Valero Energy Corporation (VLO) Q3 2013 Earnings Report, Transcript and Summary

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 to the earnings release are tables that provide additional financial information on our business segments. If you have any questions after reviewing these tables, please feel free to contact me after the call. Before we get started, I'd like to direct your attention to the forward-looking statement disclaimer contained in the press release. In summary, it says that statements in the press release and on this conference call that state the company's or management's expectations or predictions of the future are forward-looking statements intended to be covered by the Safe Harbor provisions under federal securities laws. There are many factors that could cause actual results to differ from our expectations, including those we've described in our filings with the SEC. Okay. As noted in the release, we reported 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 the 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 1,047,000 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 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 the 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 costs of Renewable Identification Numbers, or RINs, needed to comply with the U.S. 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 volume 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 costs 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 U.K. 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 $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 authorizations. 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 $5.0 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: U.S. Gulf Coast at 1.45 million to 1.5 million barrels per day; U.S. Mid-Continent at 420,000 to 440,000 barrels per day; U.S. 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 noncash 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. [Operator Instructions] Okay, Chris.

[Operator Instructions] And our first question comes from Doug Leggate from Bank of America.

I'm going to take my full quota of 2, 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 underway? And I've got a follow-up on the industry, please.

Yes, Doug. The St. Charles hydrocracker came up in the -- in July of the third quarter and pretty much hit full run rates by mid-August. Both 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 get 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 a specific guidance for what you thought they would contribute. Can you at least frame the contribution relative to that former guidance?

Yes. It's -- given the margin environment, because the guidance was in terms of a margin set, under certain margin sets, it -- they performed within guidance, within expectations of those -- that guidance.

Okay. My industry question -- I'm going to leave it to someone else to talk about riddance [ph], but my issue is on utilization rates for the industry. The context I really want to set here is that we've obviously 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 U.S. against a weak demand backdrop and whether or not you think the weakness we saw on margins in the third quarter could be something about kind of new dynamic that may have us reset or lower our expectations for mid-cycle margins. And I know it's a bit of a broad question but just curious on your thoughts on that.

Okay. Doug, this is Gene. In general, I think the margins in the third quarter are getting squeezed. And I think you probably saw some economic running cuts [ph] towards the end of the quarter, in September, primarily, but you also had turnarounds coming into play. But then moving forward in the fourth quarter, I think you got to look at what type of crudes you're running. If you're running imported sweet crude, your margins are pretty bad right now. But on domestic crude, with the differentials blowing out, I think you're seeing better margins in the U.S. And I think you'll see utilization rates in the U.S. higher versus Europe going forward because of crude advantage and the natural gas advantage.

How does that impact your thinking then about incremental use of cash in 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.

Well, I think the margin environment in the U.S. 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.

The step -- this is 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 at a discount. So the light sweet crude is at a discount to Brent 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 the part of your 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've disclosed this in our last presentation, how it's split out. We gave that guidance. It shows a lot of it's logistics and it's -- being in half 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 that the U.S. industry, certainly between the Appalachian Mountains and the Rocky Mountains, is extremely competitive in the world environment.

And our next question comes from Jeff Dietert from Simmons & Company. Jeffrey A. Dietert - Simmons & Company International, Research Division: With LLS and Mars prices being soft here early in the fourth quarter, there's a great advantage for Valero on 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've backed out 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 was 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's just kind of a continuation. If we talk specifically about the light sweets, I mean, we got production -- and it's a fundamental issue. We got production way up, 7.9 million barrels a day, pass-through [ph] inventories are now at 194 million barrels, which is 10 million barrels above last year, and it's at 5-year highs. And although we've seen draws in Cushing that brought them down, we've seen builds over the last couple of weeks. But essentially, what you've 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 U.S. Gulf Coast, and it's creating length down there. So it is pressuring those margins. And we expect that, that's going to continue for some time. Medium sour has got to compete for space in the refinery. And Mid-Continent production pushing down there is pressuring Mars, and that's where it is today. And then as Ho-Ho [ph] comes on, and you're 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 it for an extended period of discounted light sweet crude on the Gulf Coast, as well as solid medium sour discounts. And then I think you didn't ask about heavy sour, but it all ties into the same issue. You've 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've 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 we benefited on discounts improving lately because of refinery outages. And then you have Longhorn barrels. Now they're coming to the Gulf that in the past quarter, were headed to 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 very solid discounts on your heavy sours, on your medium sours and on your light sweets. And we're starting to see those barrels run through the plants in October, and we're seeing much more significant discounts headed for us in November. So we're very optimistic about where the crude discounts are. Long answer [indiscernible]. Jeffrey A. Dietert - Simmons & Company International, Research Division: Secondly, you guys have been successful moving Eagle Ford barrels out of Corpus Christi to Québec. 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, 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 if you know. Gene, I don't know if you know enough about it on how much they can feasibly run up there. I can tell you that for us, we are running Eagle Ford crude in the Québec City refinery today, and we got WTI crude headed that direction. So we're doing what we can to go ahead and move barrels up there, and we're learning how to run these crudes at Québec City as we go. So do you want to speak to the...

Well, some of the other refineries up there, they are predominantly medium sour-type refineries. But I imagine they have some capabilities running sweet, but I just don't know what. I'm sure they're running their LP models, and they're trying to optimize that as well.

And our next question comes from Robert Kessler of Tudor, Pickering, Holt. Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: I want to see if we could touch a little bit more on this kind of U.S. 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, Québec City on this side of the pond and Pembroke on the other side.

Robert, we're not going to break out those details. We report by region, but we're not going to give results by refinery. Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: 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 costs on a crack spread today at that plant? Can you give us 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 -- in the industry data, everyone says there's some profit in Europe [ph]. Our system is a little unique in the sense as we do try to run an Atlantic Basin strategy and we do have marketing in the U.K. and Ireland. And so we'll leave it at that. Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. I guess my second question then, third quarter exports for you of gasoline and diesel out of the U.S.?

Yes. We exported 193,000 barrels a day of diesel and 91,000 of gasoline, and those numbers are looking larger for the fourth quarter so far. We continue to have low inventories. We got a global demand growth, and we got very consistent demand out of Latin America. And so -- and we're seeing it industry-wide and from Valero's perspective. Right now, Rob, the arb -- the diesel arb to Europe is opening, ignoring 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 pull of products out of the Gulf to Europe and Latin America. Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: I think your capacity to export on the diesel side is 280,000, moving to 400,000 or 425,000. When do you move up to that 400,000-plus?

Well, we've got all these capital projects that Bill referred to earlier, the logistics 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 per day for distillate.

Our next question comes from Roger Read from Wells Fargo.

I guess kind of taking on with some of the other questions that have been asked, if we look at the light-heavy spread along the Gulf Coast, and this came up on the last call, you kind of believed an 8% discount 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's 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, I guess, you would say the refined products are being priced off of Brent still?

Yes, that's -- we look at Brent as being the benchmark -- this is Gene again, Roger. Brent as being the benchmark, so then you've got 2 components to your margin. You got your feedstock discounts. We're really not running any Brent, obviously. So if you're at Brent today, we've got an LLS discount. It's in the $7 range, and then you add your crack to it. And on medium sours, they're probably more in the $14 range. So you think about a medium sour at Brent, $14, $15, but LLS, it's $7, $8. So it's a -- they're 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, clearly, it's 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 they may eventually go, I mean, what -- how long before we would see an impact then on kind of Gulf Coast prices having to come up, obviously, reflect whatever the transportation costs are, but come up and kind of meet more of a global price issue? I mean, 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 were talking about earlier to Canada is wide open for our facility, and we mentioned, too, that the competitors up there sometimes are medium sour. So they're going to be looking at light sweet in the Gulf Coast. But they're still going to be looking at medium sours, and medium sours are starting to be discounted on an international basis to compete in the Gulf Coast. So they'll have to optimize based on that. You also see the arbitrage at current pricing that you could use a U.S. wide vessel and take crude up to the East Coast refineries. But there's limited amounts of these U.S. wide 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 U.S., but there are market pressures to try to solve them. But there's limitations on all those. So -- and on top of that, you've got more and more domestic sweet being produced every day. I mean, 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 was just this last week that Longhorn started running now at higher rates. I think they are up to 225,000. They were running between 90,000 and 170,000, I think, for some period of time. And then when MarketLink comes on stream later this year, you're going to have another significant slog of these barrels moving out of the Mid-Continent into the Gulf. So the pressure continues to build. As Gene said, higher production, more takeaway 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.

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

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 of 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, evaluating 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 remonetize. 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 in 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 these sweet crudes, domestic crudes, 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 the end of next year. So these are the -- we're doing a lot of different things to try to improve our situation. But when you get all said and done with that conversation, PADD V, if we broadened the focus is just long refining capacity relative to product demand, which has not come close to recovering from the prerecession period. And so we just keep looking at all the -- all of the above.

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

I'm sure there would be resistance. You saw what happened with Tesoro in Hawaii. So that would be. But the truth is, the whole PADD V seems to be 1 or 2 refineries long. So when 1 or 2 refineries go down, you make a lot of money.

And our next question comes from Paul Cheng from 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 that looking in the fourth quarter?

Joe will answer you, Paul.

Yes, Paul. Yes, absolutely. We have railed Bakken in, and we've railed heavy sour crudes in also. We've got bitumen that has 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 to the U.S. Gulf Coast, to St. James, and then we bring it back up on Capline, but it's railed down there. And in Québec, we started up the rail-loading facility, and that's going very well.

You must be [indiscernible] because the Brent and Bakken is like $25 discount on the wellhead. So you can get your hand on. I mean, how much is the total Bakken that you are running? Any rough estimate of that in the fourth quarter?

Let me see. I'd tell you it's -- it was -- 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 at Québec, so maybe another 40 or 50 on top of that.

So call it 200?

I'll call it, sure, 180 to 200.

You must be extremely profitable on those. And, Joe, it looked like that the LLS delivery price is even lower that the spot at this point. So when people looking at [indiscernible], say, LLS 6321, it actually is underestimating the margin. Is it?

Yes. It's very close, Paul, but it might be -- I don't know, it might be $1.

And then a final one. When I'm looking at that sequentially from the third to the fourth quarter with the lower RIN price and looks like better wholesale margin, so far, quarter-to-date, is it safe for us to assume your margin capture weight [ph] in your system is actually better in the fourth quarter comparing to the third quarter?

You're talking about just our income, Paul, specifically?

On your gross margin, that comparing to the benchmark, you guys provide in your website. Should we assume that the third quarter looked like may have hit the low point at least in the near term, and both quarters looked like it's much better?

Right. And that's true. The lag effect in our crude pricing is going to give us better discounts going into the fourth quarter, and it's going to help our economics. I mean, they're 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 you would tell you is that October generally isn't that much 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 on a gross margin basis, fourth quarter does look better than the third quarter, but it's lag -- it's a lag.

Perfect. Joe, when I'm looking at your guidance, say, the RIN cost for the full year at $500 million to $600 million. This quarter, you have $75 million; second quarter, $125 million; third quarter, $185 million. So you're suggesting that the fourth quarter is still at $115 million to $215 million, given that the RIN cost seems to dropped down to the $0.30 comparing to the $0.80, $0.85 in the second and third quarter. Are we missing something or is that just that you're being conservative?

No. Well, I'll tell you that the numbers 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.

The year -- Paul, this is Mike. The year-to-date number through September is $439 million. So to get to the $500 million -- the bottom end of the range, you're looking at $60 million.

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

Question for you on Meraux. I had seen some press 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. [indiscernible] the crude's back in today. And we're going to be at full rates in about another 2 days. So in terms of forward guidance on throughputs, we're -- Ashley's numbers are fine.

Okay. Good deal.

I just want to be clear. It wasn't, per se, a rupture. We had -- we were doing maintenance work and we had a stopple, and the stopple didn't hold. And that's what happened. So we didn't have a piece of pipe just break this up. We were doing maintenance work, in which we're looking at our procedures in tremendous detail here as to how that could have happened.

Okay, got it. The second question was on the unloading facility at Québec. I'm trying to see if we can kind of help quantify maybe the potential shift in feedstock. Do you have any kind of clarity you could provide or ways to think about maybe the cost of transporting up there via rail and maybe the discounts you're getting? Any kind of color you could provide will be helpful.

Blake, this is Joe. Now you know I can't tell you everything you want to know here, right? But I'll 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 a day of rail crude in September. By later this year, we will be running 50 a day of rail crude. We've got it set up now so we can take 100-car strings, 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 in Western Canada. And the rail cost into Québec is cheaper. So I would tell you, if you wanted 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 like look like right now. So in addition to the rail crudes we've got going in there, then we also then we have the waterborne crudes. And I've said earlier, we're moving [indiscernible] -- 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 Québec refinery. And then, we had a call yesterday with our Canadian guys and discussed the status of Line 9. And it looks like everything's 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've 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 North -- when that line comes up, we'll be running all North American crude, and Québec will back out to foreign barrels.

Blake, this is Bill Klesse, and so this even goes back to Paul's question or 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 on some of that by the costs. But clearly, shipping from the Gulf Coast to Canada is a couple of bucks; the rail, it's in our handout, we have all those rates in there. So I'd say all of this is extremely profitable. On the other side though, the gasoline crack still isn't really that good. Actually, it's crummy. Butane -- 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 with your question, Paul's question -- yes, it's better than it was in the third quarter, but there are things that are negative.

Our next question comes from Ed Westlake from Credit Suisse. Edward Westlake - Crédit Suisse AG, Research Division: Okay. So yes, just coming back to the crude side, I mean, obviously great conditions down in the Gulf at the moment. Are you seeing from, say, some of the medium importers sort of 1.5 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. I mean, how do you think that's going to pan out with the 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.

No, we haven't. They're really priced [indiscernible] index, which is a complicated dollar. So their prices are based on U.S. basis. But do they have better opportunities to move over to Asia and we haven't really...

Historically they have, right?

They always have, yes. Still a lot of barrels that needs to clear to the Gulf Coast to put [ph] in those market. Edward Westlake - Crédit Suisse AG, Research Division: And I mean, I guess 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 the sort of, I guess, the industry expectations, say, a year ago of sort of $2 to $5 as being the sort of right kind of discount to sort of encourage those to move to other markets?

This is Gene, again. When the market gets oversupplied, it's hard to really pick the right number. Why did WTI, the breadth [ph] go to $25 last year? So when it's oversupplied -- so $2 to $5, I mean, to me, fundamentally, is no different than $8. It's just a matter of where the market shakes out. The market is clearly long. It's hard to say what the right number is.

So we think -- we still stay to 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, and 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. Edward Westlake - Crédit Suisse AG, Research Division: 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 is methanol, but a 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're investing at. I mean, Obviously, we know the MLPs trade at the high multiples. But what sort of returns do you think you're getting on your organic logistic investments?

Ed, 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 railcar 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 going -- that asset was going to go into a logistics partnership, where do you put the return? Directionally, they're all beneficial. Most of them are pretty high-return projects, especially because they're bringing advantaged crude to refineries. But giving specific returns by each dock, by each railcar, we're not going to provide. Edward Westlake - Crédit Suisse AG, Research Division: Yes. I'm just fishing to try and help us, say, get an estimate 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 got to be able to load ships. And so some of these projects, like our dock at Corpus Christi, we just say we got to have it. The docks at Saint Charles, building a new dock over there maybe, the dock at 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, very well. But it's hard for us to tell you, as Ashley said, this project yields that, this project yield that. But they're all going to be above cost of capital and they are all going to fit very nicely in this portfolio. Edward Westlake - Crédit Suisse AG, Research Division: I mean, 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 it's not -- we've given you guidance for next year, and that's the guidance we're sticking with.

Our next question comes from Doug Terreson from 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've talked about how it's going to rebound. But 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 compared to 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? And also whether or not there are any other issues that may help to explain some of these recent global trends?

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. But key factors that aren't in a typical indicator are RINs 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 those weren't a factor. Those are probably the biggest ones probably across the entire industry. So -- but any other detail, we'd have to do it one-on-one, because that's [indiscernible] on your model.

And 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, that there is going to be pressure on certain refineries in the world to kind of make room for that. And I think that includes some of the Asian refineries in Japan and Korea and Australia, some of those have been rationalizing. And also in Europe because Europe is going to have to make room for not only the U.S. exports but the new Saudi refinery exports and Europe's only advantage is limited to distillate demand and that could be supplied cheaper from other sources. So we think global margins are off a little bit if you kind of look at past 2011, 2012 margins. '13 margins are a little weak or are definitely weaker as you're moving into the fourth quarter. So I guess we could say that pattern continues to next year. And I don't think margin is 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 it's somewhere you'll get some bounce back, but I think you'll see weaker margins in Europe than we have over the last couple of years.

Our next question comes from Paul Sankey from Deutsche Bank.

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 U.S. demand. I was interested that you've 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 -- less [ph] exports are up this quarter.

Yes. This is Joe, Paul. So economics dictate a lot of our export volume. And so we take into consideration not only the margin that we can get on the barrel that's 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're going to see that be much stronger I think in the fourth quarter. The gasoline exports, we moved most of that volume out of our Corpus Christi refinery, and a lot of it's termed up and went into Mexico and some of it went into South America. But that is part of our business that as we look at it going forward, we're very focused on expanding. And so strategically, we have initiatives that we have underway to try to create additional opportunities for ourselves to move those barrels out. But it wasn't there yet today. So even though we've got capacity to export, you've 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 netbacks and different grades in those different markets. So just -- we're constantly optimizing around that.

But I guess what you're saying is that diesel is great, right? You can export it with the RINs [indiscernible] 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 [ph], but if you look at our operating rates, our operating rates in the whole industry have been -- with the turnarounds that Gene mentioned earlier, have been very good. So operating rates are okay. They've come down some on crude units, but generally they're okay. And so we're making the product slate that maximizes our profit on the back end of the refinery. And so then we have this gasoline. We place it in 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 on those strings.

Yes, I get that and it's...

I know you do.

I think -- I just -- to go back to kind of what Joe said, just to reclarify, the -- can you kind of go over again why there's not more gasoline export, Joe? Sorry, I know you kind of answered. But if you could just totally clarify it for me.

Where [ph] would the next 50,000 barrels of gasoline go at? Would it be a loss or would it be marginal economics? That's basically the question. And...

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

That's right.

And netbacks and shipping.

And Paul, remember, I think we had shipping rates that were very high during the third quarter. I think we were $0.115 a gallon versus like $0.075 in Europe or $0.07 today. So there are a lot of factors that come into play. But again, it's economics.

Let me add a little side conversation here. So we obviously have export capability. So then it turns into either quality or the refinery economics. And as we run our economics in the refinery, basically we're 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 make more gasoline.

Yes. Just to clarify...

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 -- the 193 distillate plus the 91 gasoline, I get obviously to 284. But then I think you said your capacity to export was actually 350 or am I wrong?

I said gasoline, we would say that our gasoline export capabilities, logistically is 225. And logistically, on diesel, it's 325 today. So the point, I guess, Paul, 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. Yes, I think I get it. I think it's all an 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? In terms of export...

No, U.S. RIN.

No, this -- we're talking about the RINs, the cost of RINs. So in the U.S., when we sell product to the U.S., 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 know to take this off-line, but I'm getting there, it's just 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 can add on that?

Yes, Paul. Yes, it was up about $40 million from the prior quarter. And 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 Saint Charles hydrocracker startup. So we had added depreciation from that project.

So that's not going to be an ongoing? That's not -- 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.

Our next question comes from Chi Chow from Macquarie Capital.

I got a question back on the cost advantage crudes. And in your latest presentation, you have a slide showing the Gulf Coast -- well you got -- you have advantage crudes processed by region. And I was just noticing your Gulf Coast capacity, it looks like it's -- first quarter, second quarter this year is around 320,000 -- maybe 325,000 barrels a day. Do you have that same metric for the third quarter?

Let me see -- capacity -- yes, it's about the same. It was a running -- we estimated capacity to process like light crudes was in 2Q, around 280,000, 290,000. We estimate it's up around 310,000 now for third quarter.

Okay. So are you maxed out in the Gulf Coast at this point on the advantage crudes until Corpus and Houston, those projects come on, or are there just more opportunities to kind of tweak the volumes higher in the meantime?

Chi, 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 but -- even beyond these key projects we're looking at.

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

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

In the Gulf?

In the Gulf.

Remember you're displacing medium sours in some of this, though, that we still have better economic [indiscernible] than medium sours. So that's the reason we're only running the 310,000 versus the 400,000 capacities, because we still have better economics on the mediums.

Right. I guess second question back on this RIN issue, Bill, do have any comment on this supposed leaked EPA document? And really, what is the outlook on your end into 2014 and what the mandate might look at. And have you had any discussions with regulators or the administration lately and any feel for how they're talking about next year?

Chi, this is Joe. I think the answer to all your questions is yes. I mean, obviously, the leaked information, along with the other things that the EPA has said, have led to the decline in RIN prices. They recognize clearly the blend wall is an issue and they said they are going to address it. They extended the deadline for compliance from 2013 to June '14. And then the leaked memo comes out, it has of the significant reduction in 2014's statutory levels to what they've proposed in '14. 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 a drop from the mid $1.40 to $0.20 or sub $0.20 today. So if we look out, I mean, the EPA gave us a short-term release, if 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're 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 affects compliance with the RFS. Bill's had many meetings on this in D.C. 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 '14 and hopefully, longer-term, with legislative relief.

Okay. So do you think these legislative actions on the rewrites, I mean, does EPA kind of -- do they just short circuit that effort by just kind of taking the rug out of 2014? And is this just going to be just a year-by-year kind of rolling uncertainty as we go into RFS for 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 then acted within their authority to do what they needed to do for '13, '14, 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 when 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.

Chi, 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 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 is 336,000, 3Q is 346,000. It's mostly light but we're getting some advantaged Canadian heavier stuff, too.

Our next question comes from Allen Good of MorningStar.

I wonder if I could 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 refiner, including yourselves, are betting on maintaining high utilization through exports. As a result, you're building out export capacity. But if we look at the U.S., it seems like the oversupply will be in gasoline. If you think about globally, it seems like Europe will bear the brunt of the refinery closures, and that's not really a gasoline market. So I'm just wondering, where do you 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, you're right, they don't. But they do export a lot of gasoline when they run the refineries full out. So I think when you get the rationalization in Europe, they all reduce their gasoline exports in places like West Africa and Latin America to make room for the U.S. barrels, which have a big cost advantage.

And so -- and then what do you think as far as -- with peers increasing as well, do you think there will be enough of that lost supply from Europe really to accommodate all U.S. refiners who are looking to export more product?

Well, 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 in Europe on LNG, gas -- natural gas. You're pretty much disadvantaged and those are the refineries that will make room for the more competitive refineries.

And gasoline demand in Latin America, you've got population growth, you've got economies growing, you've got increased demand, and you've got operations that, historically, anyway, have not been very good. And Mexico, they have decent operations but structurally, they're short gasoline, and they continue to grow. Venezuela's had significant refinery operating issues in the Caribbean, which have affected gasoline supply, and which I don't if it will 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 U.S. Gulf Coast and the natural resources advantages that we're enjoying there, we're going to be able to continue to be very competitive exporters, not only to Europe but also to Latin America.

Okay, great. And then if I could just come back to capital spending, I guess a couple of years ago, it was assumed once the hydrocrackers were completed, that you'd see capital spending fall? Clearly, you mentioned earlier that the market's 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 will continue and maybe the $3 billion total for capital spending would be a safe run rate over the next few years? Or do you expect you'll extinguish some of these current opportunities over the next 1 or 2 years, where we'll see capital spending maybe fall back down once we get 3 or 4 years out?

Well, we're only giving the guidance for '14. But a big part of the '14 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 '14 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. If I could just, one quick follow-up. I guess share repurchases fell off in the third quarter. It seems like on your run rate for the fourth, you're 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 $3 billion? Or would you look to potentially add to the $3 billion once we get closer to the end or extinguishment of that debt level?

Allen, this is Ashley. We don't have guidance on 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 a recurring dividend. But we won't provide specific guidance.

But just to reiterate what Ashley said in his comments, we spent $675 million buying our shares this year. We raised our dividends. Our dividend's going to approach, I think, $400 million on an annual rate. So that's over $1 billion and we spun off 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.

And our next question comes from Matt Carter-Tracy of Goldman Sachs.

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

Well, on the water there aren't, because we're supplying Quebec on the water today with foreign light sweet crude. So, they certainly wouldn't be on the water. On the rail side, think we're probably going to be maxed out somewhere around 55,000 [ph] barrels a day. But then we're also going to be a shipper on Line 9. And so, those barrels will deliver in -- on the water, but they'll come from Canada. So I would say no.

So Joe said that earlier that once all those projects you just mentioned get finished and we said it on previous calls that the Québec refinery is going to evolve into a North American crude-supplied refinery where it used to be 100% foreign, But you'll still have this economic opportunity because you have the hardware. But over the next year, we're still importing crude into Québec. And we've told you guys in the past, we run Saharan [ph] out of Algeria, CPC [ph]. So that means there's probably some West African thrown in there. So they're running out the whole 240,000 barrels a day or so of our capacity there. For the next year, we'll still be an importer of crude 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 we -- 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 from foreign crude there.

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 the 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.