re going to basically plan your slate going forward?

We have a lot of flexibility in the Gulf Coast system, being able to swing from the heavy barrels to the light. It’s been encouraging that the Mayas continue to price at competitive values to the medium sour and the light. I don’t think it really changes our thinking going forward, Doug.

My follow-up is also a micro question if I may. And it relates to the gasoline. We are all focused on gasoline exports in terms of the expansion you guys have got going on. So I wonder first of all if you could give us an update as to where you are currently and it really what’s -- my question is it seems to us that the U.S. was self-sufficient across the country for the first time in the fourth quarter. And we basically are seeing gasoline in the Gulf trade under Brent in terms of apples-to-apples basis. So I’m just curious as to -- are you concerned, we’re going to see gasoline pricing move away from Brent towards the domestic crude and if so, how does that change your export policy and I’ll leave it there? Thank you.

Hey Doug, this is Joe. Listen on the exports, in the quarter, we did 133,000 barrels a day of gasoline exports. December was particularly strong but it was pretty consistent throughout the entire quarter. If you look forward to the first quarter, I would tell you that we’re seeing volumes at similar levels. And it all has to do with the fact that it did -- we had some low prices and the Latin American countries continue to be short and so we have the opportunity to move the barrels there. I’ll just give you the distillate number, you didn’t ask but while we’re on this, we exported an average of 219,000 barrels a day distillate in the quarter. And those volumes look consistent going forward also. As far as the -- I guess the longer term view of gasoline and its relationship, we are in strange period right now. Prices have been low. Refinery run rates in the Gulf Coast have been very, very high so we’ve had significant volumes in production and we’re at the time of the year when gasoline demand is historically down. And so I guess the guy has pulled the staff here that came out just today and we had a pretty good pop in gasoline demand. But we’re getting into that time of the year although its hard to imagine right now with this cold season, we’re getting to that time of the year where ultimately we’ll stop lending butanes and gasoline pool tightened up, which you get a little bit of recovery in the margin. So I don’t really see that much difference this year versus last. Gene?

This is Gene. My only extra comment would be I think as you move into the several periods, ultimately the gasoline is got to revert back to a Brent-related type crack because of incremental refineries in the world are suffice enough of a Brent-price crude.

Okay. We have Ed Westlake from Credit Suisse.

Hey and thanks for the time and obviously great earnings. Congratulations. Obviously Q3 to Q4, there was a big swing and there is a number of different things that could have accounted for that. I mean, crude discounts widened out in the Gulf, butane blending in winter, products exports, we just had a brief discussion on them. Secondary products was something that hurt in Q3 and obviously got better in Q4 if the crude prices came back a bit and then obviously that continued self help that you guys are putting in with the new units. I’m just trying to look for some color as to which do you think of those or something else, I mean, RINs maybe drove the big delta Q over Q?

Yeah. Ed, you kind of nailed most of those things. This is Ashley. I’d say in absolute terms, there is a million way you can slice and dice it but in absolute terms, the biggest -- somewhat in terms of indicator or capture rate, one of the biggest drivers was just outright crude discounts helping out. After that from 3Q to 4Q, the decrease in RINs cost helped on a capture rate basis, absolutely being able to blend butane which can get a price more like you finished gasoline, helped out. I'd say those are the key drivers but just hitting the better crude discounts help not only in capture rate but also outright discount, outright cracks or margins.

Thank you. And then the second unrelated question is obviously light crude is coming out to you thick and fast from the Eagle Ford and eventually at Permian in all the pipes. So that’s very helpful and you’ve announced that you’re thinking about some popping units for late 2015. You said relatively low cost for barrel. I don’t know if you’ve got an actual cost. That would be helpful. But generally, if you can talk about how you take your sort of slightly heavier design refineries to be able to actually process this light crude that perhaps is better in other people’s refineries?

Hey, this is Bill. When we are going ahead with our 70,000 barrel a day crude -- light crude unit at Corpus and Lyondell Crude Unit at Houston. We have approval to do that. And those are the designed to run normally about [58 acres], which is a little bit lighter than our crude diet in either of those crude units that we have existing. But we can run some on those lighter, a little bit incrementally lighter crude. We have less flexibility to be able to run something that looks little bit more like WTI, a little bit down to the low 40s. But these are really our big additions in terms of (inaudible) additions to the Gulf Coast capacity to run this type of (inaudible).

These projects don’t convert a heavy refinery to run light crude. They generally take light-to-medium refineries and just allow them to process additional light crude, but still have the downstream units.

And so, a little more color on that, what we do is we, essentially are backing out. Both those refineries are short toping capacity and long conversion capacity. So it will allow us to do (inaudible) to build our conversion capacity. So it's really displacing VGO and light sulfur [ATP]. But it’s not moving us from -- it’s not -- Ashley commented, we’re adding crude capacity. We’re not displacing crude capacity.

We haven’t seen any incentives to destroy heavy capacity because this counts a lot. So most of this is just adding in time, either adding through construction or through processing and operations, finding additional debottlenecking and capability to process light crude.

And if down the road, light did completely disconnect and heavy stayed links to global markets, how -- what would be the first thoughts on in terms of how you adjust -- would adjust the units to get these heavy refineries a little bit more flexible in terms of what they could take?

We’re still -- we still have some additional capacity we think within our existing units down there. And it’s something that we’ll just -- we’ll continue to work on. It’s all a function of how disconnected it actually is and is it really there. But we still have some open capacity to run additional light crude in our Gulf Coast as it is today. And then after you get to -- when you really -- as you get there and you drive towards these one, then it’s all about trying to test what are the marginal economics of weak crude, versus medium, versus heavy. And we’ll just -- we’ll find out, but it’s just a matter of how disconnected it is.

And we have Jeff Dietert from Simmons & Company. Jeff Dietert - Simmons & Company: My question has to do with Gulf Coast overall imports. We had another robust import number in the DOEs today despite the wide differentials that were in place in November and December which I would assume established the import levels. It appears that the countries that are shipping crude to the U.S. are continuing to ship despite the disincentives that were in place during the fourth quarter. Can you comment on what you’re seeing on about light and medium and heavy crude imports coming into the Gulf Coast? Are those staying pretty stable for you? And what are you seeing more broadly in the industry?

Yeah, so overall I would say we are not importing light crude into the Gulf routinely anymore at all. Our imports are medium sour and the heavy sour. On the medium sour side, some of the medium sours that we were taking into the Gulf, we’ve now shifted and a lot of those barrels are now going to the West Coast and the heavy sour has been somewhat [stake]. Jeff Dietert - Simmons & Company: Secondly, could you update us on the hydrocracker rates? How are they performing both at Port Arthur and St. Charles and how are they performing in the fourth quarter and so far on 1Q?

This is Lane Riggs again. They run very well in the fourth quarter and they’re currently running well -- I would say we were able to optimize our Port Arthur refinery and looking at our permits. Really our permits are based on a heat release or firing rates as we’ve got -- as we ran 57,000 barrels a day and looked at a little bit more optimized. We’ve actually been able to get the rates up to 50,000 barrels a day normally and still live inside our (inaudible) format. But other than that they’re running, as designed and doing quite well of course.

And we have Sam Margolin from Cowen and Company.

I guess, I’ll circle back to imports for a second. That’s probably going to lead to a follow up. It’s in our observation that a significant portion of the medium imports are leftover industry wide are from Saudi Arabia and Kuwait, something like 80% and more or less everything else, legacy, medium imports from Nigeria and other places have been backed out. Are these volumes from Saudi and Kuwait just much sticker because refining interests from the exporting countries here, or just because they are in more of a -- it's more in their interest to maintain the U.S. market share with those volumes? And I guess what I’m getting at is, are these -- with everything else getting backed out from the medium pool at a pretty rapid rate, are those volumes really an unlikely candidate to follow that trend?

For us, it really is a matter of economics and we’ve continued to see the barrels that we are getting from Saudi and the barrels we are getting from Kuwait to be economic. Again, we’ve shifted some of that volume to the west coast and we see better value in moving us to the west coast now that we have other options available to us in the gulf. But for us, it’s an economic question.

Okay. So it’s basically just a matter of price and the exporters are going to make the determination of whether there's another location descended to, or whether they need to market the U.S. pricing?

Yes.

Basically. Okay. And then this is a follow-up on imports and replacing imported crude with domestic crudes. The time to delivery of the average barrels for your systems has been reduced significantly. It's always stands to reason that the industry is able to structurally handle a lot lower import -- a lot lower inventory levels kind of on an ongoing basis. And we’ve seen significant draws up until this week of inventory from the Gulf Coast and I was just wondering if that is sort of de-risking of your supply is contributing to that at all, and if that’s also why the curve is so backward dated essentially?

It’s difficult to say, but we just haven’t seen and as we switched to more and more domestic crude, it is having an impact on the inventory and the required inventories in our system for exactly the reasons you are seeing.

All right. Thanks so much. Appreciate it.

And we have Robert Kessler from Tudor Pickering.

Good morning, gentlemen.

Hey, good morning, Robert.

I wanted to ask about Quebec City, as that refinery is slowly transitioning to 100% North America of crude feedstocks, can you give us the numbers for the quarter and how much was delivered by rail and by ship from Texas, and maybe, if I can add a bonus to that, the average light in crude price to that refinery for the quarter?

Well, I don’t have it. We will give you the average light in crude cost. But I can tell you that our rail has come up and it’s been very successful. It has a capacity to do about 60,000 barrels a day, started up in August. And we continued to ramp up volumes. We begin to hit some snags with the weather in December and January. The cold weather really hurt that operation. We were up to about 40,000 barrels a day in November. The volumes did falloff in December and January a little bit to the cold weather. We also exported five cargoes from the Gulf to Canada in the fourth quarter. So we’ve run Canadian Syn for the first time. At Quebec, we’ve run WTI, we’ve run Bakken and we run Eagle Ford. We continue to ramp up our volumes there. In the fourth quarter, we saw some weather issues even on the gulf movements that hurt us. We continue to see some challenges on the logistics to be able to get the barrels to the water. And then as you get into the winter, Quebec, the fact that we have ice-clad ships in the supply chain also hinder our ability some to be able to get to well there but we continue to ramp up those volumes and seek good economics on those barrels compared to our Brent related alternatives.

That’s good to hear. What was the average throughput for the refinery overall for the quarter?

Yeah. Robert, I’m going to continue to take Brent near traditionally high records or at traditionally high rates, but we are going to disclose refinery by refinery throughputs and margins, things like that.

Okay. And everything going on track is --

We are just going to say, as you can see from the regional data for North Atlantic region, it’s been at fairly high rates.

Yeah. And everything is on track as far as future expansion capacities to take North American crude? Most notably, I guess the additional loading capacity in Corpus fell mid this year, coming on with another 50,000 barrels a day or so.

Yeah, so two significant changes during the year. Mid-year, the Corpus loading facility coming on line and then in the fourth quarter, we expect the Line 9 reversal online also.

Yeah, you’re pretty confident that it’s 4Q and not 1Q?

Everything we hear still covers 4Q.

We have Blake Fernandez from Howard Weil.

Guys good morning, I had a couple of broader questions for you. The first one is on rail regulations. Obviously we’re hearing some rumblings of more stringent regulations coming down here potentially at some point. And I guess I’m thing about this correctly, certainly would help support differentials on the refining side but then potentially impact some of the potential earnings you would get on the logistics side, in the third call you got about over 5,300 railcars on the way. And I’m just curious if you could talk about how you see this unfolding. Does this impact your decision on owning versus leasing and basically any dynamics you see unfolding as a result of this?

Sure Blake, this is Joe and I’m very impressed that you got our number of railcars, you remembered.

Thank you.

Obviously man, this is an issue. The DOT has the ball, they’re involved. They’re working the regulations and I think the date that we’ve talked about here, they should have recommendations in place by November 14. This is also an issue that’s being worked by the American Association of Railroads, by AFPM and many others. And I would say obviously the conversations are around hiking the standards on cars. So that would be something that we would expect to see. There is a conversation around rerouting around urban areas, slower speeds through urban areas, a lot of focus on classification of the cargo, so what type of crude is being carried, all those things would make sense. And I think we would expect to see some of that. The one issue that’s hanging out there that none of us really know about because of the nature of the rail fleet is how long would it take to retrofit and how long will they allow for a phase in of any recommended changes. The 5320 cars that we have on quarter are all the rural [111A] cars. So they do have additional safety features over traditional cars. So we’re just kind of waiting to see where that goes but we believe that cars that would meet the schedule will be okay. As far as changing what we’re doing, I don’t see that this is going to have any impact on our plans to move crude by rail. And then as you say, what happens if that materially affected the economic. We currently have some 6,000 cars under lease in the fleet and what we would do is ultimately just go ahead and replace the cars that we have now under lease with the cars that we own and we continue to use them for other services such as asphalt and ethanol, so not a lot of downside for our investment in the railcars.

Good, good, thank Joe. And then the second question; a little bit off but on the ethanol side, obviously this has been a home run of an investment for you guys. And you brought at the right time and obviously you’ve recouped all of that investment if I’m not mistaken. But I’m just curious is there a lot of synergy between that and your refining business? I guess where I’m going is that ultimately it's just a flip where you could basically just sell it at a premium and take your profits and walk away.

Yeah. Blake, this is Gene. The ethanol is doing quite well. We produce more ethanol than we actually blend ourselves. It's not necessarily even the same barrels. We try to optimize both. We try to get the highest net back at our ethanol plants and then our marketing operations tries to procure ethanol at the lowest cost. Sometimes those intersect, sometimes they don’t. So I’d say there’s probably not a whole lot of synergy there. It’s roughly run -- they think it could be run in this independent business. We’re very happy with the returns we’re getting now and I don’t think the multiples you would get in case -- because last year, it was basically a breakeven business. This year we made almost $500 million. In the prior year -- 2011, we made almost $400 million. So we’re not exactly sure how that would trade in the market place due that volatility, I think which is good. Also we have a significant tax gain because you have a rapid depreciation, tax depreciation we had on the stout. I think we’re satisfied with investment. We always look at our options too.

Okay, thanks Gene.

And we have Roger Read from Wells Fargo.

I guess, a couple of questions, so many things have been hit here, but kind of getting back to the crude exports to Canada question, and may be not the exact feedstocks to the refinery or the crude cost this time around. But what much -- how much more progress do you need to more or less convert that refinery to pure North American crude? And then what’s that -- once that is done, is there anything you can do about moving things to Pembroke and advantage ways that something you would want to do in the current regime or do we need changes in the -- either from the President or Congress on that front?

So, overall, Roger, we anticipate that by the end of the year Quebec will be running 100% North American domestic crude. You will continue to see volume ramp-up. I mentioned the two step changes that occur, we get our corporate stock in place mid-year that will certainly help and the line 9 reversal, when line 9 reversal is complete and they certainly will be on 100% domestic crude. The Pembroke question is a little bit more difficult. We don’t see that we’ve be looking to export to Pembroke at least any time in the short-term.

Okay. And then in terms of the bigger projects you are undertaking in Corpus and in Houston to move to using more light. What else are you able to do, maybe just tweaking around the edges, but maybe in the aggregate, how many barrels of light be, you think you might be able to run, say 12 months from now versus what you’re running today or what you ran in the fourth quarter along the Gulf Coast?

This is Lane. I thought we had answered that question back, but there are crude units are -- will an additional 150,000 barrels a day domestic light crude capacity. We believe we have somewhere on the order of about 300,000 to 315,000 barrels a day of crude capacity on the Gulf Coast. But, again, as I mentioned earlier, we have not build all that capacity up yet, so you’ll see the economic become actually compelling, all the logistics get bottleneck, we will approach that number and I think -- I’m pretty confident, we’ll be higher than that number that’s where we are today.

And the crude fraction areas our top reserve a 15 project not a 12 months.

Right, right. Now understood, it’s too different, I was trying to understand other than the two very large projects, what are some of the smaller things that can happen, maybe on is high-profile but ultimately do have a positive impact? And then, I guess, my last question, cash flow, I think, I actually mentioned at the beginning about twice the amount of capital return to shareholders in ’13 versus 2012. Can you give us an indication of what you would expect or what you would plan to do in 2014? I mean, I know, you don't want to give guidance on a specific number but maybe as a percentage of cash flow versus what we saw in 2013 that we could expect to be directed towards share repurchases, dividend, et cetera.

Well, we just raised our dividend to a $1 share on an annual basis. So that’s $540 million. And then on top of that our capital budget is $3 billion and then the rest of it is how we conducted ourselves in the past and we take a relatively balanced approach here. We look at our dividend as the year goes on. We’ll look at our investment opportunities and I think you can expect the same actions you’ve seen from us in the past.

Okay. Thank you.

And we have Faisel Kahn from Citigroup.

Good morning.

Hi Faisel.

Hi. Just if I get a little bit more, I think, you may have answers this in your prepared remarks. But I’m looking at the capture rates sort of going up sequentially from the third quarter to the fourth quarter. Can you give a little bit of breakdown of the -- of what kind of cause that to the increase in the capture. How much was crude-related I guess in percentage terms versus how much was product related?

About half and this is very general…

Yeah.

… because each regions get its own specifics and then about half was crude-related, the other you could say was product or RINs related. Things like be able to blend butane, so the indicator is more accurate versus, compared to what we’re actually doing and then RINs coming down. So in general its half was kind of crude related and remainders are mix of things including all that stuff.

Okay. And then, just on the ethanol side of the equation, what's your sort of outlook for the rest of the year? I mean, is this something that sort of can be sustained over the course of '14 or is -- are the other factors kind of work against this sort of level of profitability?

Hi. This is Gene. First of all, 2013 was a world of contrast, it started the year at breakeven margins, some of the plants were actually down and the fourth quarter was a really big month where we had like 80% margins. I think if you look at our [divided] numbers out, we averaged about $0.40 margin on -- for the year, which you've started January a little higher than that, but that's about where we are today. It's about $0.40 going forward. How it pans out through those, it's very volatile, because it's a result between ethanol price and corn price which really don't correlate. But, however, ethanol (inaudible) remains pretty low. Our production is hanging right around 900,000 barrels a day. I think demand has strengthened the average under the RFS about 850,000 barrels a day. So we’d normally be in a build situation, but we are exporting a lot of ethanol with lower form factors, lower ethanol prices as a result. We're seeing good export economics. We're filing lower cost ethanol in Brazil in the long markets. So that's what’s keeping the market fairly [snuck] as far as inventories. The only other thing I would add I guess is that the production numbers start to ramp up, you could build from there. But later we always maintain that we have really good competitive advantage, so we've been here in over supply situation, we have -- we fell like we have a $0.20 or so gallon margin, the competitors starts dropping, some of these (inaudible) start to fall back off. So long answer but, lot of uncertainty there. I don't think directionally it's going to be $0.80 margin we saw in the fourth quarter, but something new in the between $0.20 and $0.40 is probably something that would be a reasonable expectation.

And we have Evan Calio from Morgan Stanley.

Hi. Good morning, guys. There is lots of focus on the light side here, this morning, but Keystone started up last week, actually it’s running at about 40,000 barrels a day currently. I know line fill was primarily light crude, are you seeing any of that in both of those market today? Or if you have your light do you see an ability, potential ability are -- heavy barrels that are increasing storage today that's estimated at over [500 million] barrels?

Yes. The barrels being offered off the line are really being priced at something competitive to Maya in the Gulf today barrels that are coming off.

(Inaudible) reflects of impact yet from those volumes right?

No, there really hasn't yet.

And do you expect that would take time given the K factor or do you think that might develop sooner?

Well, I think, you still -- you know the trouble with getting significant volumes of Canadian heavy to the Gulf is still getting the barrels across the border. So it will make a difference, but I don't know how bigger difference it will make in the Gulf.

But, obviously, a different question on potential crude oil exports and not on the policy question, but you know you are one of the only refineries that have exported crude off the Gulf Coast. The system has clearly been designed its entire history to import crude. I mean, can you discuss some of the coastal infrastructure and logistic issues that were related for you to reverse those flows and just the system limitations that made pose a risk if there is any loosening of that policy.

Well, that's difficult to answer. Some of the challenges we're seeing, I will just kind of go through some of those -- the logistics are still very much a challenge in the Gulf and so some of the issues we've seen is just the barrels that show up at the dock are not necessarily what we are expecting to load on to the ship. So certainly some tankage needs to be built out in the Gulf, ability to be able to segregate barrels better. And that's kind of why we have taken the path that we want to be able to completely control the logistics and load the barrels on over our own dock and at Corpus for that very reason.

And where were you on the quarter on the water exports to Quebec.

We need five partners to Quebec in the fourth quarter.

And is that your -- what would be your max run rate is?

We can run a lot more than that. At Quebec, really the issue was primarily the logistics are getting the barrels on the water. And then for us the other thing is most of those grades were new to refineries. So we don’t want to send the bunch of crude that they never run before. So those have been processed now. We have the operating history and we can continue to ramp up as the logistics allow.

Right. So logistics being the primary bottleneck there?

Yes.

And then just lastly, any comments on Aruba and I know, given change in crude dynamics in the Gulf. Does that breathe any potential life into that asset or any comments there? I’ll leave it there.

This is Klesse. There is some interest in the market place but really in the cokers and it’s more tied to upgrading. I would say there’s no interest for processing oil or anything there.

So do you think more like…?

(Inaudible)

So a bit more, maybe a second derivative effect, if there is a negative effect toward heavy pricing in the Gulf?

I suppose that if heavy oil gets deep enough discounted, you can offset some of the economic disadvantages of low cost natural gas and the other items at cokers. But we got to anticipate that ourselves.

Great. I appreciate guys. Thanks.

And we have Paul Cheng from Barclays.

Hey guys. Good morning. I have to apologize first because I came in late. So you may have already answered that question. Two question, one, that you are talking about 50% of the margin improvement is crude related and the 50% is imported and (inaudible). When we’re looking at that if we’re saying that, is there any tie-up of one-off operating benefit -- whether you have large volume of distressed crude coker that you’ve been able to purchase that we have been saying that those are better not necessary repeatable into the first quarter or into 2014. Is there anything that you can quantify whether that’s any meaningful among them?

I think we’re looking at each other, Paul, and none of us -- nothing comes to mind like that.

Yeah. Nothing that’s purely one-off benefit. We’re always in the market looking for distressed cargos and those opportunities change from quarter-to-quarter but it wasn’t -- in the fourth quarter, it wasn’t an overwhelming and meaningful difference versus 3Q or year-over-year results, we are always getting that stuff.

On distressed but the discounts themselves were aligned.

Sure. But that is just the market condition. We’ve just have been running extremely well and capturing the market. I’m just talking about anything say somewhat you need and less likely to repeat one-of items on the operating side?

No.

Okay. Second question is that when you are talking about increasing your light oil processing capability and which is what you’re doing. Bill, have you also looked at your system, is there any real opportunity to maybe building some condensate splitter and use it fit into the system that is actually pacing light oil processing because I mean condensate is probably going to be even have a bigger discount.

So the answer to the question would be yes. We would look at something like that in the right circumstance. If we are sure, we can add value.

Bill, can you elaborate that, what kind of rising consensus, is that -- the current discount is just not big enough or the yield, or is this a really big investment that we are talking about?

Well, we’d be bigger than one of our competitors announced for some other things that they’ve done with the Marcellus or Utica. But permitting and there’s a lot of other issues to come with this, so you have to be comfortable that these discounts will last long enough because the lead time is significant. But these are things that you would expect us to look at.

Can you give us a roughly what kind of mandatory in terms of, one in metric quantity that you maybe talking about if it the right economic circumstances?

No. I don’t have a good answer for you on the actual volume you are asking.

I see. Okay. Very good. Thank you.

And we have Allen Good from Morningstar.

A quick question on the impact of increase in light crude, you have in your recent presentation slide indicating that deferred yields had moved to 43% in 2015. Does that include all the light crude or projects associated with increasing light crude, or is there a risk there gasoline yields could actually be a little bit higher if you attain all those goals?

Allen, that includes what our expected runs are including those new projects. But depending on the margin environment, we are going to always optimize. So actual results could be different. But that’s what was targeted in the overall runs based on our including projects.

And then just quick one on exports. Was there any additional markets that you identified during the quarter with respect to gasoline or [LED] imports or exports that you had previously exported to. I know previously you talked about picking up the market, the European had typically exported to. Was there any further additions there, or same straightforward countries that you’ve typically exported to over the last year or two?

There were no material changes to any of the market and we are finding very, very consistent demand for gasoline in both South America and Europe. And gasoline, the bulk of our volume continues to move in Mexico and then into South America.

And we have no further questions.

Okay. Thank you, Sylvia. And appreciate the listeners for listening to our call today. If you have any other questions, feel free to contact Investor Relations. Thank you.