瓦萊羅能源 (VLO) 2013 Q3 法說會逐字稿

Welcome to the Valero Energy Corporation reports 2013 third-quarter results conference call.

My name is Chris and I will be your operator for today's call.

(Operator Instructions)

Please note that this conference is being recorded.

I would now like to turn the call over to your host, Ashley Smith.

Ashley, you may begin

Thanks, Chris, and good morning.

With me today are Bill Klesse, our Chairman and CEO; Joe Gorder, President and COO; Mike Ciskowski, our CFO; Gene Edwards, our Chief Development Officer; and several other members of Valero's senior management team.

If you have not received the earnings release and would like a copy, you can find one on our website at Valero.com.

Also attached the earnings release our table 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 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.

Okay, as noted in the release, we reported third-quarter 2013 earnings of $312 million, or $0.57 per share compared to adjusted earnings of $1.1 billion or $1.90 per share in the third quarter of 2012.

Without the adjustments noted in the release, our reported earnings for the third quarter of 2012 were $674 million or $1.21 per share.

Operating income was $532 million, compared to $1.3 billion of operating income in the third quarter of 2012, or $1.7 billion when adjusted for the items noted in the release.

The decrease was mainly due to lower refining margins across all of our refining operating regions.

Our third-quarter 2013 refining throughput margin of $7.76 per barrel declined more than $5 per barrel versus the third-quarter 2012 margin of $13.12 per barrel.

The decrease was primarily due to significantly lower gasoline and lower diesel margins.

For example, the Gulf Coast gasoline margin on Brent crude fell 57% from $9.33 per barrel in third quarter of 2012 to $3.97 per barrel in the third quarter of 2013, while the Gulf Coast diesel margin dropped by $2.74 per barrel or 14% to $16.86 per barrel.

Despite the decline, diesel margins were still quite strong in the third quarter of 2013.

To capture these strong margins, Valero increased its distillates production by 16% to 1.047 million barrels per day which also represented an increase in the percentage yield of distillates versus the third quarter of 2012.

This favorable yield shift is mainly attributed to the operation of the new hydrocrackers at Port Arthur and St.

Charles.

Now also contributing to the lower refining throughput margins were narrower discounts relative to Brent crude oil for light sweet, medium, and heavy sour crudes.

For a light sweet crude example, the WTI discount fell sharply by $13.44 per barrel from $17.30 per barrel in the third quarter of 2012 to $3.86 per barrel in the third quarter of 2013.

Additionally, light sweet crude on the Gulf Coast was more expensive.

With a premium for LLS crude, relative to Brent, higher by $0.66 per barrel in the third quarter of 2013 versus the third quarter of 2012.

Heavy sour crude oil discounts also narrowed with the Maya crude discount $1.68 per barrel smaller in the third quarter of 2013 compared to the third quarter of 2012.

In the fourth quarter, crude oil discounts to Brent have improved versus the third quarter.

WTI discounts have widened by $4.46 per barrel, and LLS has improved by $6.46 per barrel going from a premium to a discount versus Brent.

Also, the Maya heavy sour discount has widened by $6.14 per barrel since the third quarter.

So refining throughput margins were also negatively impacted in the third quarter of 2013 by the higher cost of Renewable Identification Numbers or RINs, needed to comply with the US Federal Renewable Fuel Standard.

The reported compliance costs were $185 million in the third quarter of 2013, versus $70 million in the third quarter of 2012.

Given the recent drop in RINs prices following news of the EPA's potentially favorable revisions to the 2014 renewable RIN obligation, we have reduced our estimated cost for complying with the renewable fuel standard to a range of $500 million to $600 million for the full year 2013.

Our third-quarter 2013 refining throughput volumes averaged 2.8 million barrels per day for an increase of 172,000 barrels per day from the third quarter of 2012.

Refining throughput volumes were higher due to fewer unplanned refinery and maintenance events and less weather related downtime.

You may recall that Hurricane Isaac negatively impacted operating rates at our Louisiana refineries in the third quarter of 2012.

Refining cash operating expenses in the third quarter of 2013 were $3.74 per barrel similar to the third quarter of 2012.

Although natural gas prices increased year over year, our higher throughput volumes in the third quarter of 2013 favorably offset the higher energy cost per barrel.

Our ethanol segment reported operating income of $113 million in the third quarter of 2013, an increase of $186 million from the third quarter of 2012, mainly due to higher gross margins per gallon and higher production volumes.

Production averaged 3.4 million gallons per day in the third quarter of 2013 for an increase of 992,000 gallons per day compared to the third quarter of 2012.

We increased our ethanol production to capture the higher gross margins available to us.

In the third quarter of 2013, general and administrative expenses, excluding corporate depreciation, were $170 million.

Net interest expense was $102 million and total depreciation and amortization expense was $448 million.

The effective tax rate was 27.5%, which was lower than guidance primarily due to an adjustment in deferred taxes as a result of a UK tax law change.

Regarding cash flows in the third quarter of 2013, capital expenditures were $557 million, including $78 million for turnarounds and catalyst.

We returned $151 million in cash to our stockholders by paying on $122 million in dividends and by purchasing approximately 800,000 shares of Valero common stock for $29 million.

We ended the third quarter with approximately $3 billion remaining under our stock purchase authorization.

Subsequent to the third quarter, we bought approximately 2.6 million shares of Valero common stock for approximately $90 million.

This brings our total year-to-date stock purchases to almost 17 million shares for a total of $675 million.

With respect to our balance sheet at the end of the quarter, cash was $1.9 billion, total debt was $6.6 billion, our debt to capitalization ratio net of cash was 20.2%, and we had over $5 billion of available liquidity in addition to cash.

We maintain our guidance for capital expenditures, including turnaround and catalyst, at approximately $2.85 billion for full-year 2013 and approximately $3 billion for 2014.

So, for modeling our fourth-quarter operations, you should expect refinery throughput volumes to fall within the following ranges -- US Gulf Coast at 1.45 million to 1.5 million barrels per day, US Mid-Continent at 420,000 to 440,000 barrels per day, US West Coast at 245,000 to 255,000 barrels per day, and North Atlantic at 450,000 to 470,000 barrels per day.

We expect refining cash operating expenses in the fourth quarter to be around $4 per barrel.

For our ethanol operations in the fourth quarter, we expect total production volumes of 3.5 million gallons per day, and operating expenses should average $0.38 per gallon, which includes $0.04 per gallon for non-cash costs such as depreciation and amortization.

Also in the fourth quarter we expect G&A expense, excluding depreciation, to be around $175 million, and net interest expense should be about $100 million.

Total depreciation and amortization expense in the fourth quarter should be around $425 million and our effective tax rate in the fourth quarter should be approximately 37%.

Okay, Chris, we have concluded our opening remarks.

We will now open the call to questions.

During this segment, hold on one sec, Chris.

We just want to point out that we request that our callers limit each turn in the queue to two questions.

They can rejoin the queue with additional questions after that initial volley.

Okay, Chris.

Thank you.

We will now begin the question-and-answer session.

(Operator Instructions)

Doug Leggate, Bank of America.

Thanks, good morning, everybody.

I'm going to take my full quota of two, if I may.

So one specific for Valero and one industry, if I may.

Actually, I don't know if I missed this in your remarks but can you quantify, please, how the hydrocrackers contributed to EBITDA in the quarter?

And if you could put it in the context of the guidance that you had given us for your expected run rate when these projects were under away, and I've got a follow-up on the industry, please?

Yes, Doug.

The St.

Charles hydrocracker, you know, came up in the -- in July of the third quarter and pretty much hit full run rates by mid August.

But hydrocrackers performed very well, particularly given relative to expectations in this margin environment.

Specific EBITDA performance we're not going to provide on these units or pretty much any other unit going forward.

We have got hundreds of units throughout our refineries and it's just too tough to reconcile and manage expectations and to audit each of those, so we -- those units have performed well

But in the context, you did give us specific guidance for what you thought they would contribute.

Can you at least frame the contribution relative to that formal guidance?

Yes, given the margin environment because the guidance was in terms of a margin set.

Under certain margin sets, it performed within guidance, within expectations of that guidance.

Okay, thanks.

My industry question, I'm going to leave it someone else to talk about [riddance].

My issue is on utilization rates for the industry.

The context I really want to set here is that we've always still got very low feedstock prices, particularly natural gas but we've also got some refineries that have expanded and refineries that have been given something of a reprieve on the East Coast so, what I'm kind of curious about is your thoughts on overall gasoline capacity in the US against the weak demand backdrop and whether or not you think the weakness we saw in margins in the third quarter could be something of a new dynamic that might have us reset or lower our expectations for mid-cycle margins.

I know it's a bit of a broad question but just curious on your thoughts on that.

Thanks.

Okay, Doug.

This is Gene.

In general, I think the margin in the third quarter is getting squeezed and I think you know you probably saw some economic run cuts to the end of the quarter in September primarily, but you also had turnarounds coming into play.

But then, move forward the fourth quarter, I think you really got to look at what type of crudes you are running.

If you are running imported sweet crude, then your margins are pretty bad right now but on domestic crude with the differentials blowing out, I think you are seeing better margins in the US.

I think you'll see utilization rates in the US higher versus Europe going forward because of the crude advantage and the natural gas advantage.

How does that impact your thinking then about incremental use of cash on a go forward basis if the margin environment is going to be more challenging?

I'm thinking about your decision to move forward with another step up in your spending.

I think the margin environment in the US is going to be better.

It's going to be squeezed in Europe because again, the crude -- where you have advantaged crudes you're going to have better than average worldwide margins and where you don't have advantaged crudes, you're probably going to be a little bit below mid cycle.

This is Bill Klesse.

The step up in our spending, let's get it in context from the guidance I've given, is about $0.5 billion, and this is guidance.

The market is giving us opportunities in the sense of increased crude oil production is at discounts.

So the light sweet crude is at a discount.

The Brent is widening.

We have the NGLs that are clearly coming to the entire industry whether it's petrochemicals or refining.

And then you look at what we're doing, we're spending a lot of money on logistics because of the party or question actually dealt with exports, let's be honest, and that is a huge part of the future for the refining.

So, maybe at the most we're talking about guidance of $0.5 billion and frankly, we disclosed this in our last presentation how it split out.

We gave that guidance.

It shows a lot of it's logistics and it's economics -- $1.5 billion is economic but we're still in this period of time where we're scoping these projects.

But in our endeavor to keep you all informed, we told you guys what we were looking at.

So that's how we justify, but clearly in the view of this industry in the United States, as Gene just was speaking, you have to be able to export.

And operating rate will be higher because we think the US industry, certainly between the Appalachian Mountains and the Rocky Mountains, is extremely competitive in the world environment.

Appreciate the answers, guys.

Thank you.

Jeff Deitert, Simmons & Company.

With LLS and Mars prices being soft here early in the fourth quarter, there's a great advantage for Valero in the Gulf Coast and also a strong disincentive to import crude into the Gulf Coast.

Could you talk about how these discounted light and medium prices in the Gulf Coast are impacting your crude imports?

And how you think it might impact the industry as a whole, imports into the Gulf Coast?

Well, Doug, this is Joe.

I mean, obviously, they have backed off our waterborne light sweet imports and we basically were there months ago.

The only time that we brought in any light sweet waterborne imports into the Gulf Coast is when there were distressed cargoes out there that we could buy and take advantage of operating with, so this is not a new phenomenon here, it is just kind of a continuation.

If we talk specifically about the light sweet, we've got production, and it's a fundamental issue, we've got production way up, 7.9 million barrels a day, past three inventories are now at 194 million barrels which is 10 million barrels above last year and it's at five-year highs.

And although we've seen draws in Cushing that have brought them down, we've seen built over the last couple of weeks.

But essentially what you got is supply of domestic light sweet crude exceeding demand in the Mid-Continent, and that crude with all the pipelines that we've been talking about for some time now flowing to the US Gulf Coast is creating life down there so it is pressuring those margins and we expect that that's going to continue to for some time.

Medium sour is got to compete for space in the refinery and the Mid-Continent production pushing down there is pressuring Mars and that's where it is today, and then as [hobo] comes on and you are going to be able to move more Mid-Continent barrels over to the Louisiana markets, I think you're going to see even more pressure on it.

So I think we're in for an extended period of discounted light sweet crude on the Gulf Coast as well as solid medium sour discounts.

And then you know, you didn't ask about heavy sour but it all ties in to the same issue.

You have got heavy sour discounts looking very attractive right now.

A lot of it has to do with fuel oil weakness because we've got weak Asian demand and then you have got more supply of fuel oil coming into the market with Middle Eastern and Russian production increases so the inventories of fuel oil are way up.

You've got WTS, which was -- we benefited on discounts improving lately because of refinery outages and then you have Longhorn barrels now that are coming to the Gulf that in the past quarter were head into the Cushing market.

So you're seeing more medium sour head to the Gulf but the WTS discounts are coming off a bit so and then you got the K factor.

So you've got a very solid discounts on your heavy sours, on your medium sours and on your light sweets, and we are starting to see those barrels run through the plants in October and we're seeing much more significant discounts headed for us in December so we're very optimistic about where the crude discounts are.

Long answer.

Yes, secondly, you guys have been successful moving Eagle Ford barrels out of Corpus Christi to Quebec.

And I believe you're permitted to move 100,000 barrels a day.

That arb is wide open.

Eastern Canada imports about 600,000 barrels a day of light crude.

Will more crude move from Corpus, Houston, St.

James up to Eastern Canada given the arbs where they are today?

Could you discuss that and maybe some of the constraining factors?

Well, Jeff, it is.

Yes, you will see more of the domestic crude moving up to Canada and I think, I don't know, Gene, I don't know if you know enough about it of how much they can feasibly run up there?

I could tell you that for us, we're running Eagle Ford crude in the Quebec City refinery today and we've got WTI crude headed that direction.

So, we're doing what we can to go ahead and move barrels up there.

And you know, we're learning how to run these crudes at Quebec City as we go.

So, you want to speak to the --

Some of the other refineries up there, they are predominately meaning sour-type refineries but I imagine they have some capability running sweet but I just don't know what.

I'm sure they're running there LP models and they are trying to optimize that as well.

Thanks, Joe.

Thanks, Gene.

Thanks, Jeff

Robert Kessler, Tudor, Pickering, Holt.

Good morning, guys.

I wanted to see if we can touch a little bit more on this US kind of versus Europe dynamic.

Looking, for example, at your North Atlantic margin contribution or operating income, I'm wondering if you could split out that income in the third quarter between say Quebec City on this side of the pond and Pembroke on the other side?

Robert, we're not going to break out those details.

We will report by region but we're not going to give results by refinery.

Any color you could provide on the market?

I mean your volume guidance for the North Atlantic region for the fourth quarter would imply you're still going to keep the European side running.

Where are you relative to kind of cash cost on a crack spread today at that plant?

Can you give some kind of color there?

We don't have any guidance for you on that either.

I think we'll just stick with the general stuff that you read in the industry and that is until this dip the other day in Brent pricing, it was reported there were a lot of cutbacks in throughput rates in Europe, and then there was a cutback and it says that in the industry data, everyone says there is some profit near.

Our system is a little unique in the sense as we do try to run an Atlantic-based strategy and we do have marketing in the UK and Ireland.

So we'll leave it at that

Okay.

I guess my second question then, third-quarter exports for you of gasoline and diesel out of the US?

We exported 193,000 barrels a day of diesel and 91 of gasoline.

Those numbers are looking larger for the fourth quarter so far.

We continue to have low inventories.

We've got global demand growth and we've got very consistent demand out of Latin America and so and we're seeing it industrywide and from Valero's perspective.

Right now, Rob, the diesel arb here is opening during the RIN and that's the first time it's been like this here in a while so we're very optimistic about the ongoing full products out of the Gulf to Europe and Latin America.

Thanks for that.

I think your capacity to export on the diesel side is 280 moving to 400 or 425.

When do you move up to the 400 plus?

Well, we've got all these capital projects that Bill referred to earlier, the logistic projects, and so it will be over the next several years.

I would tell you today we're probably at maybe a capacity of about 325,000 barrels a day for distillate.

Okay, thanks very much.

Roger Read, Wells Fargo.

I guess kind of taking on with some of the other questions that been asked, we look at the light heavy spread along the Gulf Coast and this came up on the last call, kind of believe an 8% discount of between the lights and the heavy sours, if we look at LLS, we've kind of stayed in that line.

If we look at Brent, it is clearly blown out quite considerably.

What is, at this point, given that there aren't much in the way of light barrels being imported to the Gulf Coast, which one is the better indicator and how do you work around that if LLS is the barrel but the -- I guess you would say the refined products are being priced off of Brent still?

We look at Brent as being the benchmark.

This is Gene again, Roger.

Brent has been the benchmark so you've got two components to your margin.

You have got your feedstock discounts, where we're really not running any Brent, obviously.

So you want Brent today.

We've got an LLS discount that's in the $7 range and then you add your crack to it, and our medium sours are probably more in the $14 range so you think about a medium sour Brent at $14, $15, but LLS at $7, $8.

So it's very good numbers which is kind of what we've been saying all along.

A lot of people were concerned that LLS would get cheap and it would sell cheaper than medium sours.

Well it clearly is not happening.

We're seeing pressure on the medium sours as well.

And as you start to move forward on moving more barrels from the Texas coast to say Eastern Canada or wherever else we may eventually go, I mean what -- how long before we would see an impact then on kind of Gulf Coast prices haven't to come up obviously reflect whatever the transportation costs are, but come up and kind of meet more of a global price issue?

Is that -- can we move enough barrels to Canada?

Is there an appetite, let's just say from the Gulf Coast to get the permits from the Department of Commerce to make that happen?

Right.

Well first of all, the arb light we talked about earlier to Canada is wide open for our facility and we mentioned too that the competitors up there are sometimes are medium sour so they are going to be looking at light sweet from the Gulf Coast but they are somebody looking at medium sours and medium sours are starting to be discounted on an international basis to complete in the Gulf Coast, so you know they will have to optimize based on that.

You also see the arbitrage at current pricing that you could use a US flagged vessel and take crude up to the East Coast refineries but there's limited amounts of these US flagged vessels available so right now I'm not sure it does get solved in the short term.

I think all these barrels are competing against each other.

There's more crude than the market needs in the US but there are market pressures to try to solve them but there's limitations on all of those.

So on top of that, you got more and more domestic sweet being produced every day.

The Bakken numbers, the Eagle Ford numbers, the Permian numbers, just keep ramping up month after month so it's -- I'm not sure exactly how the situation gets solved right now

Well, Roger, just to add to Gene's point, we've got the production coming on stream but it's just this last week that Longhorn started running now at higher rates.

I think they are up to 225.

They were running between 90 and 170 I think for some period of time, and then when MarketLink comes on stream later this year, you're going to have another significant flood of these barrels moving out of the Mid-Continent into the Gulf.

So the pressure continues to build, as Gene said.

Higher production, more take away capacity out of the Mid-Continent to the Gulf.

It's just going to continue to build.

And obviously, the rail economics from the Bakken area to the coast is wide open as well, so there's a lot of market pressures to try to correct this.

The big question is is there enough of it to really solve it.

We don't think there is right now.

Thank you.

Sam Margolin, Cowen and Company.

Good morning.

I was hoping to touch on the light oil units you guys are building in the Gulf Coast.

I know it's pretty far out but if there's anything you could share about sort of current pricing, feedstock replacement, differentials that are maybe off benchmark right now that can help us get a better picture of the economics once those start running and help us model it out.

So, Sam, the premise behind these, there are a couple kind of toppers at specific units that leverage some other infrastructure at those plants.

We're not just doing crude expansions.

We're doing it to fill up some downstream units that are currently importing feedstocks.

So that's basically it.

But it's too soon to give out details to model it specifically.

We're still evaluating the cases, the investment needed, and the various margins that are going to drive it, so we think they look good but still evaluating, so too soon to get into model specifics

Okay.

Well maybe this is a little more near term.

In the past, you've talked about the West Coast, those assets have been up for review a couple of times.

It was obviously a really tough quarter out there this past period and I was wondering if you could shed any light on the way you're thinking about that asset base now, I don't know maybe the MLP changes things in terms of what's out there to drop down and re- monetize.

You might not want to lose it but what's your latest thinking on that region?

Well, it's obvious that we're not making a lot of income or cash flow on the West Coast and so we're looking at our options and continue to look at them from improved operations.

Benicia, this year, hasn't run very well for the whole year.

Working there, we work on our cost structure.

I think you know we have a rail facility planned at Benicia to run this sweet crudes, domestic crudes, and but now we're stuck into an environmental review, or I guess it's an assessment, and so now that project slipped on us where we thought we'd have it done at the end of this year.

It's probably end of next year, so these are -- we are doing a lot of different things to try to improve our situation but, when you get all said and done with that conversation, pad five, if we broaden the focus, is just long refining capacity relative to product demand which is not come close to recovering from the pre-recession period.

And so we just keep looking at all of the above.

Okay.

I think last year sort of demonstrated that that region goes from long to short very quickly.

Is there any -- is there any resistance as far as rationalizing capacity there or it's all up to you?

I suppose you mean resistance being from politicians or somebody?

Yes.

Oh, I'm sure there would be resistance.

You saw happened with Tesoro in Hawaii.

Yes.

So that would be, but the truth is the whole pad five seems to be one or two refineries long so when one or two refineries go down, you make a lot of money.

All right.

Well thanks for the time.

Paul Cheng, Barclays.

Two questions.

Maybe this is for Gene.

Gene, have you railed in any Bakken and WCS into any part of your system in the third quarter?

And how is that looking in the fourth quarter?

Joe will answer your call

Yes, Paul, absolutely we have railed Bakken in and we've railed heavy sour crudes in also.

We've got bitumen that is gone into St.

Charles and we're probably doing 20 a day of that, and then the Bakken is actually, I would tell you, all of Memphis' volume is theoretically railed Bakken.

It goes down the Gulf Coast to St.

James and then we bring it back up on cap line but it's railed down there and then at Quebec, we started up the rail loading facility and that's going very well.

You must be [preening Monday] because the Brent to Bakken is now $25 discount on the wellhead?

So you can get your hand on I mean how much is the total Bakken that you're railing?

Any rough estimate that in the fourth quarter?

Let me see.

I'll tell you it's -- in the third quarter it was 130 a day and that's primarily Memphis volumes.

It will increase -- I don't have the number of Bakken versus other crudes that we're going to be running in Quebec so maybe another 40 or 50 on top of that?

So call it 200.

Call it -- sure.

180 to 200.

Must be extremely popular on those.

And that -- Joe, it look like that the LLS delivery price is even lower than the spot at this point so when people looking at the numbers, say ROS 6321, they actually is underestimating the margin, is it?

Yes, it's very close, Paul, but it might be, I don't know, it might be a buck?

And then a final one.

When I looking at that sequentially from the third to the fourth quarter with the lower RIN price and look like better wholesale margin, so far quarter to date is it safe for us to assume your margin capturing in your system is accurate, better in the fourth quarter comparing to the third quarter?

Yes, you're talking about on just our income, Paul, specifically?

On your gross margin, that comparing to the benchmark you guys provide on your website.

Should we assume that the third quarter looks like they have hit the low point at least in the near term?

In both quarters, it looks like it's much better?

Right and that's true.

The lag effect in our crude pricing is going to give us a better discounts going into the fourth quarter and it's going to help our economics.

I mean, they are significantly better.

We saw a little bit of it in October but we're seeing a lot more of it in November.

Yes, the point we're trying to make here, Paul, is you're asking obviously for a little guidance here and what we would tell you is that October generally isn't that much better than September but because of the lag in the system, for all us guys in this business, November and December look a lot better so our gross margin basis fourth quarter does look better than third quarter but it's a lag, it's a lag.

Perfect.

Joe, when I'm looking at your guidance, the RIN course for the full year at 500 to 600.

This quarter you have 75, second quarter 125, third quarter 185, so are you suggesting that the fourth quarter is still at $115 million to $215 million given that the RIN core seems like it jumped down into the $0.30 compared to the $0.80, $0.85 in the second and third quarter?

Are we missing something or that is just that you are being conservative?

No.

I'll tell you the numbers that I have don't really sync up with the numbers that you just stated.

I would tell you that the number that we've got to achieve compliance is probably a lower number than you have

Paul, this is Mike.

The year-to-date number through September is 439.

So, to get to the 500, the bottom end of the range, you're looking at $60 million.

Okay, perfect, thank you.

Blake Fernandez, Howard Weil.

Question for you on Meraux.

I had seen some price reports suggesting there was a rupture at the crude unit.

Obviously, Ashley has already given us throughput guidance for 4Q.

I'm just trying to confirm that there's no major issue or anything that we need to be aware of there?

This is Lane Riggs.

Back to crudes back in today and we're going to be at full rates in about another two days and so in terms of forward guidance on throughputs, Ashley's numbers are fine.

Okay.

Good deal.

I want to be clear it wasn't per se a rupture.

We were doing maintenance work and we had a stop wall and the stop wall didn't hold and that's what happened, so we didn't have a piece of pipe just break or something.

We were doing maintenance work, at which we're looking at our procedures in detail here as to how that could have happened.

Okay, got it.

Thanks, Bill.

The second question was on the unloading facility at Quebec.

I'm trying to see if we can help quantify maybe the potential shift in feedstock.

Do you have any kind of clarity you can provide or ways to think about maybe the cost of transporting up there via rail and maybe the discounts you are getting?

Any color you could provide would be helpful.

Thanks.

So, Blake, this is Joe.

Now you know I can't tell you everything you want to know here, right?

But I would tell you from a volumetric perspective, the rail facility was available to us in August and in September we started ramping up volumes a bit.

I would tell you we might have run 15 at day of rail crude in September.

By later this year, we'll be running 50 a day of rail crude.

We've got it set up now so we can take 100-car streams which is a block which basically kind of gives you a unit train operation which is kind of the best economics that we can achieve on this.

You know what the rail cost is to the East Coast out of these producing regions and Western Canada, and you know the rail cost into Quebec is cheaper, so I would tell you if you want to use $10 to $12 a barrel, you could probably use that and you can see what the discounts are for Bakken and the Syncrude over in that market and kind of come up with what the benefit might look like right now.

So, in addition to the rail crudes we've got going in there, though we also then have the waterborne crudes, and I said earlier we're moving WTI.

We're actually moving Eagle Ford and Bakken crudes up there and we expect that we'll be doing somewhere around 50 a day by the end of the year.

So, 45 to 50 a day.

So we're getting a lot of North American crude into the Quebec refinery and then we had a call yesterday with our Canadian guys and discussed the status of Line 9 and it looks like everything is going well and the project is progressing.

We're encouraged by the fact that some of the reviews, for example, in Ontario they were going to review the project on an independent basis.

They have canceled that review.

So, everybody seems to be getting more comfortable with that pipe and at that point in time we'll probably be running all of North America -- when that line comes on, we'll be running all North American crude in Quebec, we'll be back up to 400 barrels.

That's perfect.

Blake, this is Klesse.

This even goes back to Paul's question.

Maybe I'm trying to manage expectations a little here.

There is no question running domestic crude oil or North American crude oil is very advantageous.

And we give up some of that by the costs but clearly shipping from the Gulf Coast to Canada is a couple bucks.

The rail, it's in our handout.

We have all those rates in there, so all this is extremely profitable.

On the other side, though, the gasoline crack still isn't really that good.

Actually, it's crummy.

Butanes -- we make a lot of other stuff besides just diesel and gasoline and jet and a lot of those markets are weak.

So, yes, the crude is clearly an advantage but some of the other products are not contributing here.

So, I'm just trying to manage it because I could see where your question, Paul's question.

Yes, it's better than it was in the third quarter but there are things that are negative.

Got it.

Okay.

Thanks for the color, guys.

Appreciate it.

Ed Westlake, Credit Suisse.

Just coming back to the crudes side.

Obviously, great conditions down in the Gulf at the moment.

Are you seeing from say some of the medium importers sort of one, one and a half million barrels a day comes into the Gulf and I appreciate you're more heavy, but are you seeing some of those medium imports I'm thinking mainly the Middle East start to try and redirect the cargoes?

How do you think that's going to pan out with a growing supply that's coming down the pipes?

Ed, I don't know.

I mean I don't know that we've seen Middle Eastern cargoes redirected.

I know we haven't.

I haven't.

They're really priced so the target is at the index which is a complicated power so their pricing is based on US basis.

But do they have better opportunities to move over into Asia?

We haven't really --

We don't really historically to have, right?

They always have.

There is still a lot of barrels that need to clear the Gulf Coast for those markets

And just thinking about the $8 spread at the moment between I guess LLS is the only decent benchmark we have, how has that changed your thinking about this sort of I guess the industry expectations say a year ago of sort of two to five as being the sort of right kind discounts to sort of encourage those to move to other markets?

Ed, this is Gene again.

When a market gets over-supplied, it's hard to really pick the right number.

Why did WTI go to Brent go to $25 last year, so when it's over-supplied, so two to five, I mean to me fundamentally it's no different than eight.

It's just a matter of where the market shakes out.

The market's clearly long.

It's hard to say with the right number is.

So, we think we still stated our position that things will eventually evolve to transportation costs.

But you have to have what Gene just said, you have to have adequate ways of adequate capacity in the transportation area.

And until you get that, then what Gene said, what is the number.

And yes, are we a little surprised it's blown up this much?

Of course we are, but I think long term, for long term it doesn't really change our thinking.

The switching to that idea of transport, I mean obviously $1.5 billion I think is your CapEx for strategic, and obviously a chunk of that methanol but the chunk of that is going to be on the logistics.

Could you give us sort of an update on what type of -- I'm thinking to make it simple, EV EBITDA that you are investing at.

I mean obviously we know the MLPs trade at high multiples but what sort of return do you think you're getting on your organic logistic investments?

Yes, Ed.

So, this is Ashley.

We don't have returns for each project and then you can slice these different ways because does the refinery get the benefit or does the rail car get the benefit.

There's a lot of ways you could look at it and then how will that return then go in if it was -- asset was going to go into a logistics partnership where do you put the return.

Directionally, they're all beneficial.

Most of them were pretty high return projects especially because they are bringing advantaged crude to refineries but giving specific returns by each dock, by each rail car, we're not going to provide.

I'm just fishing to try and help us get an estimates of how much logistics EBITDA you'll have down the road after you've spent a lot of this capital

And it's a fair question.

Part of the problem is what Ashley said.

The other piece of it is we're very convinced the future in this business just strategically is you've got to be able to move stuff around.

You've got to be able load ships.

And so some of these projects like our dock at Corpus Christi, we just say we've got to have it.

Docks at St.

Charles, building a new dock over there maybe, Port Arthur, we're just saying this is the way the future has to be, just like some of our competitors are saying the same thing.

With the MLP, obviously you have a cost structure that permits them to be dropped at a reasonable rate so, it all fits together, we think as a management team as well but it's hard for us to tell you as Ashley said, this project yields that, this project yields that.

(multiple speakers) They are all gong to be above the cost of capital and they are all going to fit very nicely in this portfolio.

Maybe one final thing then is there a constraint on moving even faster in terms of growing these logistics or spending more money in that area?

I don't see us doing that so I guess it's just our capability to do things and we think we're doing the right projects now that work on our strategy.

So, that's not -- we've given your guidance for next year and that's the guidance we're sticking with

Right, okay.

Thanks very much.

Doug Terreson, ISI Group.

I have a couple of questions.

First, the capture rate seemed a little bit low in relation to Q3 of years past and so, I think we talked about how it's going to rebound but I just wanted to see if there were any color you could provide into those results?

And then second, this morning, BP highlighted normal seasonal factors and I think growth is competitive capacity is the driver of weakness in global gross margins recently meaning exclusive of the positive feedstock points that Ashley, Gene, and Joe made about Valero's system in the United States.

And so, this might be a question for Bill but I just wanted to see whether you think the recent weakness in global margins is seasonal, cyclical, or both?

Also, whether or not there were any either issues that may help to explain some of these recent global trends?

Hey, Doug let me start with your capture rate stuff.

I'll give a couple of generalities because everyone models differently and has got different assumptions so it's hard to reconcile subjective stuff like that on an earnings call.

Sure.

But, key factors that aren't in a typical indicator are RIN costs, not everyone captures butanes and naphthas and things like that and those had wild depressed swings in the third quarter that impacted what you would normally see in prior periods when there's four to factor.

Those are probably the biggest ones probably across the entire industry.

Okay.

But any other detail, we would have to do it one-on-one because --

That's fine, Ashley.

For your model.

Yes.

Doug, this is Gene.

On the global margins, I guess the way we view it is with the new capacity coming on in Saudi and some of the Chinese refineries, there is going to be pressure on certain refineries in the world to kind of make room for that.

I think that includes some of the Asian refineries in Japan and Korea and Australia and some of those rationalizing and also in Europe as Europe is going to have to make room for not only the US exports but the new Saudi refinery exports.

And Europe's only advantage really is diesel demand and that can be supplied cheaper from other sources so we think global margins are off a little bit and kind of look at past 2011, 2012 margins, 2013 margins are a little weak -- are definitely weaker as you're moving in the fourth quarter so I guess we would say that pattern continues next year.

Now I don't think margins are going to be so bad as they are right now in the fourth quarter where every refinery in Europe loses money.

I mean that's too far, right?

So somewhere you'll get some bounce back but I think you'll see weaker margins in Europe than we have for the last couple of years.

Okay, Gene.

Thanks a lot.

Paul Sankey, Deutsche Bank.

Morning, all.

You gave us the product export numbers which Bill, you said in the past is really the key to the whole bull case here given the weakness of US demand.

I was interested that you have got more capacity to export seemingly, or correct me if you don't, but given the weakness of, as you said, crummy gasoline cracks I was wondering why more -- why there wasn't more export, if you like, or what the constraint was on exports and I understand you also said that exports -- net exports are up this quarter.

This is Joe, Paul.

So economics the dictate a lot of our export volume and so the -- we take into consideration not only the margin that we can get on the barrel that is going out but also then the RIN effect.

And clearly in the third quarter that would have encouraged exports to be as aggressive as possible.

The distillate export volume we had was very much what we expect.

It is going up significantly in October and again with the [arb] being open to Europe we are going to see that be much stronger I think in the fourth quarter.

The gaslight exports, we've moved most of that volume out of our Corpus Christi refinery and a lot of it's termed up, it went into Mexico, it went into South America.

But that is part of our business that as we look at it going forward we are very focused on expanding and so strategically, we have initiatives that we have underway to try to create additional opportunities for ourself to move those barrels out but it wasn't there yet today.

Even though we've got capacity to export, you have got to have a market to move it into and there's got to be demand for it.

And so we moved as much as we could economically move versus the alternative.

Yes.

It's all versus the alternative, Paul.

After net backs and different grades in those different markets so just we're constantly optimizing around that.

I guess what you're saying is that diesel is great, right?

You can export it with the RINs, [a life] of RINs to Europe and so that's maxed out.

On gasoline, the alternative is a different as a competitor essentially.

Is that what you're saying that has a lower price than you?

I think what we're going to say to you is, you're optimizing the refinery to make distillates.

Even our distillates are up.

And it's not necessarily that we're sparing the [cats] but if you look at our operating rates, our operating rates in the whole industry have been, with the turnaround that Gene mentioned earlier, have been very good so operating rates are okay.

They have come down some on crude units but generally they are okay.

And so we're making the product slate that maximizes our profit on the back end of the refinery and so we have this gasoline, we place it the domestic market and some has to go out of the country.

As Joe said, some are from our refinery in Corpus Christi but we're not necessarily sparing gasoline units but the gasoline margin is poor so we're optimizing to jet, diesel, and those streams.

Yes I get that and --

I know you think --

Just to go back to what Joe said just to re-clarify it, can you just kind of go over again whey there's not more gasoline exports, Joe?

Sorry, I know you kind of answered but if you totally clarify it for me?

When the next 50,000 barrels of gasoline go out, would it be a loss or would it be a marginal economic?

That's basically the question.

And that would be set by the bid from a buyer abroad?

That's right.

And netbacks and shipping and --

Yes.

Paul, remember I think we've got -- we had shipping rates that were very high during the third quarter.

I think we were $0.115 a gallon versus $0.075 in Europe, $0.07 today, so there are a lot of factors that come into play but again, it's economics.

We had a little fun conversation here so we obviously have export capability so then it turns into either a quality or the refinery economics and as we run our economics in the refinery, basically we are always in balance, right, because you adjust operating rate so we didn't find it attractive to make more gasoline.

So, I mean it's because of the economics.

If the economics for gasoline had been really strong, we would have figured out how to make more gasoline.

Yes, just to clarify you --

And that is the answer, the economics in the refinery didn't drive us to make more gasoline.

Then the marketing groups dispose of it to the best way they can.

Yes, I get it.

Just I think did you say that your export capacity is now 350 because we were running with a 280 number and if I add the 193 plus the 91, 193 distillate plus the 91 gasoline, I get obviously to 284 but then I think you said your capacity to export is actually 350, or am I wrong?

All right.

The gasoline, we would say that our gasoline export capabilities logistically is 225 and logistically on diesel is 325 today.

Great.

So the point I guess, Paul is that we're not logistically constrained.

It goes back to Bill's point about economics.

Right.

That's exactly what I was trying to get at.

I think I get it.

I think it's a little Atlantic basin thing that we're going to have to think about, right?

And the RINs you're referring to obviously is European RINs, right?

(multiple speakers)

No, we're talking about the RINs, the cost of RINs so in the US when you -- when we sell product in the US we're the obligated party.

When you export, you don't have that obligation.

So, Joe is telling you that works into the math.

Yes I'm going to take this off-line but I'm getting that.

It's just that it's so important obviously to the outlook, how much we can export and how much we can grow that going forward.

Just separately, the DD&A jumped up even with high utilization, high throughputs, DD&A per barrel jumped up.

Is there anything you had on that?

Yes, it was up about $40 million from the prior quarter.

It relates to accelerated depreciation that we took on some of our logistics assets as we were finalizing the financial statements for the MLP.

And then we also had St.

Charles hydrocracker start up so we had added depreciation from that project.

Great.

Thanks very much.

So that's not going to be an ongoing, we don't obviously forecast that to keep growing at that rate?

No, no, no.

The guidance I think Ashley gave was 425 so it's going to be about $30 million less than what the third quarter was.

Perfect.

That's two questions.

Thanks.

Chi Chow, Macquarie Capital.

Great, thank you.

Got a question back on the cost advantage crudes, and in your latest presentation you have a slide showing the Gulf Coast -- well you have advantaged crude processed by region and I was just noticing your Gulf Coast capacity looks like its first quarter.

Second quarter this year is around 320,000 -- 320,000 maybe 25,000 barrels a day, do have that same metric for the third quarter?

Let me see here, capacity is about the same.

It was running -- we estimated capacity to process like light crudes was in 2Q around 280,000, 290,000.

We estimate it is up around 310,000 now for third quarter.

Okay.

Are you maxed out on the Gulf Coast at this point on the advantaged crudes until Corpus and Houston those projects come on or are there are just more opportunities to tweak the volumes higher in the meantime?

This is Lane.

We still have the opportunity to optimize the domestic sweets versus, really I would say, medium sour imports and so we haven't entirely used all of our capacity yet to put these domestic crudes into our refineries.

We still have some capacity left even beyond these projects we're looking at.

Lane, do you have an estimate on volumes, on how much more you can kind of optimize towards?

Yes.

Our capacity right now is around 415,000 barrels a day to run these crudes

In the Gulf?

In the Gulf.

Remember your displacing medium sours in some of this stuff that we still have better economics on medium sours.

That's the reason we're only running the 310,000 versus the 400,000 capacity is because we still have better economics on the medium.

Right.

Okay.

Thanks, Gene.

I guess second question back on this RIN issue, Bill do you have any comment on this supposed leaked EPA document?

Really, what is the outlook on your end into 2014 and what the mandate may look at?

And have you had any discussions with regulators or the administration lately?

And any feel for how they're thinking about next year?

Yes, Chi, this is Joe.

And I mean I think the answer to all your questions is yes.

I mean obviously the leaked information, along with other things that the EPA has said, have led to this decline in RIN prices.

They recognized clearly that the blend wall is an issue and they said they are going to address it.

They extended the deadline for compliance for 2013 to June of 2014.

And then the leaked memo comes out and it has a fairly significant reduction in 2014 statutory levels to what they proposed in 2014.

Now, that being said, none of us know if this is true or not.

But, it certainly had the effect of taking the pressure off of the RIN market and that's why we saw it drop from the mid $1.40s to $0.20 or sub-$0.20 today.

So, if we look out, I mean EPA gave us a short-term release.

As we look out, there has been a lot of activity on the legislative front and there are many bipartisan groups that are working on amendments, rewrites essentially, of the RFS.

And they are kind of across the continuum as you would expect although we think it's poor legislation and it should be repealed, it's really much more probable that it gets amended and it becomes palatable and it puts the RINs where they should be which is a compliance tool and not something that economically effects compliance with the RFS.

You know Bill's had many meetings on this in DC and other places and I've had one also and so we continue to work the issue and we do think that we're going to get some relief in 2014.

And hopefully longer term with legislative relief.

Okay.

Thanks, Joe.

So do you think these legislative actions on the rewrites, I mean does the EPA kind of -- do they just short-circuit that effort by just kind of taking the rug out of 2014?

And is this going to be just a year by year kind of rolling uncertainty as we go into the RFS the following year or do you really believe there will be a rewrite at some point on the RFS?

Okay, so first of all I think the EPA did what they could and they acted within their authority to do what they needed to do for 2013, 2014, okay?

But, looking out I do think that there's enough attention on this issue that you are going to get a legislative fix.

I'm hopeful that you are and there are a lot of people working it so I expect that we're going to see something.

I'm not sure what it will be.

It certainly won't be this year but hopefully we see it sometime in the early to mid part of next year.

Okay.

Thanks, Joe.

I really appreciate it.

It's Ashley.

I want to clarify on your first question.

I was just talking about the light crude capacities and what we're processing so when you add in the Canadian stuff and this better matches that chart you were referring to in the appendix of our slide deck, it has been improving.

1Q was 331,000 a day.

This is all Gulf Coast.

331,000 a day.

2Q was 336,000, 3Q was 346,000.

It's mostly light but we're getting some advantage to Canadian heavier stuff too.

Okay, great.

Thanks, Ashley.

Allen Good, Morningstar.

I wonder if I can just come back to the export issue and to get your thoughts on the market, maybe a bit longer term.

It would seem that every refinery, including yourselves, are betting on maintaining high utilization through exports as a result you're building that export capacity.

But if we look at the US, it seems like the oversupply will be in gasoline and if you think about globally it seems Europe will bear the brunt of the refinery closures and that's not really a gasoline market.

I'm just wondering where do see that extra demand for gasoline coming from given it seems like gasoline exports will need to increase over the next few years.

Is it simply a fact of increasing demand in Latin America or do you think you can grow markets elsewhere?

And then more importantly, how do you think Valero maintains its market share of exports considering your peers are really jumping into the export market with additional capacity as well?

Okay, this is Gene.

As far as Europe not importing gasoline, they, you're right they don't, but they do export a lot of gasoline when they run the refineries full out.

I think when you get the rationalization in Europe, they don't reduce their gasoline exports in places like West Africa and Latin America to make room for the US barrels which have a big cost advantage.

And so what do you think as far as with peers increasing as well?

Do you think they'll be enough of that lost supply from Europe really to accommodate all US refineries who are looking to export more product?

It's more than just Europe.

We talked a little earlier about the whole global market.

There's also refineries going down in Australia, Korea, Japan, the European refineries, anyone that has disadvantaged crude without a market.

Some of the -- if you're importing crude, exporting products, and you are on LNG, natural gas, you are pretty much disadvantaged.

Those are the refineries that will make room for the more competitive refineries.

Gasoline demand in Latin America, you've got population growth, you've got economies growing, you've got increase demand and you've got operations that historically anyway have not been very good.

And Mexico, they have decent operations but structurally they are short on gasoline and they continue to grow.

Venezuelans have a significant refinery operating issues in the Caribbean which affected gasoline supply and which I don't know get resolved anytime soon so, although I think Gene's comments on Europe are right and I also think we're fairly comfortable that with low-cost efficient refineries in the US Gulf Coast and the natural resource advantages that we are enjoying there, we are going to be able to continue to be very competitive exporters not only to Europe but also to Latin America.

Okay, great thanks for that.

And then if I just come back to capital spending, I guess a couple of years it was assumed once the hydrocrackers were completed that you would see capital spending fall.

Clearly you mentioned earlier that the markets presenting a lot of opportunities for you to continue to reinvest in the business.

If we were to assume that current market conditions hold going forward, do you think your queue of potential projects is deep enough where we could assume that this $1.5 billion on growth would continue and maybe the $3 billion total for capital spending would be a safe run rate over the next few years?

Or, do expect you will extinguish some of these current opportunities over the next year or two and we'll see capital spending maybe fall back down once we get three, four years out?

Well we're only giving the guidance for 2014 but a big part of the 2014 spending is logistics and those projects get completed.

And, so as they fall off, it remains to be seen.

But we think part of our job is to add shareholder value and there are these opportunities.

But we are not -- we're not just saying hey, capital spending is going up, up, up.

What we did is we raised our 2014 guidance basically $0.5 billion to $3 billion because really a lot of logistics stuff we're trying to get done and a lot of it does get done next year.

Okay, great.

Thanks.

And if I could just one quick follow-up.

I guess share repurchases fell off in the third quarter.

It seems that on your run rate for the fourth you are back to about call it a little bit less than $300 million per quarter.

Should we assume that run rate going forward until you extinguish the [$30] billion or would you look to potentially add to the $3 billion once we get closer to the end or extinguishment of that level?

Yes, hey, Alan it's Ashley.

We don't have guidance on specific -- how much specific buyback activity we're going to do going forward.

Except that we do consider that a priority return of cash to shareholders along with the recurring dividend.

But we won't provide specific guidance.

But just to reiterate what Ashley said in his comments, we've spent $675 million buying our shares this year.

We raised our dividend so our dividend is going to approach I think $400 million on an annual rate.

That's over $1 billion and we spun off at CST so this management team, for any of the people that are still on the call, this management team has been very focused on returning value to the shareholder.

Great.

Thank you very much.

Matt Carter-Tracy, Goldman Sachs.

Great, thank you.

Just one additional question on crude export.s I know you addressed the product export constraints in some depth, but I'm curious as you are looking at both railing Bakken crude into Quebec and also shipping Eagle Ford crude by tanker, if there are actually any logistical constraints that would keep you from shipping more Gulf Coast crude to Quebec if the differentials became favorable to doing that?

Well, I mean on the water there are because we're supplying Quebec all the water today which with foreign light sweet crude so there certainly wouldn't be on the water.

On the rails side, I think we're probably going to be maxed out somewhere around 65,000 barrels a day, but then you know we're also going to be a shipper on Line 9 and so those barrels will deliver and all the water that they'll come from Canada.

So I would say no.

So, Joe said that earlier there was all those projects you just mentioned get finished and we set said it on previous calls that the Quebec refinery is going to evolve into a North American crude supply refinery where it used to be 100% foreign but you will still have this economic opportunity because you have the hardware.

But over the next year, we're still importing crude into Quebec.

And we've told you guys in the past, we've run Sahara and out of Algeria, CPC, so I mean there's probably some West African thrown in there, so they'll run out the whole 240,000 barrels a day or so of our capacity there we, for the next year, will still be an importer.

Because you do wind up with some refining hardware capability here.

Eagle Ford is very paraffinic.

It gives the whole industry problems in the crude heater, so you do wind up with some processing limitations which then we all try to address here through hardware.

But for the next year we're still going to run some foreign crude there.

Sure.

Thank you.

We have no further questions at this time.

I would like to turn the call back over to Valero Energy Corporation's management for closing remarks.

Okay.

Thank you, Chris.

We thank our callers and listeners for joining the call today, and if you have any other questions please call Investor Relations.

Thank you.

Thank you, ladies and gentlemen.

This concludes today's conference.

Thank you for participating.

You may now disconnect.

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