John Locke - Executive Director, Investor Relations Joe Gorder - President and CEO Mike Ciskowski - Executive Vice President and CFO Lane Riggs - Executive Vice President, Refining Operations Jay Browning - Executive Vice President and General Counsel Randy Hawkins - Vice President, International Crude Oil Supply and Trading.

Jeff Dietert - Simmons Paul Cheng - Barclays Paul Sankey - Wolfe Research Sam Margolin - Cowen & Company Blake Fernandez -Howard Weil Faisel Khan - Citigroup Jason Smith - Bank of America Roger Read - Wells Fargo Ed Westlake - Credit Suisse Evan Calio - Morgan Stanley Allen Good - Morningstar.

Welcome to the Valero Energy Corporation Reports 2014 Second Quarter Earnings Results Conference Call. My name is Sylvia, and I'll be your operator for today's call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. Please note that this conference is being recorded.

I will now turn the call over to John Locke. John Locke, you may begin..

Thank you, Sylvia. Good morning. Welcome to Valero Energy Corporation’s second quarter 2014 earnings conference call.

With me today are Joe Gorder, our CEO and President; Mike Ciskowski, our Executive Vice President and CFO; Lane Riggs, our Executive Vice President of Refining Operations; Jay Browning, our Executive Vice President and General Counsel; 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 our Investor Relations team after the call. Now, I would 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. As noted in the release, we reported second quarter 2014 earnings from continuing operations of $651 million or $1.22 per share.

For all period shown in the table that accompany the earnings release, our results of operations reflect our Aruba Refinery as discontinued operations and we recognize $63 million of charges in the second quarter of 2014 associated with the recording asset retirement and other obligations related to our Aruba Refinery.

Second quarter 2014 operating income improved over second quarter 2013 with gains in the refining in ethanol segments partly offset by a decrease in the retail segment due to the spin-off CST brand in May 2013.

The refine segment throughput margin in the second quarter of 2014 was $9.84 per barrel, which is an increase of $0.58 per barrel versus the second quarter of 2013.

Decreases in gasoline and distillate margins relative to Brent in most regions and narrower WTI discounts in the Mid-Continent relevant -- relative to Brent were more than offset by wider discounts on light sweet medium sour and heavy crude oil in the Gulf Coast.

Also contributing to the higher throughput margin was our Quebec City refinery’s increased consumption of North American light crude in the second quarter. North American grades composed 83% of the refinery’s feedstock diet, up from 45% in the first quarter of 2014 and up from 8% in the second quarter of 2013. Additionally, at our St.

Charles refinery we have began processing Canadian bitumen by our new crude-by-rail unloading facility. The U.S.

crude supply landscape continue to transition in the second quarter with oil stock shifting from the Mid-Continent to the Gulf Coast, the inventory reduction in Cushing and corresponding oil supply growth in the Gulf Coast led to a $2.49 per barrel decline in the WTI discount to Brent and $5.19 per barrel increase in the LLS discount to Brent compared to the second quarter of 2013.

Gulf Coast sour crude oil differentials to Brent also widened over the same time period due to increase in supply of crude oil. The discounts for Mars and Maya relative to Brent increased by $4.69 per barrel and $8.49 per barrel, respectively.

Refining throughput volumes averaged 2.7 million barrels per day in the second quarter of 2014, which is an increase of 115,000 barrels per day versus the second quarter of 2013.

Less turnaround activity and higher utilization rates spurred by the increase availability of discounted North American light crude in the Gulf Coast led to the increase in refining throughput volumes.

Refining cash operating expenses in the second quarter of 2014 were $3.90 per barrel, which is $0.07 per barrel greater than the second quarter of 2013, due mainly to higher energy costs. The ethanol segment generated $187 million of operating income in the second quarter of 2014 versus $95 million of operating income in the second quarter of 2013.

The increase in operating income was mainly due to a $0.39 per gallon increase gross margin which was driven by lower corn prices on an abundant corn crop and low industry ethanol inventories at the start of the quarter.

Ethanol production volumes averaged 3.3 million gallons per day in the second quarter of 2014, which were lower than the second quarter of 2013 due to production slowdown caused by lingering rail congestion in the Mid-Continent.

Now looking at the third quarter for ethanol, we expect volumes to increase with the startup of our recently acquired plan in Mount Vernon, Indiana, given the favorable ethanol margin environment we look forward to this plant’s contributions.

General and administrative expenses, excluding corporate depreciation were $170 million in the second quarter of 2014. Net interest expense was $98 million and total depreciation and amortization expense was $414 million. The effective tax rate was 34.3%.

Now with respect to our balance sheet at quarter end, total debt was $6.4 billion and cash and temporary cash investments were $3.5 billion of which $382 million was held by Valero Energy Partners. Valero’s debt to capitalization ratio net of cash was 14.1% excluding cash held by Valero Energy Partners.

Valero had approximately $5.8 billion and Valero Energy Partners had $300 million of available liquidity in addition to cash. Cash flows in the second quarter included $806 million of capital expenditures of which $240 million was for turnarounds and catalyst. We also repaid $200 million of debt that matured in April.

In the second quarter we return $361 million in cash to our shareholders, which included $133 million in dividend payments and $228 million in purchasing of approximately $4 million shares of Valero common stock.

Subsequent to the second quarter, we continue to return cash to stockholders by purchasing an additional 2.0 million share of common stock for $104 million. We also increased our regular quarterly dividend for the third of 2014 by $2.05 per share to $27.05 per share or $1.10 per share annualized.

Also in the second quarter we announced the sale of the McKee crude system, the Three Rivers crude system and the Wynnewood Products system to Valero Energy Partners for $154 million. This transaction closed on July 1st and as an example of executing our strategy to create stockholder value to Valero Energy Partners.

For 2014, we maintained our guidance for capital expenditures including turnarounds and catalyst at approximately $3 billion.

We expect stay-in business capital to account for slightly under 50% of total spending and for the reminder to be allocated to strategic growth investments, primarily for logistics and advantage crude oil processing capability.

I should add that approximately $870 million of Valero’s estimated strategic capital spent for 2014 is all logistics and most of this is expected to be eligible for dropdown into Valero Energy Partners.

Now for modeling, our third quarter operations, we expect throughput volumes to fall within the following ranges, Gulf Coast at 1.45 million to 1.55 million barrels per day, Mid-Continent at 410,000 to 430,000 barrels per day, West Coast at 260,000 to 280,000 barrels per day and North Atlantic at 440,000 to 460,000 barrels per day.

We expect refining cash operating expenses in the third quarter to be around $4 per barrel. For our ethanol operations in the third quarter, we expect total production volumes of 3.6 million gallons per day and operating expenses should average $0.40 per gallon, which includes $0.04 per gallon for non-cash cost such as depreciation and amortization.

We expect G&A expense excluding depreciation for the third quarter to be around $165 million and net interest expense should be about $95 million. Total depreciation and amortization expense in the third quarter should be approximately $420 million and our effective tax rate should be around 35%. Okay. So we have concluded our opening remarks.

In a moment, we’ll open the call to questions. During the segment we request that our callers limit each turn to two questions. They may rejoin the queue with additional questions after that..

Thank you. (Operator Instructions) And our first question comes from Jeff Dietert from Simmons..

Good morning..

Good morning, Jeff.

Good morning, Jeff.

I was hoping to hit on capital spending? You stand consistent with your $3 billion forecast for 2014.

I was curious as you look forward continues to be an opportunity rich environment in your view more light processing, more logistics, perhaps on the logistics side do you see that as a steady trend or trend that accelerating as far as logistics investment opportunities?.

Hey. Good morning, Jeff. This is Joe. Yeah. I’d say you raise a very good point. I mean, if you look at it broadly, we are going to maintain a very balanced approach with the use of cash returning it to shareholders via the dividends and buybacks.

And then, investing to maintain the quality assets, which is, just a core part of our capital programs and then we are also investing to take advantages, natural resources advantage were enjoyed.

Relative to the investment in logistics asset, I think what you would see now is a bit of shift in capital -- in the strategic capital from -- for example, we shift some of the spending for the purposed methanol plant for 2015 and we move the crude by rail facility up into 2014.

So as the percentage, I think, that we have now is 54% of our strategy capital now is focused on logistics, where as previously, Jeff, is in the 40s. So the point that you make is one that we clearly agree with and recognize and so we’ve seen a shift in that capital..

Secondly, could you talk a little bit about your historical capital investment and what types of returns you’re seeing so far from some of those investment, maybe hit on the hydrocracker investments at Port Arthur and St.

Charles? What kind of returns are you seeing there based on their performance to date?.

Jay, go ahead..

Long time, yeah..

Yeah. Jeff, I’ll tell you what, you asked a question and I think you recognized that it’s very difficult to look at unit within the refining complex and determine specifically what’s the return to that is, because of all the interrelationship in the plant.

I think we’ve said in the past and we would continue to say that the hydrocracker project were very good investments. Project -- the units are running very well and Lane can speak to that and the projects that we are getting out of units are good, high-quality diesel fuel that we are able to export as EN 590 grades versus a conventional diesel fuel.

So, although, I don’t have a specific return on hydrocracker project per se for you, I’ll tell you we are pleased with the investment. We think they have improved the quality of the portfolio and they are performing very well..

Jeff, this is Lane. They’ve averaged 120,000 combine units averaged 120,000 barrels in the second quarter. They’ve definitely earned very well. These are great units. We are currently in the process of performing a test run at our St. Charles Refinery. It’s I don’t want to. I would be careful not to say what they are, where we are on that.

But it certainly allows us to look at a very limited opportunistic capital investment. Those units are really bring them up to essentially all about the equipment and the sizes. But they’ve ramped fantastically in the second quarter..

Thanks, guys..

Thanks, Jeff..

And your next question comes from Paul Cheng from Barclays..

Hey, guys. Two questions, Joe, I joined a little bit late, maybe you already covered it.

Do you have a preliminary CapEx outlook for 2015 and ‘16?.

Yeah. No, Paul, we don’t and I’ll tell what, what we are doing right now is we are going through the strategic planning process here at Valero and part of that, obviously, is the review of any kind of growth project we might be looking forward to in the 2015, in addition to what we got base loaded.

We are spending $1.4 billion, $1.5 billion a year on maintenance reliability turnaround. So, that is going to continue and be fundamentally part of what we’re doing. But we haven’t settled in on the projects, the growth projects we want to carry forward those and we continue to pursue the crude units, we continue to look at the methanol plant.

And then as you would expect there is host of logistic projects that we are evaluating. But we haven’t settled in on the number, yet..

Do you have settled into a direction at least this year is three, are we talking about -- from a direction standpoint flat, up or down?.

Yeah. Paul, it won’t be up..

Okay.

The second question that, do you have an estimated downtime cost in the second quarter in terms of the actual incremental cost and also that if you can give it, if you have it, would be helpful that for two number, one is the actual incremental cost and the second one is the opportunity cost that you lost?.

Hi Paul. This is Lane. So our unscheduled downtime cost in the second quarter was $103 million..

$103 million.

And that’s pretax or after-tax earning?.

That’s really EBITDA..

And you say, that’s opportunity cost or it’s actual cost? I’m sorry..

That is what we would call our volume variance which is if the units would’ve performed the way we had planned than they would have generated another $103 million..

Right.

So that’s the opportunity cost?.

Yes..

And how about actual incremental cost. Because I presume that you probably have some because of all the downtime, you have some additional maintenance cost and all that….

Yeah. I’m not -- it’s really that's embedded inside our performance. We’d have to get back with you on that exact number..

Okay. Will do. Thank you..

And the next question comes from Paul Sankey from Wolfe Research..

Hi. Good morning everybody..

Good morning Paul..

Guys, your throughputs in the quarter beat your guidance in every region. And you've effectively raised your guidance for 3Q to be more in-line with the better performance in Q2.

Could you talk a little bit more about the dynamics of how you're coming in so much higher? Really, within weeks and months of having set the guidance, you're coming in about 10% plus higher, in terms of throughputs.

Could you just talk a bit more about, firstly, the technicalities of that? Secondly, the implications? And thirdly, where we might go, given the CapEx you've highlighted this year for presenting yet more light sweet? Thanks..

Okay. So Paul, this is Ashley. On actual runs, throughput runs versus guidance, guidance is -- it’s a conservative estimate based on planned downtime and turn around, things like that. And I think what you can do is run some -- get some throughput.

It might be lower margin throughput because you’re buying higher-price intermediates or other feedstocks to keep downstream units going. Generally that’s where you’re going to see delta..

So, it's not a function of you running more light sweet and, therefore, pushing more crude through the refineries?.

No. I think we generally planned to run the amount of lights that we expected. It more has to do with planned downtime..

Okay.

So actually, what you're pretty clearly saying is, the better performance is simply due to a conservative guidance that you beat?.

Because of relatively heavy planned turnaround activity..

Right.

The final part of my question was, does your current CapEx program expand the capacity or is it a shift mix entirely?.

Paul, we’ll let Lane talk about the crude units and what the impact will be..

Yeah. So Paul, this is Lane Riggs. So again we have our two announced crude units, one at Corpus Christi and one at Houston with the combined capacity of incremental suite capability of about around 160,000 barrels a day. And then we’ll finish McKee which is an incremental 25 a day next year.

Those are really the planned expansion on light sweet product capability. So with that said, we still are learning limits of our system on how much light sweet crude we can run, particularly on a Gulf Coast where it’s available.

And we’re not really -- we still optimize those crude into our system versus our alternative medium sour, heavy sour, Canadian heavy and all these other. So we still have -- we can feel optimize and run more if the economics signals are there..

The final part of this whole question is for me to ask you, in the past, you said that you need a 10% light heavy differential to run a (indiscernible) I think, was the guidance. Do you have a sense the -- you talked about the sensitivities.

Can you give us a sense for what the price differentials need to be to be running, more or less? Yeah, on lights, on lights?.

So you are saying -- Paul, this is Lane. So you are saying that we’ve given guidance in the past that we need a light heavy differential of 10% versus…..

Yes. Kind of a rule of thumb for what causes you to run more light sweet in a mix against, for example, a medium sour..

To back out heavy and run..

Yeah, back out heavy and run sweet. It’s probably fair somewhere in that number. Today we definitely have incentive to run all three et cetera. And they all have slightly a pretty similar margins into our crude capacity and/or into an open (indiscernible).

So I think today, if you would look at, they are very reflective of what these -- what the relative values in refineries are..

13% off of rig. Right, so it’s in that general range. It still would trickle to run the heavy solid crudes versus pushing more light sweet into the plant..

Okay, guys. That’s helpful. Thank you..

Our next question comes from Sam Margolin from Cowen & Company..

Good morning. I'll just touch on the condensate export issue. It seems like it's come into flux a little bit over the past couple days.

I was wondering, as we await the BIS public guidance, as far as what the requirements will be in processing, if you have identified any opportunities at Corpus Christi, maybe either on the midstream side or sourced at the VLO level for that kind of processing capacity? Where you can kind of lean into some regulatory shifts that might nominally work against you but with VLP, could actually become the revenue margin driver over time?.

Well, Sam, we look at these projects all the time. Right now, we don’t have a condensate splitter project on the board. We’re very focused on the two crude units that we talked about and really nothing beyond that at this point in time..

So Sam, this is Lane. I’ll follow-up a little bit. The two crude units that we have designed, have a designed API gravity of 50. So these two crude units are fairly long although we would say the equipment is necessary to run a pretty light diet.

We could run condensate and this is going to be a matter of again, what the economic signals and how distressed it is. In our economics, we had LLS and Brent parity. And we had to export naphtha out of U.S. Gulf Coast close to Far East.

So that stream whether it’s condensate, it’s naphtha, whatever form it takes, it’s got to find the market whether it’s western Europe or the Far East, that sort of -- the value of naphtha is in the value of these condensates. It’s still -- it will be interesting to see how that goes..

Okay.

Even if they are taking up to 50, they'll still produce some BGO for the hydrocrackers and some of the other downstream units too?.

Yes, it’s not as much, right, because it’s lighter..

Okay..

And that will be included in our economic because our alternative would be the intermediate to fill out of conversion units..

Okay, thanks. And I just wanted to touch on differentials in the Gulf, too. There has been a lot of volatility.

I think last year when LLS spiked to that Brent premium briefly in July and August, you guys had highlighted the fact that some barrels were coming in on Longhorn offspec and the spot market for LLS and in Houston got very tight because of that.

Is there any single piece of infrastructure development that we can be mindful of here over the last couple of weeks, aside from just very high utilization in the Gulf, maybe the delay in BridgeTex or something of that nature that might explain that LLS pop a couple of weeks ago?.

Sam, this is Joe. Randy Hawkins is with us reporting and Randy is our Senior Vice President of Crude and Feedstocks Supply and he will be able to answer that for you..

I think you touched on it already -- the high utilization rate that kind of led to some of the spike that we saw in LLS at the end of the August trade month. But I think you hit on the nose.

The thing that we are looking ahead is the BridgeTex startup that we are anticipating at sometime late Q3 that will bring some of this distressed midland type barrels to the Gulf Coast that should help to provide some of the barrels that the Gulf Coast needs..

Okay, great.

I think it's delayed, right? Is there some planned barrels or something that people are missing, and sort of a spot market issue, maybe?.

Yeah, I mean, I think there were some -- maybe some people that were anticipating BridgeTex being a bit earlier and I think overall the high run rate, people were just a bit short and falling inventories as well led to that..

All right. Thank you so much..

And the next question comes from Blake Fernandez from Howard Weil..

Guys good morning. Thanks for taking the question. I had two for you. One bigger picture and one more specific.

But the big picture, Joe, as you kind of transition into your new role, I'm just curious if there is any low-hanging fruit or any strategic shifts that you see on the radar screen that you really want to address out of the gate?.

Blake, good morning. I mean that’s a fair question but quite honestly I think that this management team that’s in the room today has been working with Bill for a long time and the plans that we put in place are plans that we are all very comfortable with.

And so if you look at what we have got on the burner with the crude units and the logistics investment and then you look at some of the projects that are being contemplated like the methanol plan. These are all projects. This team feels pretty good about and that we are continuing to advance the conversations around.

So from an investment perspective there isn’t. From a use of cash perspective, we have maintained for sometime now that we are going to try to maintain a balanced program between investment and capital projects for growth and return of cash to shareholders. And I think we are going to continue to do that.

I mean very clearly the fact now that we have had our second dividend increase this year which support the fact that we are permitted to increasing the cash returns to shareholders. And then today we bought back about 10.4 million shares and we will continue to do that throughout the year as cash flow is available to do it.

So I would say there is no major shifts right now. The ox cart is not in the ditch. And as I mentioned earlier we are going through the process of pulling together our strategic plan for the next several years including and that will be capital plan. So I think we are in a pretty good position..

All right. That’s great. The second question, I hope this is one question, but you runs up at Quebec of North America crude hit at 83%.

I was hoping if you can give us a breakdown of how much of that has been barge from Gulf Coast and how much is actually tied I guess from Canada? And then I guess similarly on the rail to St Charles, just trying to understand should we be thinking about the economics on that as far as once you pay for transport.

Is that kind of competitive with Maya or even more competitive just kind of some general feel about how we should be thinking about the margin impact there? Thanks..

Blake, this is Randy Hawkins again. At Quebec the split of our North American crude was around 58 days by rail and about 1 00 a day shifts from the US Gulf Coast and two Quebec.

Could you repeat the question on the Canadian?.

Yes. Basically it looks like you started railing bitumen into St. Charles and I guess that is kind of view that as competing maybe with Maya and I didn’t know by the time you pay for transport to rail it down from Canada if we should be viewing that as if more competitive.

In other words, discounted to which you could access Maya at or at par?.

Yes, I would say that we’re railing from Canada would be on par or better than Maya. The volumes for Q2 are fairly small. We anticipate this increase as we move into Q3..

Yes, Blake the refinery was moving turn around in the internally around in second quarter, so we aren’t going to see the impact of any of those that bitumen movement until the third quarter..

Okay, great. Thank you so much..

And the next question comes from Faisel Khan from Citigroup..

Good morning, it’s Faisel from Citi. Just had a question to follow-up on Blake's question on Canadian heavy. So I guess with the rail capacity at St.

Charles and even some of your other facilities, and then with the connection to Keystone from Port Arthur, how much Canadian heavy do you guys envision having the ability to access by the end of the year? And then how are you thinking of that, versus your term contracts with PEMEX.

Is there flexibility? Just sort of arbitrage those barrels between each other?.

Sure. Faisel, this is Randy Hawkins again. On our Canadian volume, we do anticipate with our rail facility in Lucas coming up later in the year that we will increase the amount of rail that we are taking into our production facility. We also buy regularly Canadian heavy after the pipeline systems coming out of cushion as well.

So right now we don’t anticipate that impacting our volumes with Mexico and it more is backing out some of the spot heavy that we are doing elsewhere from around the region..

Okay.

And just how much sort of capacity for Canadian heavy do you think you guys will have the ability to sort of run by the end of the period what always pipelihe and real capacity?.

I think for now we are limited logistics more so than we find the configuration ..

Okay, fair enough. And just my question it’s on the changes in the rail regulations, have you see from the DoT and also the Canadian regulators.

Is that going to have any impact of sort of the volumes you guys are moving around your system by rail?.

Faisel, I think we are all waiting to see what those regulations settling in at and if you look at the things that are being proposed with the shell thickness in the (indiscernible) protection systems, the breaking systems.

There is going to be a lot of retrofitting activity and modifications to already planned cars that has to take place and frankly the fleet, the rail fleet is in service today, it’s very large and depending on the timeline for retrofit, it’s going to have an affect on rail movement just in general.

So we don’t have a good estimate as to what the overall impact is going to be. We are in the process of working this year or so specifically working with ASP and formulating response to DOT and to transport Canada’s proposal, but its probably just a little bit early for us to give you any idea as to what the impact might be..

Okay. Understood. Thanks. I’ll get back in the queue..

Our next question comes from Doug Leggate from Bank of America..

Hey, guys. It's actually Jason Smith, on for Doug. If we could touch on throughput from the product side. With you guys and industry seemingly running at a higher overall level and in the release, I think you highlighted product prices versus Brent. Can you talk about what the implications of a self-sufficient U.S.

system are, particularly on gasoline, where I think we're exporting as much as we're importing, at this point?.

All right. So we’re kind of looking at each other, trying to figure out exactly what it is you that you’re trying to understand. Are you saying, at what utilization rates do we satisfy U.S.

demand?.

No. I'm trying to say, I mean, we've basically seen, we've talked about product prices, pricing off Brent.

But is there -- as we become more self-sufficient on the gasoline side, is there risk? Do we potentially price off of LLS?.

I see..

How do you see that playing out? We're producing 9.5 million a day of gasoline today. We're exporting as much as we're importing. .

Right. That’s an interesting question. Why don’t we let -- Scott Lively is with us today and he is our Senior Vice President of Products, Supply and Trading. Maybe he can just give you some thoughts on that..

Hey Doug, how are you doing?.

Good..

I guess, the way that I think about it, I don’t think about necessarily what price products have to price off of as a feedstock. I just think, you’ve got prices that are around the globe and we have to compete. And so barrels either arb into those markets or did not arb into those markets.

And so you can say, we priced against Brent or we priced against something else. Well, we’re running a lot more WTI based crudes in the Gulf Coast. So that region sees more of a WTI like margin whereas, something on the East Coast of New York refinery say, might price more against West African, Canadian that moves eastward.

So I think you’re going to see pockets, the differentiation based on what crude types people run. But I don’t get it but I necessarily think about the way that you’re trying to describe with pricing against brand specifically or WTI specifically..

We do talk about the incremental barrel into a refiner being a light sweet water borne barrel, which should be kind of a Brent type barrel, as long as that’s the incremental barrel, you’re going to be pricing products off of Brent..

You have to get rid of all the gasoline production in those marginal refineries, which -- that’s a lot of European and African and South American refineries. Those would have to be backed down, shut down before your price in the marginal barrel off of LLS or WTI and that significant amount, so those are the price pattern.

Yes, you going to have times where U.S., low quality gasoline in the winter going to trade cheaper than it does in summer, you always have seasonality. But the marginal barrel is still going to be pricing out of the U.S. that’s going to set the prices..

Got it.

How is the shift to a lighter crude slate and how is that impacting your gasoline yield? Are you seeing more gasoline out of that crude, at this point?.

Hey, this is Lane. And now we’re pretty much still running, making almost within the noise of our systems, the same amount of gasoline that we were. And because of flexibility in the system and how we can change in points, whether we made naphtha or gasoline or just a lot of optimization points that we still have..

Got it. My follow-up is on the West Coast. One of your peers recently announced a petrochem feedstock project.

Are there any opportunities for projects like that within your portfolio? And also, if you could, maybe, give us an update on the Benicia rail project and where that stands right now?.

Okay. This is Lane again, all start with the Benicia rail project. It’s currently in the -- DEIR is out during the comment period, we close on that. The comment period will close September 15.

We’re still confident that we will get a permit, of course we’ll hope -- we'll, certainly along the city of Benicia will help to help answer all the question that come out of DEIR. On the first point, we are looking at a lot of projects to the ones that you’re talking about. And I think we’re fairly skeptical. It would be tough to get permits.

I think at the end of day, we take a while to build the project and get permit push through with quite an effort, as you can see with the crude-by-rail project on the West Coast..

Okay. Thanks guys. Appreciate it..

And then next question comes from Roger Read from Wells Fargo..

Hello, Good morning..

Good morning, Roger..

Well, I guess, I wanted to ask a little bit about the export market, what you see for volumes as we head into the fourth quarter. Traditionally, the strongest part of the year. And if you could give us a recap of what you've seen in the diesel market year-to-date.

If we looked at where the futures were a year ago versus what we realized, margins came in a lot lower and I'm just speaking from a general or generic term.

Can you kind of walk us through what you are seeing out there in the diesel market, both domestically and on the export side? And whether or not that has any particular concerns, as we look to the end of the year?.

Hi, Roger. This is Scott again. Over the quarter, we exported 210 a day of diesel and I would say, that’s pretty flat with where we were on 1Q. We still see continued global demand growth in that fuel. So we feel pretty positive about our ability to export number one and having those markets to export into number two.

You did have a little bit of hangover effect of the mild winter that Europe had, which really, particularly kept German stocks from drawing down. But those stocks are coming back more in line and those guys look like they are going to need to be building going into the winter.

So we fully expected these export rates that we’ve had to continue out in the 3Q and 4Q..

Okay. And then, something that got beat up on last year. We keep waiting for the EPA to give us the official numbers. Can you give us an idea of what you're seeing in the RINs market? We all know where the prices are.

But what you've been doing about buying RINs, what your plans are if they make changes, presumably, an upwards revision to the ethanol and other biofuel requirements, as has been rumored in the press. As we, maybe, get something next month.

Certainly hope to see something by the October, November period?.

Well, we do of course, keep our eye on the markets and we are participants. I think it probably put me at a competitive disadvantage if I said exactly what we were doing and what I planned on doing if we got an idea that they were actually going to raise too or above the blend wall as Podesta and potentially, Gina MacCarthy have alluded to.

I think we just have to sit back just like everyone else and wait for them to come out with the final decision on what the obligation is gong to be.

And hopefully at sooner rather than later because obviously as the time horizon shrinks that shrinks the time horizon for you to be able to go out there and procure the RINs that you’re obligated to in arrears..

Yeah. I think the one thing that we do have going right now though is that there is probably as much ethanol being blended into the gasoline fuel. This could possibly be blended and as a result supply of RIN is there. So the economics are supporting it and the ethanol market in general, this is favorable to blend..

Right. Unfortunately, it's not always an economic driven story, where RINs are concerned and ethanol. I guess, one final question, just as a follow-up on that.

Have we heard anything about 2015 volumes or adjustments or any of that or is the expectation that, that may come out with the revised ‘14 numbers?.

I think that’s what their expectation is, is that it comes out it would be interesting to have ‘14s and ‘15s come out. Well, it would be interesting to have ‘15 come out in ’14.

I wouldn’t think that there hasn’t been our past practice, but I don’t think there is anything that we’ve heard to a great that’s given us any indication of what ’15 might be..

Okay. That’s it for me. Thank you..

And our next question comes from Ed Westlake from Credit Suisse..

Yeah, good morning everyone. Just on I guess a bigger picture, strategic question, $1.5 billion of growth CapEx, of which around 50% going into logistics. You've got VLP out there, $2.6 billion. So it's a relatively small MLP, but Valero's market cap has got a currency of its own. And obviously, you can drop down assets into VLP over time.

Just get a sense of the color of how big you see the organic suite of opportunities in logistics.

And then maybe even, any comments on using your equity to be more assertive, perhaps, in the inorganic M&A space?.

Okay. Well, I think, we stated before that we Valero Energy have about $800 million of EBITDA that could be dropped to VLP. So, it’s a very significant number. We completed the first drop here at the beginning of the third quarter on July 1, I think it was -- and that was about $154 million transaction.

And I think it’s fair to expect that we are working the subsequent drop transaction as we go forward. I think we recognized very clearly the value of interrelationships of the two entities and the multiple pickup we get when we drop Valero Energy down to VLP.

We have a lot of projects as you mentioned that are in our current growth capital that we are working on which will be assets that would add to the base of assets that can be dropped. So really the question is that we are working through is the pace and the timing on those. And we said we are going to grow VLPs distribution to 20-plus percent a year.

We still are intending to do that. And so our drop schedule at a minimum would be able to accommodate that growth rate..

It just seems like there's a large opportunity for companies in your space who have the skills to be very large and successful infrastructure companies, against the shell revolution to continue to shift assertively into that direction, given the relative multiples. So appreciate you might be going through the planning process now.

But any thoughts about the direction you want to take the company?.

Yeah, I think we’re looking at host of different logistics project that are in development and will allow us to take advantage of what you've described. There’s great opportunity with the shale plays. But I don’t have anything specifically share with you right now.

Okay. Then, maybe a question for runs, just on crude. Obviously, LLS spiked last year, and then LLS collapsed in the fourth quarter. The spike is, let's hope its history. And let's focus on the future, where we could see, perhaps, a repeat of what we saw the fourth quarter. A couple of things seemed to happen last year.

Obviously, we built gasoline for a hurricane that didn't happen. There were lots of imports during the period. There was a rapid rise in inventories, seasonally. And you folks and others in the industry were trying to reduced inventories for the usual year-end planning purposes. So I'm just, sort of, the question. You mentioned BridgeTex earlier.

But is there anything different that you see happening this year or do think this is sort of a new seasonality that's going to set in for the Gulf Coast crude prices?.

Yeah, thanks for that. I think the biggest difference that I see, is that crude runs are so much higher than what they’ve been as of late which we go through some regional turnarounds that we head into Q3 or so. My thoughts is that this thing will get back to normal.

As we’re seeing September contract trade today and we’ve seen LLS back down $2 to $3 under Brent and last year $7 under Brent. So things are starting to look normalize..

Yes. And then, maybe, one tiny follow-on. Obviously, in winter, there's a difficulty pushing gasoline into the U.S. market and so you try and export the product into other markets.

How are we, in terms of the ability for you to say, maintenance aside, run at a higher utilization than you would have done in the past? Because of the ability to export more product and out-compete other refineries around the world? Any color, there?.

This is Scott again. As you know that those gasoline exports are seasonal. So we do export less in 2Q and tend to export more in 3Q and 4Q especially we have more availability in butane works itself back into the pool. I think that we’re going to cost advantaged.

And we do see plenty of opportunities with growth and market in Central, South and Central America, South America and in Mexico we still see put in opportunity to put barrels out in those regions. So we still pretty good about our positions to export and keep refinery rates high in our system as result of those exports..

We are up on it. One last thing I’ll add was Scott has said to your point, U.S. Gulf Coast capacity is most competitive capacity in the world. So if there we can save any market, we have low natural gas front. We are (indiscernible) and we’re well positioned to maintain our assets. High utilization is we can find.

We’re not really up against any export logistic per se. So we don’t really see being (indiscernible)..

Thank you.

And the next question comes form Evan Calio from Morgan Stanley..

Hi. Good morning, guys. Maybe a more specific follow-up on next question. I know you are not providing 2015 CapEx guidance at this point. It was asked and answered yet.

Given you had the MLP and given midstream spending as a increase percentage of CapEx, how do MLP dropdown relate to your consideration of CapEx, and it would appear to me that they are direct offset and distributable -- potential distributable cash flows and I have follow-up? Thanks..

Well, I mean, that’s a million dollar question right there.

In the subsequent question that is, at what point in time do we start doing this logistics projects in VLP itself and not at Valero Energy for dropdown? We have a lot of good projects that we are looking and what we are trying to understand is whole notion around, if you would look at gross capital or net capital number to be quite honestly, yes.

We have a very good feel for I believe what we are going to be spending on refining side of the business that the wildcard here is, how much do we spend on the logistics side. So, I know you love to have a number and there will be a point when we give it you but I am just not prepared to share today..

What would, let me ask you a question when you are evaluating midstream projects and what ultimately goes into the EBITDA that you characterize as MLP EBITDA. I mean, do you consider the relative cap rate versus the MLP drop rate in the overall calculation of the IRR.

For instance the rate different and more color there, I think, would help us, I am just curious that’s an element of your evaluation of what to proceed on?.

Yeah. I believe it is..

Maybe lastly, then, for me, any update on the timing, we're keeping a midstream focus here, but any update on the timing of potential methanol facility decision and given Westlake Chemical Partners MLP IPO that uses a fixed-rate structure versus variable and is, I think it's up 25% this morning, well through the range? How does a structure like that factor into that project consideration, which I know is under review and I'll leave it at that? Thanks..

Okay. Well, honestly, you know, we mentioned earlier that we continue to take a look at the project and we are advancing engineering. Lane and his team are trying to get our arms around exactly, what the scope of the project is.

And again, yet, to look at the transaction you mentioned to know the impact of it, so we will take a look and then perhaps we can look back with you and have actually involve and John..

Okay..

Specific we are in Phase II. We are doing all those sort of engineering to major equipment so we can nail down the cost estimate. How that we view in the fourth quarter. So that’s where we’re in the process..

Okay. Okay. And that's the process prior to -- it's going to reach an FID.

Is that accurate?.

It’s the process, I’m sorry, can you say that again?.

I'm sorry.

Is that the step -- after that phase is complete, is that when you then decide whether or not to go to a final investment decision?.

That phase we’ll make a decision whether we feel so good about that we’ll go ahead and order all the equipment, which would expedite the project. That’s really the critical decision that we’ve taken..

Great. All right, guys. Appreciate the information. Thanks..

And our next question comes from Allen Good from Morningstar..

Good morning, everyone. I want to try to come back to the export question and, maybe, get your longer-term outlook.

There seems to be a lot of changes underfoot there, with a lot of the refining capacity additions in Asia and the Middle East, potential improvement in European competitiveness given exports of, maybe, heavy crude over there, maybe even light crude. I think you have a bunch of peers increasing exports as well.

So could you just talk about your long-term outlook there and how you think the export market for U.S.

refineries and Valero, particularly, will develop?.

Allen, this is Scott again. I think that we were a bit ahead of the curve versus Europe of course on running those price advantaged crudes. So depending upon how long that takes to work its way and you can still see more closures in Europe. And clearly, Europe’s kind of at a pinchpoint between the United States -- and mostly U.S. and Russia.

Like I said before, I steel feel pretty good about our ability to export into these markets. A lot was made about Jubail coming on line. So far, you can see a sprinkling of cargos go here and there. But so far, what we’ve seen is those cargos from Jubail have mostly gone into internal demand and stayed on the east coast of Africa.

So sure, going forward, there is more refineries, they are going to come online and by way of China, there is going to be more capacity in U.S. but you should see that tempered with refinery closure especially those ones that are marginal. And as we said before, we still see the prospect of world demand growth for diesel..

Okay. Switching to the condensate export question, just looking at your recent investment presentation. And you have some notes in there saying that at the end of the day, less condensates in the crude stream could ultimately be beneficial for Valero, given some of the utilization rates and yields.

Have you been able to quantify, exactly, what the loss on utilization or yields may have been over the past couple of years, as those crude streams did get lighter with additional condensates?.

This is Lane. I don’t know -- I'm not sure, I can give you exactly the loss. It hasn’t been large but what we do, we’re very careful in terms of how we articulate the quality of those suppliers. We have deducts and we can’t give you numbers but we have standard deductions with API gravity goes up.

We try to offset any sort of financial penalties we might have. But as refiners, we personally would like to see the condensate out of the blended crude. We’re not but that’s going to take a considerable infrastructure buildout to try to get condensate in whatever locations pushed to back in half.

And so we’re not necessarily opposed to condensate being segregated to other crude strengths. But today, we don’t have. We haven’t had any real major constraints based on these gravities that we certainly have. The way we purchase our crude, we certainly attempt to offset it..

And just a follow-up from the earlier comment regarding that, you’re not interested in making any of those investments that would be separated too?.

Well, again, our two crude units had a capacity there we provide them for 50 API. We can certainly run them at slightly reduced capacity. We can run even more. I think, the way we best -- the way we do things, we’ll compare condensate and versus our alternative crude economic and that will determine how much we’re going to run.

I think what I was trying to talk earlier was I think, the industry and everybody making it stream, its going to have to try the market. That was the like condensate, whether it’s slightly altered condensate, process condensate, new condensate, I’m not sure. That’s I have to plan at own somewhere. Our assessment was it’s going to be the Far East.

But we will certainly our best relationship with condensate and crude oil is this becomes more available..

Okay. Great. Thank you..

And your next question comes from Faisel Kahn from Citigroup..

Yeah. Hi, guys. Just a couple of small questions.

First one, with the Cushing inventory, sort of, reaching bottom, is there any impact to McKee and Ardmore for you guys or do you have sort of enough inventory within the refining gate to, basically, not be impacted by lower inventories at Cushing?.

Faisal, this is Randy again. The key specifically it’s mostly a Midland market which is with crude oil at the moment. And similarly, Ardmore also takes some barrel out of that market as well. So we’ve really not seen any impact on supply of the source barrels..

Is it fair to say that, because of where production is, that you just don't need the inventory levels? Because you've got enough growth in production to offset sort of the balancing impact of having storage in place in previous years?.

Yeah. I think definitely to market goals are backward aided so there is no incentive for people to hold barrel there..

Okay. Fair enough. Last question on -- actually two more questions.

On the Corpus Christi dock, could that dock be used for condensate exports? Have you guys looked at that?.

Yes. This is Riggs. We looked at that and they could be use for condensate..

Okay. Fair enough. The last question is on getting barrels into Louisiana from Houston.

Are you guys having any issues, or are you pretty much able to get as much crude from the western side of Houston into Louisiana? Any sort of constraints that you guys are seeing?.

No. This is Randy get in. No real constraint. I mean, it moving to your pipe on that Ho-Ho and barging and shipped in through Louisville. All that does satisfy and the rail is continuing to come down as well from the Bakken. So (Indiscernible) is well supplied. .

Great. Thanks a lot guys. Appreciate the time..

Sure..

Thanks, Faisel. Thanks, Sylvia. I think with that we appreciate everyone calling in and those listening to our call today. If you have additional questions, please contact our IR department. Thank you..

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