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Executives

Ashley Smith – Vice President-Investor Relations

Joe Gorder – President and Chief Operating Officer

Mike Ciskowski – Executive Vice President and Chief Financial Officer

Bill Klesse – Chairman and Chief Executive Officer

Gene Edwards – Executive Vice President and Chief Development Officer

Analysts

Jeff Dietert – Simmons & Co.

Evan Calio – Morgan Stanley

Robert Kessler – Tudor Pickering Holt & Co., LLC

Doug T. Terreson – International Strategy & Investment Group LLC

Paul Cheng – Barclays Capital

Roger D. Read – Wells Fargo Securities LLC

Doug Leggate – Bank of America Merrill Lynch

Paul B. Sankey – Deutsche Bank Securities, Inc.

Arjun N. Murti – Goldman Sachs & Co.

Edward G. Westlake – Credit Suisse Securities LLC

Faisel Kahn – Citigroup

Chi Chow – Macquarie Capital

Allen Good – Morningstar Research

Valero Energy Corporation (VLO) Q2 2013 Earnings Conference Call July 23, 2013 11:00 AM ET

Operator

Welcome to the Valero Energy Corporation Reports 2013 Second Quarter Conference Call. My name is Lorissa, 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.

Now I’d like to turn the call over to Mr. Ashley Smith, Vice President of Investor Relations. Sir, you may begin.

Ashley Smith

Thank you, Lorissa, good morning, and welcome to Valero Energy Corporation second quarter 2013 earnings conference call. With me today are Bill Klesse, our Chairman and CEO; Mike Ciskowski, our CFO; Joe Gorder, President and COO; 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.

Before we get started, I'd like to direct 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.

Okay, as noted in the release, we reported second quarter 2013 earnings of $466 million or $0.85 per share. The results include after-tax charges to general and administrative expenses of $20 million or $0.04 per share and income tax expense of $9 million or $0.01 per share, both related to the May 1 spinoff of CST Brands to Valero's stockholders.

In addition, the results include after-tax charges to G&A expenses of $34 million related to various environmental and legal matters.

Second quarter 2013 operating income was $808 million versus operating income of $1.4 billion in the second quarter of 2012. The decrease was mainly due to lower refining margins in each of our operating regions.

Our second quarter 2013 refining throughput margin of $9.26 per barrel was over $1 per barrel lower versus the second quarter 2012 margin of $10.63 per barrel. The decrease was partly due to significantly lower discounts per heavy sour crude oil.

For example, the Maya crude oil discounts to Brent crude oil decreased by $4.40 per barrel from the second quarter of 2012 to the second quarter of 2013. Fortunately the Maya discount has improved by more than $3, over $3 per barrel with July month today discounts to Brent of nearly $8.20 per barrel.

Also contributing to the decrease in margins were the lower discounts per medium sour crude oil and light crude oil. For example the Mars crude oil discount to Brent crude oil decreased by $0.69 per barrel in the second quarter of 2013 compared to the second quarter of 2012.

For light crude oil on the Gulf Coast, the LLS crude oil was a slight discount to Brent crude oil in the second quarter of 2012 versus the premium in the second quarter of 2013, for an increase of about $1.80 per barrel.

In addition, the refining throughout margin was negatively impacted by the higher costs of Renewable Identification Numbers or RINs needed to comply with the U.S. Federal Renewable Fuel Standard.

For the second quarter of 2013, the reported cost to comply were a $125 million versus $58 million for the second quarter of 2012. Given the recent escalation in RINs prices, we now estimate our cost to comply with the renewable fuel standard to be in the range of $600 million to $800 million for the full year of 2013.

Another factor that affected the refining margins was the higher cost of natural gas. Natural gas prices increased from $2.24 per MMBtu in the second quarter of 2012 to $4 per MMBtu in the second quarter of 2013. In addition to effect in our operating expenses, this increase impacts our cost of sales due to our use of hydrogen, which is produced from natural gas. So far in the third quarter, natural gas prices have favorably decreased about $0.40 per MMBtu versus last quarter.

Our second quarter 2013 refining throughput volumes averaged 2.6 million barrels per day, for a decrease of 52,000 barrels per day from the second quarter of 2012, caused mainly by turnarounds and planned maintenance at our Quebec City, McKee, Port Arthur, and Meraux refineries.

Refining cash operating expenses in the second quarter of 2013 were $3.82 per barrel, which was higher than second quarter of 2012 due mainly to higher energy costs.

I’d like to highlight several other items in our refining operations. First, the new hydrocracker at Port Arthur has continued to perform well and contribute to earnings. In the second quarter of 2013, we estimate the new Port Arthur hydrocracker contributed approximately $80 million in EBITDA with the throughput rates nearly at capacity and achieving high conversion rates. The contribution is slightly lower than last quarter due to changes in market prices for key drivers such as higher natural gas prices, lower naphtha values, and lower butane values during the summer RVP gasoline blending season.

Using 2012 average prices, we estimate EBITDA would have been approximately $120 million.

We look forward to the contribution from the recently completed St. Charles hydrocracker, which is essentially a clone of the Port Arthur unit. Earlier in July, the St. Charles hydrocracker experienced a smooth and successful startup and is now running at planned rates.

As a reminder, both of these hydrocrackers were designed to take advantage of the current environment of relatively high crude oil prices, strong diesel margins, and inexpensive natural gas. This is also consistent with our strategy to increase production of high quality diesel.

Also at the St. Charles refinery, the Diamond Green Diesel joint venture biofuels plant started up at the end of June. Throughout July we have been ramping up rates, this plant is designed to produce approximately 9,300 barrels per day of renewable diesel from low quality recycled cooking oils and fats using refinery hydro processing technology.

The project is a 50-50 joint venture between Valero and Darling International, a leading gatherer of used cooking oils and animal fats. Valero’s retail segment reported $39 million of operating income in the second quarter of 2013 prior to the May 1 spin-off of CST Brands.

Subsequent to May 1, Valero reported its equity interest in the earnings of CST Brands as part of other income. As a result of entering into long-term fuel supply agreements, CST Brands became our largest wholesale customers. Our ethanol segment reported operating income of $95 million in the second quarter of 2013, an increase of $90 million from the second quarter of 2012 mainly due to higher gross margins per gallon and higher production volumes.

Production averaged 3.5 million gallons per day in the second quarter of 2013 for an increase of 156,000 gallons per day compared to the second quarter of 2012. The increase in production volumes was mainly due to the economic incentive of higher gross margins per gallon.

In the second quarter of 2013, general and administrative expenses excluding corporate depreciation were $233 million. Included in this were pretax charges of $52 million or $34 million after taxes for increases to environmental reserves related to non-operating sites and legal reserves and pretax charges of $30 million or $20 million after taxes related to cost incurred to affect the spin-off of CST Brands.

In the second quarter of 2013 net interest expense was $78 million. Total depreciation and amortization expense was $405 million and the effective tax rate was 37%. Regarding cash flows in the second quarter of 2013, capital expenditures were $796 million including $162 million for turnarounds and catalysts.

We returned $364 million in cash to our stockholders by paying $109 million in dividends and by purchasing 6.5 million shares of Valero common stock for $255 million. In addition, Valero paid off $300 million worth of 4.75% notes that matured in June and we received approximately $550 million of net cash from the CST Brands transaction.

At the end of the second quarter of 2013, we had approximately $3 million remaining under our stock purchase authorizations. With respect to our balance sheet, at the end of the quarter, cash was $2.4 billion, total debt was $6.6 billion, our debt to capitalization ratio net of cash was 18.8% and we had over $6 billion of availability liquidity in addition to cash.

We maintain our guidance for full-year 2013 capital expenditures of approximately $2.85 billion which includes turnarounds and catalysts. For 2014, we estimate capital spending including catalysts and turnarounds to be in the range of $2.5 billion to $3 billion. Returning cash to stockholders remain a high priority and we are balancing this with opportunities to create value by strategically investing in logistics assets, hydrocracking, petrochemicals, and processing cost advantage lighter crude oil.

Our premise is to capture the competitive advantages provided by the growing supply of cost advantage crude oil and natural gas in the U.S. and Canada. Along these lines we are also evaluating potential petrochemical investments that will leverage our existing assets to upgrade the value of abundant and growing supplies of natural gas and natural gas liquids.

Lastly, we are evaluating the formation of a master limited partnership for our logistic assets. If for modeling our third-quarter operations, we should expect refinery throughput volumes to fall within the following ranges; U.S. Gulf Coast at 1.5 million barrels to 1.55 million barrels per day; the U.S. mid-continent at 420,000 barrels to 440,000 barrels per day; the U.S. West Coast at 270,000 barrels to 280,000 barrels per day; and North Atlantic at 470,000 to 490,000 barrels per day.

We expect refining cash operating expenses in the third quarter to be around $3.85 per barrel. For our ethanol operations in the third quarter, we expect total production volumes of 3.45 million gallons per day and operating expenses should average $0.38 per gallon which includes $0.04 per gallon for non-cash cost such as depreciation and amortization. Also in the third quarter we expect G&A expense excluding depreciation to be around $160 million and net interest expense should be about $100 million.

Total depreciation and amortization expense in the third quarter should be around $420 million and our effective tax rate in the third quarter should be approximately 35%.

Okay, the rest that we have concluded our opening remarks, we will now open the call to questions. During this segment we request that our callers limit each turn in the queue to two questions. After those two questions callers may rejoin the queue with additional questions.

Question-and-Answer Session

Operator

Thank you. (Operator Instructions) Your first question is from Jeff Dietert from Simmons.

Jeff Dietert – Simmons & Co.

Good morning.

Joe Gorder

Good morning, Jeff.

Jeff Dietert – Simmons & Co.

Sure, they’ll probably be a long list of these, but I wanted to start with RINs and one of the struggles I am going through is, our blenders passing through the cost of rents into the retail prices, does it vary by region, what are the major considerations with regard to whether or not these RINs cost are getting passed through to the retail well?

Joe Gorder

Well Jeff, this is Joe. I mean, it’s a great question. We’re trying to figure the same thing on ourselves. And I would tell you that we look at it on a regular basis and it’s very difficult to quantify whether or not we are seeing the effect of the RINs in the cracks.

We think we might be able, but we’re not 100% sure. I do know that if you look at our customers, there are some out there that are able to capture this and there is some that aren’t and everybody is interested in somehow capturing this and the real question for us going forward is, how much of this actually gets pass through into the marketplace and how much doesn’t because it’s a legitimate expense for us as we have mentioned $600 million to $800 million, it’s a big hit and we’d like to be recapturing it, we’re just not sure whether we are or not.

Jeff Dietert – Simmons & Co.

There has been press reports that have talked about blenders in the Gulf Coast reducing the price of blended gasoline in order to try to shift more gasoline sales through the blended stream rather than selling all RBOB and perhaps in the colonial pipeline and then it gets blended up in the Northeast. Have you seen evidence of this activity on the Gulf Coast? I guest the risk is, if you discount your blended gasoline, you loose the value on your traditional gasoline blended sales and I don’t know how much you might be able to shift over from RBOB sales to blended sales?

Mike Ciskowski

This is Ciskowski. I’m trying to get a handle on this issue, it’s obviously very difficult. Joe gave you a couple of our perceptions as to the market and our estimate of costs. I guess I need to remind you that we’re no longer in the retail business. So we're not focused on the street that CST Brands and our other operations. So we're a wholesaler.

Valero is obviously trying to pass the tool where we can. We're obviously trying to recapture it where we can. Our opinion is we’re getting some of it in the crack, but we're not getting all of it and now we can have a debate whether we’re getting 50%, 25%, but we think we're getting some in the crack, but not all of it. And then, but having said all that Valero is going to maintain a competitive or be competitive to our wholesale branded customers where we capture the risk. And we will stay competitive and as if in fact the street and these other people are taking it on the street. We’re going to be competitive to our customers – for our customers.

Jeff Dietert – Simmons & Co.

Thanks, Bill. Thanks, Jim.

Bill Klesse

Thanks, Jeff.

Operator

Thank you. The next question is from Evan Calio from Morgan Stanley.

Evan Calio – Morgan Stanley

Hey, good morning guys.

Bill Klesse

Good morning, Evan.

Evan Calio – Morgan Stanley

First question just to follow up to kind of keep the RIN conversation moving. I know Bill, you've been front center in the RIN conversation and I read portions of your testimony in Washington last week. My question is, as you run your system do you make operating decisions based upon a fully loaded kind of RIN economic analysis of each asset. So the question is, would Valero or the industry potentially see economically induced RIN cuts based upon RIN cost and margins et cetera, particularly as you move into the seasonally weaker fourth quarter?

Bill Klesse

So that’s a perspective question. Today, with the gasoline cracks where they are at the peak of the gasoline season, and we are primarily talking about gasoline.

Evan Calio – Morgan Stanley

Yep.

Bill Klesse

Then I would say that you are not seeing it, because we have good cracks. But the part of that question was, do we include that in our economics, and the answer is yes. And so, as we look down the road, end of the fourth quarter I don’t know what the world will look like, but it is turning into a cost to manufacture for our company, certainly for the independent refining segment of the industry.

Evan Calio – Morgan Stanley

Great. That’s helpful. Thanks. And for second question on CapEx, I know this is the first time you’re providing 2014 CapEx, which looks flat, [ex-] CST to 2013. Can you discuss how you think about overall CapEx levels, the new project returns versus potential share buyback and I guess this will be outside of MLP-able assets?

Bill Klesse

Well our goals continue to be, as I’ve stated over the years, we’re going to maintain a safe operation. We’re going to maintain our investment grade rating. We’re going to hold a little more cash. These are the things that I have continually said. We are investing in reliability. We think in this world you have to be reliable. So what the company can do to support our people in the refineries by investment we’re doing.

But then, this is a long-term capital investment business. And the marketplace has given us these opportunities because I know people are questioning methanol and you see some comments on petrochemicals. So the marketplace has given us this, given us lot of natural gas, giving us the potential from very inexpensive butanes, which obviously can be converted to gasoline, and Valero has the wherewithal, the expertise, the talented people to be able to construct and operate these type of plants. We have sustainable competitive advantages by extensions and bolt-ons to our existing assets and these are sustainable.

So [I’m] getting to be an old guy and I look at what management does, and I think part of management’s job is to take our cash flow and look at our alternatives. Do we have projects that will give our shareholders value, growth, over the long-term, and if we do and we look at our stock and how we think our stock is priced, but if we do have these, then we should presume for our shareholder, and if we don’t, we return cash.

I think this management team has done a very good job at this, frankly. Over the years we bought a lot of our stock. There was a lot of stock issued in the acquisition period of Valero’s history and we’ve bought a lot of stock back over the years.

We raised our dividend. We got caught by the Great Recession just like a lot of people and had to regroup. But once we got past 2009 and 2010, we’ve gotten back on the same path we were on before of returning cash to the shareholder.

We do continue to think our stock is inexpensive and we know that many of our shareholders are looking for yield anywhere they can get it. But we do think the marketplace has given us some opportunities.

So, we match it all up. We bought in the last 2.5 years 41 million shares. We spent about $1.2 billion around share repurchases. I’ll probably get criticized from a few guys because some of those shares we brought at high year prices. We raised our dividend numerous times, and I’ve made comments to the investment community that when we have the hydrocrackers done, management will look at the dividend and make a recommendation to our Board. So we’ve done that.

Methanol has, actually it’s gotten some feedback from some of you that are questioning that. Well, Valero is very uniquely positioned at our St. Charles refinery. We have a lot of hydrogen production capability. We can pull this syngas of these plants. We can build on ethanol plant for half of what the grassroots methanol plant can be built (inaudible) and with all the hydrogen capability of our own plants and third parties, we think we have an opportunity here to add significant shareholder value.

So I feel strongly that this is our job and whether this or alkylation or adding some crude capacities around light sweet crudes, which we don’t have at some of our plants. We certainly don’t want to be buying feedstocks when I am absolutely certain. The light sweet crude is going to be very long on the Gulf Coast. These are the type of jobs I think that are clearly in our shareholders interest, but it has to be a long-term thought process because basically just about anything we are doing anymore with permitting and it now takes us four to five years. So that’s kind of how we look at it.

Evan Calio – Morgan Stanley

It’s really helpful. If I just, a quick follow-up and I’ll leave it there. Within 2014, I guess for CapEx, I mean the categories are spending similar to 2013 in terms of growth versus maintenance and your MLP-able EBITDA growth rate if you will?

Joe Gorder

Yes, because some of those projects we’re talking about, we won’t spent that much anyway. We get the railcars coming in, the logistics is still. All those projects are still significant part of that spending as next year.

Evan Calio – Morgan Stanley

Great. Thank you, guys.

Operator

Thank you. The next question comes from Robert Kessler from Tudor, Pickering, Holt.

Robert Kessler – Tudor Pickering Holt & Co., LLC

Hi. Good morning, guys. Two questions for me on transportation economics and logistics assets, one on barge traffic. Your recent presentation highlighted 20,000 barrels a day to 30,000 barrels a day in barge deliveries in the Gulf Coast. I’m curious if you have any more color on the pace of increase there and from where and to where you’re moving? Presumably you are moving kind of west to east. But I’m curious if the volumes have picked up and what you are seeing in the market for barges on the coast, are you getting into a tight market situation there? And then, I’ve got a question about railcars as well.

Joe Gorder

Yeah, Rob, this is Joe. I mean, our barge volumes have been pretty consistent. I’d say if you look at everything, we are moving probably 90,000 barrels a day. We barge sweet crude into Houston. We barge sweet crude into Meraux, Memphis, receives Bakken. It will come up from St. James from barge periodically. St. Charles is receiving Cold Lake or they can heavy sour from higher crude down there and then we have a little bit of barge volume around corporate. So the major change there as far as our volumes go, okay. That’s all I have there, so.

Robert Kessler – Tudor Pickering Holt & Co., LLC

Okay. Yeah, thanks for that. And if you wanted to pickup additional barges say in the spot market, your senses that would be available for you?

Bill Klesse

Yeah, I think in the spot market, it is a snug market, okay. I mean barges are being highly utilized and Jones Act vessels, which you could move products for crude on are very tight, and the prices have gone up on those. So there is not an abundant supply, but what we are seeing is and hearing from the barging companies is they have got so many barges under construction that we are going to find ourselves inadequate supply going forward.

Robert Kessler – Tudor Pickering Holt & Co., LLC

Okay, thanks for that. And then on the railcars, obviously the changing dynamics of this spreads of light has let’s say, marginalized railcar transportation economics in the short-term, and just putting that in context with your capital program, you have previously stated plans for significant expenditures on railcar purchases, I think in fact that 850 million, it’s the single largest of the spinning bucket you have outlined in your investor presentations, and I know that that’s for optionality in feedstock in the like, but it sort of brings a question about the possibility of marginalized railcars sitting idle in the portfolio down the road. How do you think about that potential scenario in your overall capital budgeting process?

Bill Klesse

Well, there are two things I would say. You are right. The volume has come off and a lot of it has to do with what we have seen with WTI coming in so tight and that’s affected it, that’s going to vary. And we expect that discount will open up again. So the thing that we give with railcars is, you get tremendous optionality and where you move volumes and we are railing, we are actually railing now some bitumen down to Port Arthur, and that wasn’t in our plan, but we have been able to get that and we are taking it across at commercial drop down or a commercial terminal down there.

If we look out a little bit longer-term, Valero has over 6,000 railcars that we currently lease. We use them to move asphalt, we use them to move LPGs, what we’re adding to our fleets, worst-case scenario, we would go ahead and displace these leased railcars and use the ones that we purchased.

So we still feel good about our decision to go ahead and get these cars. I guess the fact that we have leased cars provides us a hedge on the downside, but we fully expected as these markets go back to a more normal pricing, which we expect WTI discount to go back out to $7 relative to the Gulf Coast, Bakken open up again, and I think we are going to see more normal discounts, which will put the railcars right back in the market.

Robert Kessler – Tudor Pickering Holt & Co., LLC

Understood, thanks Joe.

Operator

Thank you. The next question is from Doug Terreson from ISI.

Doug T. Terreson – International Strategy & Investment Group LLC

Good morning everybody.

Ashley Smith

Good morning Doug.

Doug T. Terreson – International Strategy & Investment Group LLC

Bill, returning to your comments few minutes ago about your meetings with Congress last week, and specifically on the renewable fuel standard, I wanted to see if you would comment on whether you feel that the industry is making progress in this area, and having its position understood, and any of the guidance for consumers, and also any updated opinion that you may have on whether changes might be ahead in this area, and also what you think there might be, just kind of a progress update on where we are headed with this?

Bill Klesse

Well, I think everyone on the call understands the RINs issue, and your assumptions when the 2005 and then the 2007 law were passed are very different today than before. The issue boils down to just a few things cellulosic is not available. That is not on the EPA's website, everyone says there is going to be a little cellulosic production this year, but it's totally uneconomic as well. I think it was clearly, let's pass the law and they will come, and it hasn't happened.

The other part of the regulation that is clearly you pass part of this advanced biofuels in the sense of the ethanol fees and this, so you get cellulosic. Then the other part of it is, it encourages you or you have to buy Brazilian sugarcane ethanol or somebody sugarcane ethanol. We have a law that encourages you to import over producing domestically.

And then on top of all of this, gasoline demand has not continued to grow. It's actually down and now flat. So the whole thing is screwed up and that's why, I said the other day it needs to be redone. And I'm supporting the industry position. I accept that. It needs to be done, redone because Valero is a little bit unique, and that we are a significant ethanol producer and we are also a significant renewable diesel producer. So we think E-10 is part of the fuel mix.

We think E-85 is part of the fuel mix. We have no issues with renewable or bio-diesel. We think that's all fine. Some of this technology is pretty damn good. But the EPA solution of going to E-15 is not practical. There are no facilities. Even the service station people are saying they don't know about their tanks and lines. That is no, hardly any certified pumps and you have the car warranties. I understand some of the 2013 car warranties saying, it's okay, but there is a whole lot of culprits out there besides this. So the whole thing needs to be redone.

The whole thing is basically with RINs is now, as I got quoted everywhere, it is out of control. RINs were in the preamble of the EPA’s regulations that they were not going to be significant. They were there to give the industry flexibility and they give the EPA a way to monitor and now it’s become a huge issue and so it just needs to be completely redone.

So where do I think, it’s going? Well, the EPA doesn’t seem to be able to do anything, and so it’s a White House or Congress conversation, and the only way the White House will move is they get enough political pressure frankly from consumers, because at the end of the day, the consumer is going to pay for this.

Doug T. Terreson – International Strategy & Investment Group LLC

All right.

Bill Klesse

And they get enough pressure from consumers or the option that you see happening, and there will be some bills introduced here is over in Congress and the House and in the Senate, where people are at least understanding that this, the basis of the law are not appropriate anymore, yet there will be some compromise, so I am optimistic.

Doug T. Terreson – International Strategy & Investment Group LLC

Okay.

Bill Klesse

That we are going to get something out of Congress and then the President will have to make a decision that is it backtracking or is it just fixing a problem. The earlier question is the realty, this is very unfair in the street, because you have winners and losers at retail and clearly in the refining segment, this is hurting the independent refiner, it is not hurting the majors. So you are actually hurting the independent guys. And it's that what you really want to happen, so I think we will get some congressional action, but I am not sure you're going to see anything this year.

Doug T. Terreson – International Strategy & Investment Group LLC

Okay, and then on methanol, I mean the outlook for that business is pretty positive for the next several years. And you’ve talked about some of the rationale for the new plant, but I want to see if you elaborate on the competitive advantages, and the synergies that you referred to with some of your existing operations? And also what you guys plan to do with the product once you manufacture, I’ll recognize that it’s a way down. But if you can just kind of cover those that would be great?

Bill Klesse

So now you're jumping from the ethanol business to the petrochemicals?

Doug T. Terreson – International Strategy & Investment Group LLC

I am.

Joe Gorder

Ethanol to methanol?

Doug T. Terreson – International Strategy & Investment Group LLC

Yes.

Bill Klesse

Yeah, from ethanol and methanol, okay. Because we think on ethanol, we just think it is fuel mix and we think we have a decent business there. And our people are doing a fine job. So I remember the old saying because renewable fuel, old saying, the renewable fuels association, 'Pigs get fat, hogs get slaughtered'. We got a good business there and everybody corn prices are up, farmland is up, it's part of the mix, it's accepted by the consumer, so I think some balance needs to get worked into this.

On methanol, because we have our own hydrogen plants at St. Charles, we are able to strip the sun gas before we finish and make hydrogen. We can take this sun gas, so we really don't have to build the front-end of methanol plant.

Doug T. Terreson – International Strategy & Investment Group LLC

All right.

Bill Klesse

And because there is a lot of supply capability and additional capability from an individual plan, when you look at the whole steam sink everything that you have around this. This is why I am saying we think that we will be able to build those plants for about half of what the grassroots plant 60% of the grass-roots plant.

The other thing is we used to be in this business. We’re in a joint venture down in Houston. We had managed our shutdown when natural gas prices were going up. Obviously it was part of the MTBE business as well and use methanol to do that. But methanol is a way to move methane in a liquid from, if you think about it. And so, we just think it’s a nice little bolt-on and we’ll develop it little further. But we felt it’s important to get it added into our marketplace, and Valero was looking at this.

Doug T. Terreson – International Strategy & Investment Group LLC

Okay, great. Thanks a lot.

Operator

Thank you. The next question is from Paul Cheng from Barclays.

Paul Cheng – Barclays Capital

Hey, guys. Good morning. Maybe this is for Joe or may be this is for Bill. Bill, I was looking at, I’m trying to understand between the difference in the ethanol business, how you invoice your customer and in terms of, say, in the reformulated gasoline, when you invoice it you will have, say, what is your charge for the alkaline and what do you charge for ethanol as the price, Bill?

If then we really plan that much different that we can’t move into the same system related to RIN. I mean that you could have two invoice if your customer want to buy the coupon reformulated gasoline including ethanol. So you will have to invoice that with the (inaudible) and then also separate item as ethanol. If they just want to buy the niche gasoline with alcohol, with our ethanol, so you have that and then you have a charge off the RIN given that every single refiner who sell to someone with our ethanol have to pay for that RIN.

It seems now it’s just part of the parcel, possible yet. By doing in this way you have the benefit to crystallize and make it very transparent, what the consumer ultimately is paying for then, and as we say, Congress is not going to do anything until that they get the topic outlined from consumer, and perhaps we will help the process. And secondly that is also making, I think that water usage so that we'd don't get confused that these investment community that how much is being possible or not possible? So, if there are any hurdle or obstacle – why the industry and including you guys as the leader why not moving into that

Bill Klesse

Well, I will let Joe and Gene add to this, but remember when you blend, that's when you can separate the RIN, theoretically the RIN has no value till you blend it. Now it all of a sudden the value, and because we can't get – if you don't count the carryover from 12, because you can't get to the mandated volume, you’re short of RINs in the market. So you are just short. Now I understand you're asking about a whole pricing mechanism here, but RINs have taken on the life of their own, they are a market in and of themselves now.

And then at the rack, you have to be competitive. We sell ethanol at the market price, we sell gasoline at the market price, and so if the whole industry moves to some different pricing relationships, I'm sure you're correct, but unless the industry moves you can’t capture it.

Paul Cheng – Barclays Capital

That seems – yes, exactly what happened in 2005-2006, when we start moving into the ethane, there is a lot of confusion and you will never would expect to go ethanol, it’s a separate item in the invoice. But by 2009, I think the only industry moved, I’m just curious that you said anything stopping because everyone selling to their customer without the attachment of ethanol need to recuperating. So it seems like that is also fair because the stand that the guy that were buying the fuel, reformulated gasoline and they don’t pay for the RIN?

Joe Gorder

Yeah, I mean Paul, Bill answered it I think correctly.

Paul Cheng – Barclays Capital

You guys have an answer to this?

Joe Gorder

No, I don’t have.

Bill Klesse

It’s a competitive process and if you try to keep the RIN and other suppliers that’s in the terminal is going to give the RIN to the customer, you are uncompetitive, so it’s all got to balance out, it’s a very fungible market out there, whether it would be the spot level or ethanol level.

Paul Cheng – Barclays Capital

No. I understand that. What I am saying is that, you’re making it crystalline and transparent for everyone to see and to know that what is that priced at they are paying and so we don’t have the confusion.

Mike Ciskowski

Well, I think it’s something we can kick around Paul, clearly we are just not there yet and we got to think through what the competitive implications are.

Paul Cheng – Barclays Capital

All right. On my second question then, can you just give that the $2.5 billion, $3 billion for next year for the CapEx, is that new norm for the Company going forward, and at least for the next several years. I mean I think last year that we have been talking $1 billion, $2 billion, $2.5 billion, so is that now changed into this $2.5 billion and $3 billion and if that’s the case how is that impacting in terms of your outlook on raising your recurrent dividend payout?

Mike Ciskowski

Well, I have never given longer term guidance than about two years out, I have said and I have thought 2014 would be in the $2.5 billion range previously and all we have done here is say, hey, it’s $2.5 billion to $3 billion. So to me, we’re still in the range, we are still in our budgeting for next year.

So whether it is the new norm or not, I don’t know, I think it depends on whether or not we believe we will add value through some of these discretionary projects. I have said several times that our stay-in business, when I call the whole making an agenda to business, turnaround, regulatory, all of that seems to run somewhere in the $1.6 billion to $2 billion range. And then on top of that we add this discretionary area. But your main question is, it's bout returning cash to the shareholder and I think that if we have projects that add greater value, we're going to presume and if we don't we're going to return the cash to the shareholder and I don't see that as one big change from what this management team has been doing.

Paul Cheng – Barclays Capital

All right. Thank you.

Operator

Thank you. The next question is from Roger Read from Wells Fargo.

Roger D. Read – Wells Fargo Securities LLC

Yeah. Good morning.

Joe Gorder

Good morning, Roger.

Roger D. Read – Wells Fargo Securities LLC

I guess may be just to change the subject a little bit. Light-heavies obviously had an impact on Q2. Can you help us understand as we're looking at Q3 where if you measure by LLS, light-heavy spread is pretty attractive. If you measure it by Brent WTI not so much, kind of what you're seeing move out there and what do you think really will sort of drive the market here over the next or let's just say, through year-end in terms of the most important marker on the light side of that argument?

Joe Gorder

You mean which would be more important like a Brent or an LLS or TI?

Roger D. Read – Wells Fargo Securities LLC

Yeah and maybe how LLS fits in, in terms of driving the Gulf Coast market there.

Joe Gorder

Right, so Roger, if we think about what's happened in this quarter, we obviously we had Brent WTI coming in a material way. We saw LLS move out and get priced at a more significant premium to Brent. I mean a lot of that has to do with the simple fact that, if we ended up being shorter in the Gulf Coast on light sweet crudes, than perhaps the market anticipated. And we’ve said all along that the pricing of sweet crudes in the Gulf is going to be dependent on the quantity of domestic crude that’s there, and we saw that we did have a bit of short supply, and there is a host of reasons for it. I mean, we had Syncrude outages in Canada that reduced the volume.

We got BP Whiting still running light sweet crude, which has supported Bakken prices at Clearbrook. Bakken is pricing up in the field, that’s an LLS plus transportation or adjusted for transportation, which is making it expensive. But it’s expensive because it was in tight supply.

So I think as we look forward into the third and the fourth quarters of this year. We are going to have more takeaway capacity out of Cushing and out of the Permian is going to bring those barrels to the Gulf, okay. I think that you will see more volume coming on-stream and moving into Cushing, so the inventory droughts that we saw will probably stabilize here a little bit. And so what’s that due to the overall crude markets, well, I think you’re going to see the light sweets, I mean our view is that LLS will trade down, and we will trade at a discount to Brent.

Longer term I think we’ll see the WTI spread back out to maybe a $6 to $8 discount. And I think we will see the medium sours will adjust and priced themselves into the refinery. And then we’re getting some relief on the heavy sour discounts now, the Mexicans have adjusted the K factors aggressively as they can over the last several months, and they have adjusted a $1.90 and that will take affect on August 1, which will increase the discounts on the Maya, which effects of course all the other heavy sours.

So I think as we look at the, we saw all the discounts on crude come in, in the second quarter. I think we’re going to see them start to move back out in the third and the fourth quarters.

Roger D. Read – Wells Fargo Securities LLC

Okay. That’s helpful. And the unrelated second question, probably more for you, Bill, getting back to the CapEx versus dividend versus share repo evaluation, what are the rough returns you are looking for or what are the various ways you analyze what makes the most sense for Valero to do at a given moment in terms of investing in the methanol plant versus, say, a more aggressive share repo program or accelerated, maybe I should say rather than aggressive?

Bill Klesse

Well, so many of these plants are bolt-ons or extensions of our business. Because you’re capitalizing on the whole refinery that’s already there, these returns all are north of 25%, on all of them. These are IRRs. So, and we get into a huge conversation here, what is our cost of equity and I’ve even had it with a lot of you that are on the call, and so we look at it and we try to balance and what you’ve really seen with his management team and I keep going back to this is we’ve bought our shares every single year that we’ve been of this as part of this management except 2009 and 2010. And the other component here is next year we only have $200 million of debt that matures and year after that we only have $500 million of debt that matures. So we also see that we have ample cash flow coming out as well.

So, I think some of these projects are very good returns. We look at that. We look at where our equity is priced. It’s obviously down from where it was and don’t forget we spot out for the shareholders of CST as well. So I think we’re very shareholder focused here. The only caveat I really stick on is it’s long-term. You got to think we’re looking at long-term shareholder value, not tomorrow afternoon.

Roger D. Read – Wells Fargo Securities LLC

Okay.

Bill Klesse

And we want a dividend that sustains, that we can sustain.

Roger D. Read – Wells Fargo Securities LLC

Okay. So when you are looking at the share repos, not necessarily – it’s more a free cash flow driven than it is a return analysis, summing in other words, you are not going to worry so much about the share price at a given moment as you are, that’s part of what you are doing or is it more to within that?

Bill Klesse

That would be correct. Back couple of years ago, we made a decision. We weren’t going to buy any refineries, because we thought they were too high priced and we turned around and had a very significant share repurchase. So, yes, we have free cash flow. We have enough cash where we said our cash position is solid. We are going to maintain this investment grade rating. Then, yes, we are going to return the cash to the shareholder.

Roger D. Read – Wells Fargo Securities LLC

Okay. Thank you.

Operator

Thank you. The next question is from Doug Leggate from Bank of America.

Doug Leggate – Bank of America Merrill Lynch

Thanks, fellows. Good morning. Bill, maybe I could just change talk again a little bit to the MLP. I know you’ve kind of suggested now that you are probably moving forward here, but you spoke to this $50 million to $100 million of EBITDA, but as we look through your presentation, but there was a fair amount of MLP related expenditures. So can you help us a little bit with how you see this scale about EBITDA ultimately and what the kind of timeline is to get there?

Bill Klesse

Well, we have said and I think this was 2012 assets kind of where we had $50 million to $100 million of EBITDA and that’s probably the range of where we’re looking to go out initially. And as, Mike Ciskowski running this project for us here and he tells many that getting everything done, this is probably a first quarter of 2014 projects subject to of course our Board. And then, so we’re doing all of that.

Obviously we’re adding a lot of projects, pipelines, railcars, terminal enhancements, so rail facilities to unload and all of these assets are MLP-able. What we have said is our focus would be in the sense of a terminaling and distribution MLP, because some people has asked us about other assets and we said, well, our focus is more there. But obviously we have put many more potential dropdowns going forward.

Doug Leggate – Bank of America Merrill Lynch

Okay. Then you want to be drawing in a number, Bill, but just to keep it contacts. Obviously you’re spending about $1.7 billion over the next, it says five years in the presentation, but it is really five years or is that a little quicker than that?

Bill Klesse

It will be quicker than that.

Doug Leggate – Bank of America Merrill Lynch

Okay, great stuff. We can figure it out from there. Last one from me though is to go back to the RIN question and it’s really, just on your guidance that you gave for the full year. If I’m not mistaken you’d talked to the $500 million to $750 million before, but RIN prices were like $0.75. Now they’re up 60% from there and you’re barely above the top end of that range in your guidance. Can you help us understand why we’re not getting kind of proratable impact and it sounds like there will not be a lot of change in your cost even though the RIN cost has doubled, and I’ll leave it there. Thanks.

Bill Klesse

Well, part of it has to do with where we bought these RINs and our position in the whole process, plus there is assumptions in our numbers as to export volumes, how much we’re capturing and all of that. So that’s based in there as well. But this is the range that we’re operating in now, $600 million to $800 million, but clearly if it’s $1.50 a RIN, we’re at the high end of the range. So, but we’re only in July.

Doug Leggate – Bank of America Merrill Lynch

Right, but what I’m trying to figure out is that, your previous range where the high end was $750 million and the RIN price was $0.75. Now the RIN price is about $0.36 and your high end is only up $50 million. So why only such a modest increase?

Bill Klesse

Well, obviously at the high end, I had a range of [$0.04] I mean, I was probably at the low end. So I think you just have to accept that we’re not misleading you. This is how we are viewing it. You guys are asking us for guidance and I’m saying to you, okay, $1.36. I always use $1.48 or something, but these higher numbers will be at the high side of our range. It has to do with our position as to when we bought a lot of these. So there is a serious timing component and volunteer.

Doug Leggate – Bank of America Merrill Lynch

So this is for 2013. Does it change the markets in 2014? Does it change significantly?

Bill Klesse

Absolutely, it will change. Remember when we first started this, they were $0.75, and in January or February they were still $0.05 and then they started moving up. They went to $1. They pulled back to $0.60, $0.70. Then they got back. But next year it would be a much larger number at $1.50 a RIN.

Doug Leggate – Bank of America Merrill Lynch

Right.

Bill Klesse

We’ll get into the conversation, well, how much a RIN is going to be in 2014, because you’re totally unfeasible.

Doug Leggate – Bank of America Merrill Lynch

All right. Okay. I’ll leave it there, Bill.

Bill Klesse

No, seriously because you have the carryover from 2012. So that’s the big debate this year, but you’re going to have to carry from 2013 into 2014. You can carry in 20%, but there are going to be enough rooms around. So all the way it’s totally not feasible next year.

Doug Leggate – Bank of America Merrill Lynch

All right, Bill. Thanks a lot. Appreciate that.

Operator

Thank you. The question comes from Paul Sankey from Deutsche Bank.

Paul B. Sankey – Deutsche Bank Securities, Inc.

Hi. Good morning, everyone.

Bill Klesse

Hello, Paul.

Joe Gorder

Good morning, Paul.

Paul B. Sankey – Deutsche Bank Securities, Inc.

Howdy. Thanks, well, for the CapEx guidance, early CapEx guidance. We appreciate that. Bill, you mentioned really part of my question, which was the $1.6 billion to $2 billion that you have the ongoing stay-in business CapEx.

Bill Klesse

So our DD&A is running on about $1.6 billion to $1.7 billion, at $1.7 billion, and I think it’s very unrealistic to assume we don’t have to spend DD&A or maintain our assets.

Paul B. Sankey – Deutsche Bank Securities, Inc.

Let’s see. I mean effectively one way of looking at this has even effectively doubled your growth CapEx at the margin, but we’re coming of two huge projects in the past year or so that have come online. I’m just wondering what the components are of the new relatively high number for growth CapEx. Could you list the biggest on several projects that you’re going to be investing in? Thanks.

Joe Gorder

Yeah, Paul, the best guidance we can provide right now about those details would be on slide 19 of our latest IR presentation, which we presented earlier this month and that’s focused on 2013, but the 2014 details are largely in line with that. As we get later in 2013 and we complete our strategic planning process, we’ll be able to hung that and give you the specific chunks, but it’s very similar. We also have specific continuation of spending on existing processes or existing projects. And keep in mind, as Bill said earlier, they’re long-term projects. I know it takes you guys a second to update your model, but it actually take years to get permit and construction and do all these things and to spend the money.

So, in order to achieve the returns Bill talked about earlier, it does take some time and that’s why there’s generally going to be continuation of existing projects.

Bill Klesse

And then on slide 32, in that same hand out we gave a little EBITDAs with some of the projects as well, okay. So if you can teach together how we’re looking at them.

Joe Gorder

We’ll update that later this year as we go through our planning process and complete that.

Paul B. Sankey – Deutsche Bank Securities, Inc.

I think that you’re referring to Deutsche Bank models. By the way they’re actually with Deutsche – you’re looking for from a planning. So thinking about how you decide on these investments, I’m looking at your cash flows that are low in 2009 of little bit under $2 billion, maybe last year $5 billion. Is that how we think about it, and we’ve been asking this question in various ways on this call obviously, but I’m just wondering another way of looking at this is that you’ve doubled your – effectively doubled your growth CapEx to the margin against the expectations. You could have effectively doubled your free cash flow, especially in a high risk RINs environment. I’m just trying to drill down into why you’re spending so much money basically. Thanks.

Bill Klesse

Well, if you look at the logistics capital, it's kind of being intact, so in place and I'll just try to add clarity here the place where I'm sure some of you guys are wrestling with is in this whole petrochemical methanol area, and our view is that the marketplace is giving companies like us a huge opportunity that add a lot of value for our shareholder. We expect low cost natural gas, that's why the hydrocrackers looks so good.

Paul B. Sankey – Deutsche Bank Securities, Inc.

Thank you. For the years, you are assuming Bill that $4?

Bill Klesse

No, that’s up $5. We think the number needs to be a little higher long-term, so that the drilling industry can make a reasonable return. There seems to be a debate sub four, how much return you’re getting, but if you get into the $5 range, we believe they can make a return, no. You guys would know more about that I suppose than us.

But then you look at the butane is coming, here we have alkylation units within our refineries right now. These things just look like something where Valero and its shareholders can really benefit.

Paul B. Sankey – Deutsche Bank Securities, Inc.

Yeah I get.

Bill Klesse

So we’re studying it and we're getting it out there, so at least you guys know these are the things that we are looking at.

Paul B. Sankey – Deutsche Bank Securities, Inc.

Okay. Can you give us a sense of how much more light sweet crude you think you will be able to run, let's say, by the end of 14?

Bill Klesse

Yeah, well, actually can, because we our projects weren’t quite be done.

Mike Ciskowski

Yeah, by 14 not a whole lot more, it's not till these the toppers have done in early 2015 that would be able to increase those. And those I think…

Bill Klesse

Go back and 14.

Mike Ciskowski

Yeah but if you’re really talking – it’s not until 2015 conversation. But if you take the Houston plant, it is 70, down in Corpus it’s 90, we’re looking at Port Arthur where we have a ideal crude tower. Our excess crude tower in excess basin tower is probably 50,000 to 75,000 and we’re something – Quebec is already a sweet crude refinery but we’ll be subbing in North American crude more and more as we go through time. And then at Meraux, we’ll be running more liner crude there as well. So (inaudible) price et cetera significant, then we have these little change or add this deal here and repipe this project that’s going on too. But as you – he’ll give you numbers.

Joe Gorder

It’s 160,000 barrels a day.

Paul B. Sankey – Deutsche Bank Securities, Inc.

For those two?

Joe Gorder

For those two.

Bill Klesse

My counting then the other one that I just said, so we’ll pick up another 50 to 100 to Port Arthur and Meraux.

Paul B. Sankey – Deutsche Bank Securities, Inc.

Okay. So in closing from me, end 2015, how much more slight sweet would be if you like a substitution and how much more would be incremental throughput in what throttle. And I’ll leave it there. Thanks.

Bill Klesse

Some with all the incremental throughput, so as incremental throughput backing others our feedstock purchases. So remember we buy Algerian Resides, a lot of those that we bring directly into our units, we bring some other of these feedstocks in that basically go to the cads and instead we’ll be making a lot of our own gas oil.

Paul B. Sankey – Deutsche Bank Securities, Inc.

Okay. Is all incremental replacement, a bit confused? Is the (inaudible) capacity is higher or lower?

Bill Klesse

The overall crude capacity will be higher per share.

Paul B. Sankey – Deutsche Bank Securities, Inc.

I know that.

Bill Klesse

Not our throughput capacity.

Paul B. Sankey – Deutsche Bank Securities, Inc.

Got you. Okay. That's great. And so...

Bill Klesse

Remember we run today, I guess officially we'd say we're 2.3 million barrels to 2.4 million barrels a day of crude, but we’re 2.8 million barrels to 2.9 million barrels of throughput, because we're buying these other items.

Paul B. Sankey – Deutsche Bank Securities, Inc.

Yeah. And I don't want to take up the whole call, but that's very helpful, and I will come back potentially with more. Thanks a lot.

Bill Klesse

Okay.

Operator

Thank you. The next question comes from Arjun Murti from Goldman Sachs.

Arjun N. Murti – Goldman Sachs & Co.

Thank you, and sorry for another follow-up on the RINs, but if you look at the 2014 and I agree with your comments and how unworkable the RFS looks, can you talk about to what degree you guys can crack up your exports to help offset some of your RIN obligation next year relative to what you might be doing this year?

Bill Klesse

Well, it depends on the cost of the RIN. So you have to have a basic crack. So sooner we'll have a basic crack that says, hey, it's profitable to make those barrels. Then you have if RINs are $1.50, technically you have $0.15 a gallon here that you're playing around with. So you can be very competitive going in export versus the U.S. market, as far as ramping up.

Joe Gorder

Ramping up the exports.

Arjun N. Murti – Goldman Sachs & Co.

I mean if the industry is basically out of RINs next year and you guys are on the coast who do have export capability, I mean again Congress is going to have to take actions at some point here, but in the absence of that it seems like you could have a very, very high RIN price well above where you are today.

No one wants to shut in their unit, which I guess is the other way to not have a RIN obligation, it would seem like exports is one of the outlets and you guys would seem to have the better position to do that, but just trying to kind of see if we can frame how much you could reduce your volume metric RIN obligation next year, if it’s whatever the right phasing is very, very high RIN price, much higher than where we are right now.

Joe Gorder

All right, so Arjun, let’s assume that the markets out there for the barrels to be exported, okay, and as the Arabs support the exporting and just as an example, we exported 70,000 barrels a day of gasoline. In the second quarter we exported 170,000 barrels a day of diesel. Now those numbers are what they are because we optimize the supply into the marketplace. We had a very strong market to add to because, yeah, Joliet turnaround, and Whiting turnaround, I think we’re down and so we’re able to move barrels to that higher market.

Barring that and saying that the market was demanding the barrels abroad, we could go to 225,000 barrels a day of gasoline and 280,000 barrels a day of diesel and then the projects that we’ve gotten underway to improve docks and tankage and segregations at the refineries would allow us to take it up beyond that going forward, particularly with the same trial hydrocarbon coming on and the quality of the diesel fuels that we’re getting out of St. Charles and Port Arthur. So there is capacity.

Bill Klesse

I think Joe is giving you a capacity conversation and I don’t think it’s realistic because the industry is in the same boat and so yes, we are on the Gulf Coast and we have that capability, but so like other people and you get down to the basic, you got to have the basic racks. So yes, the way you’ve phrased your question, Joe answered you, yeah, we would have capability. Yes, we are on the Gulf Coast, so we could do that, but I would not want lead you down a path that this would be a significant solution for us. I don’t think so.

Arjun N. Murti – Goldman Sachs & Co.

I appreciate, yeah, go ahead.

Gene Edwards

It’s Gene, I would just add to those that both of these solutions there, exporting more ore reducing refinery runs, reduce supply, so to Maya really doesn’t go down, which we don’t think in the next year. We got to meet demand, but still to me it’s definitely got new price in the cracks on the U.S. basis and maybe lower basis for exported barrels.

Arjun N. Murti – Goldman Sachs & Co.

No. That to me would be the mechanism right by which you then get the true pass through, especially if the U.S. economy recovery and the demand is there, do you guys either supply less, which I don’t think you do, but potentially export more, it’s clearly a mechanism to get the pass through, but I appreciate your counter and the answer, thank you so much.

Operator

The next question is from Edward Westlake from Credit Suisse.

Edward G. Westlake – Credit Suisse Securities LLC

Hey good morning, yeah there are obviously a lot going on in refining, lots of questions. I guess the 2Q Gulf Coast was probably the weakest absolute number that we’ve seen for a long time. I guess despite the first hydrocracker, and that’s also despite, there is some cheap Eagle Ford coming into the Corpus. Clearly light heavy is weak, but is there anything else material going on that we should focus on, and I guess if not and it’s like heavy expands again overtime, you should go back to a more normal capture?

Ashley Smith

Yeah, that’s it. I mean, when you are referring to light-heavy either you are talking about really kind of the sour crudes versus the sweeter crudes in general?

Edward G. Westlake – Credit Suisse Securities LLC

Yes.

Ashley Smith

Because, they were – you are right. The discounts at all of those crudes relative to the sweet crudes were off and we should just like, we ran about the same amount of heavy sour crude. Core Q2 2012 versus Q2 2013, we ran quite a lot less medium sour though, because it tended to be just out of the market. Now, on the heavy sour side, we don’t provide all of our heavy sour for example, Maya so we had some advantages there. But I don’t know of anything else overlaying, I don’t know of anything else going on in the Gulf other than that.

Joe Gorder

Well, we make a lot of other products and they are all moving around, but if you take our poor relative refining which is a very (inaudible) Maya crude oils, it did very poorly in the second quarter.

Edward G. Westlake – Credit Suisse Securities LLC

Okay.

Joe Gorder

Even with its new hydrocracker.

Bill Klesse

Yeah, and that…

Joe Gorder

Okay, due to the pricing of Maya. So you can see that have a huge impact.

Edward G. Westlake – Credit Suisse Securities LLC

And then a second question, more broader around the Texas market I guess, I mean you’ve got the Eagle Ford growing some decent Permian well results. Recently you’ve got two major pipelines probably more coming down into Texas. I mean, do you think there is a limit on the effective capacity of the industries to move those barrels over to Louisiana or earlier you spoke about there being enough barges, but it feels like there is a lot of volume and it could cause some stress, any color on that would be helpful.

Joe Gorder

Well, I think as the volume comes into Houston eventually here it’s got to move east. And so you’re going to have shales pipeline running, which have the very high tariff, which is a lot higher than barges. So I think you’re going to see the barges, you’re going to see assets come into play here. Of course it’s got to move. It’s got to move along the coasts, and one of our competitors have signed a deal to take to ship it up to the East Coast by water as well. And so you’re going to see it moving and to us Houston is going to be the bulk of quite of all in this.

Edward G. Westlake – Credit Suisse Securities LLC

And I mean in terms, I mean obviously does any limit how much light you can run I guess moves across, but as you talk to your major suppliers, I’m thinking Mexicans obviously those mediums coming over from the Middle East. How do you think they're going to respond to the fact that not just yourselves, but the whole industry on the Gulf is going to probably looking for less of their products.

Bill Klesse

Well, it remains to be seen and there will be political considerations as well, because I mean Valero, we buy from the Persian Gulf suppliers. And they have a stake in this market, and their crude is more medium than this light that we are talking about, but this isn't today's issue and it’s probably not tomorrows’. This is probably a 2015, 2016 conversation, but over time the U.S. is going to have a lot more oil on the Gulf Coast than I think the refining industry got to figure out how to run it.

Edward G. Westlake – Credit Suisse Securities LLC

Thank you. That's very clear.

Operator

Thank you. The next question comes from Faisel Kahn from Citigroup.

Faisel Kahn – Citigroup

Hi, good morning, it's Faisel from Citi.

Ashley Smith

Hey Faisel.

Faisel Kahn – Citigroup

Hey, Ashley. Just another ethanol question, I guess how difficult would it be for you guys to increase your blending capability, and I know you sell a certain amount of merchant volumes, and you blend some of your volumes, but how difficult will it be to increase your blending capability given your natural supply of ethanol here and your production of gasoline?

Joe Gorder

Well Faisel we are looking at increasing it everywhere we can as you would expect and for example, with the Diamond Green project, we're going to have a lot of renewable diesel that we can blend it to the pool. But we're looking at every asset we have, and if it requires some modest investment to increase the blending capabilities there, we're going to do it. And but generally said, I mean we just don’t have access to the terminal assets to control blending up all the products that we produce. We are a merchant refiner, and we sell a lot at the plants of the refinery and we just don’t have the opportunity to blend that up.

Faisel Kahn – Citigroup

Okay, understood.

Mike Ciskowski

So we are blending where we can and diesel side is what Joe is talking about more, because we have a customer base here.

Faisel Kahn – Citigroup

Sure.

Mike Ciskowski

And the customer base goes into a terminal, I mean everybody sees I guess somebody said the $1.36 RIN. So I mean it’s a matter of customers as well. So where we can we have added facilities where we are blending, but clearly the marketplace is in disarray because the wholesale racks theoretically anyway you got all these different prices now.

Faisel Kahn – Citigroup

All right, fair enough.

Mike Ciskowski

We are trying to minimize, if the question is that you are trying to do things to minimize your exposure, the answer is absolutely.

Faisel Kahn – Citigroup

Okay, got it. And then just last question from me and the call is being going on for a while. On the potential investments in natural gas liquids and also alkylate sort of investments, can you talk a little bit and little more granularity and kind of where, what type of assets you are looking at building and where you are looking to doing that, is it fractionation and where would it be and also on the alkylate side, where are you looking to increase your production of alkylate?

Mike Ciskowski

Well, so it’s not fractionation per se. We don’t think I answered this on the last call, last April. I don’t think we add value per se just to build the fractionator. But where Valero, we don’t really have a competitive advantage over some of these guys like enterprise for instance, you can come in and build fractionator, but what we do, do is, we have alkylation units in all our refineries, alkylates are great blend stock.

When you look at how we make gasoline, gasoline, gasoline’s are Brent. If you remember that it’s made up of all these different components, and so as we look at our system. We have, we believe we’re going to very inexpensive butane subsequent to last, we have spend the last 10 years of our maybe 15 years of our careers, we’re moving butanes from gasoline. And the one way you can stick butane back into gasoline is by alkylating it, or making a longer carbon chain.

And so, as we see normals coming and converting them to butylene and you see cheap or inexpensive isobutane. There is we just think this is a good option in a refinery to be able to increase that the amount of that blend stock.

Faisel Kahn – Citigroup

It make sense within how, when where do you do that? And how are you, I mean what are the magnitude of investments, you make to kind of increase that capability?

Bill Klesse

Well these alkylate units would be $200 million, $300 million and all the sulfuric acid Valero would not build the new HF Alky and as we look at our system there would be on the Gulf Coast.

Faisel Kahn – Citigroup

Okay, understood. Thank you.

Bill Klesse

With one possible exception, for a different reason.

Faisel Kahn – Citigroup

Got it, thanks guys I appreciate the time.

Ashley Smith

Sure, thanks Faisel.

Operator

Thank you. The next question is from Chi Chow from Macquarie Capital.

Chi ChowMacquarie Capital

Great.

Bill Klesse

Hi, Chi Chow.

Chi ChowMacquarie Capital

Hello, hi Bill. How are you doing? I think you noticed this, hey just sorry to keep pound as the main issue, but Mike, can you tell us how the accounting works on your RIN purchase and how exactly that flow to your P&L.

Mike Ciskowski

Our accounting is based on whatever our RINs deficit is and we amortize them. We purchase forward, we have been purchasing a number of contracts and we amortize that cost in as a deficit basically created.

Chi ChowMacquarie Capital

Okay, great. And is that split by region as far as where that amortization goes in the cost of good.

Mike Ciskowski

From a regional standpoint, we allocate all of that based on throughput basis to the regions.

Chi ChowMacquarie Capital

Okay. So split in each region by throughput.

Mike Ciskowski

Correct.

Chi ChowMacquarie Capital

Okay. Got it. Thanks on that. And Bill, I just want to clarify, I think you mentioned on one of the other questions, the $600 million to $800 million on the 2013 cost, is that a net number net of some sort of pass through assumption?

Bill Klesse

No, that’s not a net number. That’s just what the deficit would cost us.

Chi ChowMacquarie Capital

Okay. Okay, good. Thanks for that. And I guess, final question on rail movements. How do you think this Quebec railcar accident is going to impact crude by rail going forward? Is they going to be more regulation costs? Any thoughts on that?

Mike Ciskowski

So this is Ciskowski. I don’t think it will impact in the sense of the extremes. I do think that you’re not going to see one person trains anymore. You are not going to see trains less sitting on the siding, full of products. I think it’s just one of those areas that people just hadn’t focused on and this is a very tragic accident and I mean, we all understand that.

So I think you're going to see more of the procedures. You’re going to see a very strong review of procedures. I think you will see the cooperation increased in North America here between Canada and the U.S. on regulation on – maybe on tank car design. You will see more on these bonnets beeping them up. I think also you'll have a conversation that will pull the Mexicans into this as well. But rail and crude, railing ethanol, railing distillers grain, railing corn, railing asphalt, propanes, they're all here. They are part of the distribution system. But there will be procedural things that will change. I mean this train was left below. I don't think you're going to be leaving a train on the side with nobody there anymore.

Chi ChowMacquarie Capital

Yeah. Sure. Not going forward.

Bill Klesse

But those kind of things will take a little time, but to me that's rare. We'll see more procedures and maybe it's in the operating area.

Chi ChowMacquarie Capital

You mentioned maybe changes in tank car design. Does that impact your deliveries at all going forward on your railcars?

Bill Klesse

That would not because there is no change in that, right?

Chi ChowMacquarie Capital

Right.

Bill Klesse

And then, if it is we operate a very – we strive all the time for safety and reliability and at some times we take a look at it.

Chi ChowMacquarie Capital

All right. Okay. Thanks, Bill. I appreciate it.

Bill Klesse

Yeah.

Operator

Thank you. The next question is from Allen Good from Morningstar.

Allen Good – Morningstar Research

Good morning. Just a question on the chemical investment follow-up. You mentioned some of the characteristics around St. Charles that made it attractive. When you look around your system, maybe what are some of the other opportunities you think for additional chemical investments. And if you do identify those, would you be willing to move forward with maybe several of these similar size investments at the same time.

Bill Klesse

Well it is a very fair question and we are looking at this because the market place is changing so quickly because I am of the belief that United States can have a huge manufacturing and petrochemical resurgence here, our government will figure out how to get behind. But we’ve looked at the Gulf Coast plans, there are in the sense of our crown jewel assets. They give you access to the water, because some products would be exported. Remember Valero was already in the benching time with xylene business. We’re already in the propylene business. So we’re in a lot of these businesses anyway, and so we are just talking about (inaudible), but they’d be along the Gulf Coast.

And would we take on several projects at the same time? Sure, we have the capability as the other companies do, they match projects in the capital spend level that we’ve guided you.

Allen Good – Morningstar Research

Okay, thanks. And I guess the second question is, early you mentioned that you expect some of these crude differentials that have narrowed in the first half of the year to widen back out. Well, this year, looking at your most recent presentation you have small lift here of rail and barge projects that you anticipate to come online later this year moving, (inaudible) crude in the Gulf Coast, West Coast and North Atlanta region.

If we’re at the same situation here as far as differentials are concerned, I guess mainly being the brand, as we get into the third and fourth quarter where it’s basically no differential, would you still expect some of those rail projects to come on line and start delivering some of that crude via rail or would you delay that in the next year and to may be give some more widening into this spread?

Bill Klesse

Yeah, it would absolutely depend on some of our deals. But yeah, hey we’re in business to make money and if it’s not economic to do some, we may have some fees we have to pay a few guys, but and where we have to take it, well we’ll have to do it, make the best of it. But we try very hard to maintain optionality on these deals. I’m sure, if you don’t have any spreads, you’re going to optimize.

Allen Good – Morningstar Research

Is there really general, that we have Brent spread or any other source spread we could use just may be a rule of thumb to see whether there some of these rail projects in general are economical for you?

Mike Ciskowski

Well, in the back of our handout, we have that big map where we made this price call it 12 to 18 months and we said, New York Harbor is where we see the equilibrium point between Brent and delivered sweet crudes into the harbor. So you take Brent plus a couple of bucks for freight, and so we’ve been saying that’s where a lot of these balances run these costs. And then you back up from there, and so we think overtime, you’re going to have these differentials, because the crudes got to move to the markets and it’s got to displace the foreign barrels.

So – but sure you’re going to have a spot month or two of what’s going on right now, but we don’t believe they’re going to last. So we’re in business for the long term.

Allen Good – Morningstar Research

Okay, great. Thanks.

Mike Ciskowski

In our appendix it’s in there, we put all those numbers in there, and so I think we say 12 to 24 months is our price outlook. But the basis is the East Coast being equilibrium. So Gulf Coast, we think that LLS is several dollars below that.

Allen Good – Morningstar Research

Great, thank you.

Operator

Thank you. The next question comes from Paul Cheng from Barclays.

Paul Cheng – Barclays Capital, Inc.

Hey, guys. Just real quick question, Bill, I know that you may not want to give us an absolute number, but what is the percent of your rail arrangement with the rail operator, is I think will pay for the long-term or what percentage is that like 30 day roll over kind of deal?

Bill Klesse

I don’t know if it’s, I don’t want to give it to you. I am not sure we know…

Joe Gorder

No, we don’t have…

Bill Klesse

I think we have loading fees. Well I think here we just, we’ll give Ashley a couple, we’ll gets and puts up together. The railroad, we own the cars, so Joe’s point is, hey you don’t have that. But the right reason I was hesitant on the previous question is we make some commitments the load cars at these third-party loadings at our own refineries, at our facilities, so there are no obligation. But we do have some fee commitments below then a couple of things like that, purchases of oil. So we will put some thing together, but it’s very, it’s relatively small, but we have a, once we get all our railcars, we will have a $750 million investment in railcars, and a couple other 100 million in sidings. So we want to return to.

Paul Cheng – Barclays Capital, Inc.

Secondly that on the (inaudible) and also the Seaway one and two can you give us some rough idea there what is your (inaudible) commitment on those?

Joe Gorder

Yeah, Paul, we don’t do that.

Paul Cheng – Barclays Capital, Inc.

Okay. Final one, Bill, when we’re looking at your dividend policy when the Board [give out] whether you are going to increase or not, is there a policy from management that this is a annual exercise or it is a semi-annual or that’s really no policy at all?

Bill Klesse

Well, I’d like to – went away and phrase your question, no policy at all.

Paul Cheng – Barclays Capital, Inc.

No, I mean, you made…

Bill Klesse

I think we are little better than that. We’ve raised our dividend in January and I said that we would look at it and management would have a recommendation. We have it at our Board meeting this month after we finish the hydrocrackers, but we will look at our balance. We’ll look at our forecast. We’ll look at our payout rate. I have said that Valero wants to be among the highest in dividends and returning cash to our shareholder of our peer group and so we look at those guys as well.

So I feel like there is more of a process, but we don’t say the July Board Meeting is a dividend meeting. It is a dividend meeting with the Board, but we don’t say management is going to raise the dividend or some at the January meeting or the April meeting or the July. We go into it with us having looked at our forecast where we think our cash is, do we think we can sustain it, and then we make a recommendation to the Board.

Paul Cheng – Barclays Capital, Inc.

Thank you.

Ashley Smith

Thanks, Paul.

Operator

Thank you. We have no further question.

Ashley Smith

Okay. Thank you, Lorissa, and I just want to thank everyone for listening to our call today. I believe we set a record for me, thank you for that interest. Please visit our website or contact Investor Relations for additional information.

Operator

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

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