Valero Energy Corporation (VLO) Q3 2012 Earnings Report, Transcript and Summary

Ashley M. Smith - Vice President of Investor Relations Michael S. Ciskowski - Chief Financial Officer, Principal Accounting Officer and Executive Vice President William R. Klesse - Executive Chairman, Chief Executive Officer, President and Chairman of Executive Committee S. Eugene Edwards - Chief Development Officer and Executive Vice President of Corporate Development & Strategic Planning

Manav Gupta - Morgan Stanley, Research Division Jeffrey A. Dietert - Simmons & Company International, Research Division Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division Kristin Button - Moody's Corporation, Research Division Paul Y. Cheng - Barclays Capital, Research Division Blake Fernandez - Howard Weil Incorporated, Research Division Roger D. Read - Wells Fargo Securities, LLC, Research Division Edward Westlake - Crédit Suisse AG, Research Division Douglas Terreson - ISI Group Inc., Research Division Faisel Khan - Citigroup Inc, Research Division Paul Sankey - Deutsche Bank AG, Research Division Chi Chow - Macquarie Research Harry Mateer - Barclays Capital, Research Division

Welcome to the Valero Energy Corporation Reports Third Quarter 2012 Earnings Conference Call. My name is Christine, and I'll be your operator for today's call. [Operator Instructions] Later, we will conduct a question and answer session. Please note that this conference is being recorded. I will now turn the call over to Ashley Smith. You may begin.

Hey, thank you, Christine. And good morning, welcome to our earnings call. With me today are Bill Klesse, our Chairman and CEO; Mike Ciskowski, our CFO; Gene Edwards, our Chief Development Officer; Kim Bowers, our Executive Vice President and General Counsel and several other members of our 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, feel free to contact me after the call. Before we begin, 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 described in our filings with the SEC. Now, I'll turn the call over to Mike

Thanks, Ashley, and thank you for joining us today. As noted in the release, we reported third quarter 2012 earnings of $674 million or $1.21 per share. This includes an after-tax noncash asset impairment loss of $341 million or $0.62 per share and after-tax severance expense of $41 million or $0.07 per share, primarily related to the Aruba Refinery as described in the earnings release financial tables under Notes D and E. Excluding these 2 items, third quarter earnings were $1.1 billion or $1.90 per share. Operating income was $1.3 billion versus operating income of $2 billion in the third quarter of 2011. Excluding the previously mentioned items, third quarter 2012 operating income was $1.7 billion. The decrease in operating income was mainly due to lower refining margins in the U.S. Gulf Coast, West Coast and Mid-Continent regions. A decline in retail and ethanol margins also contributed to the decrease in operating income. These declines were somewhat offset by significantly higher refining margins in the North Atlantic region. Our third quarter refining throughput margin was $3.12 per barrel, which is a slight decrease versus third quarter 2011 of $13.24 per barrel. The decrease in refining throughput margin was mainly due to lower discounts on crude oils and feedstocks and lower margins for other products, such as petrochemical feedstocks and propane. However, we saw higher margins for gasoline and diesel in all of our regions, and diesel had the highest margins among our major products. Our third quarter 2012 refining throughput volume averaged 2.6 million barrels per day. That was up 8,000 barrels per day from the third quarter of 2011. The increase in throughput volumes was mainly due to the acquisitions of the Pembroke and Meraux refineries in 2011, which was nearly offset by the lack of throughput at Aruba, hurricane-related downtime and slowdowns at our St. Charles, Memphis and Meraux refineries and unplanned downtime at our Meraux refinery, as a result of the crude unit fire in July. The Meraux refinery restarted its crude unit in mid-October. Excluding the Aruba severance expense, refining cash operating expenses in the third quarter of 2012 were $3.72 per barrel, which was higher than the second quarter of 2012 mainly due to higher energy costs and increased maintenance expense. Operating expense though was lower than guidance due to lower than anticipated cost for catalysts than energy. Our retail business reported quarterly operating income of $41 million, which includes a $12 million noncash asset impairment loss, as described in Note E to the financial tables. Retail operating income was $17 million in the U.S. and $24 million in Canada. The rising crude price environment squeezed retail fuel margins in both regions. Fuel volumes declined slightly compared to third quarter 2011 as weak gasoline demand impacted sales. Our plan to separate our retail business and unlock value for our shareholders is moving forward. In October, we submitted our request to the IRS for a private letter ruling on a tax-efficient distribution of our retail business to our shareholders. Later this quarter, we expect to file a registration statement with the SEC. Given the timing of these events, we expect to complete the retail separation late in the first quarter or early second quarter of 2013. Our Ethanol segment reported a $73 million operating loss in the quarter, which was down $180 million from the third quarter of 2011, mainly due to much lower gross margins as high corn prices and excess ethanol inventories squeezed the margins to very low levels. As a result of the low margins, we reduced our ethanol production to average 2.4 million gallons per day in the third quarter of 2012, a decline of nearly 900,000 gallons per day compared to the third quarter of 2011. The end of third quarter, general and administrative expenses, excluding corporate depreciation, were $174 million, which was in line with our guidance. Depreciation and amortization expense was $402 million, and net interest expense was $70 million. The effective tax rate in the third quarter was 46%, but excluding the asset impairment losses and the Aruba severance expense, the tax rate was 35%. Regarding cash flows in the third quarter, capital spending was $784 million, which includes a $75 million of turnaround and catalyst expenditures. We reduced our capital spending guidance for the full year 2012 to approximately 3. -- $3.5 billion versus prior year -- or prior guidance of around $3.6 billion. We expect 2013 capital spending to be $2.5 billion, and that includes approximately $200 million for our retail segment. Also in the third quarter, we paid $97 million in cash dividends to our shareholders. With respect to our balance sheet at the end of September, total debt was $7 billion, cash was $2.5 billion and our debt-to-cap ratio net of cash was 20.6%. At the end of the third quarter, we also had nearly $5.7 billion of additional liquidity available. Our key growth projects continue to move closer to startup. This week, we expect to begin commissioning activities at our Port Arthur hydrocracker project, and this unit should be operational in December. The St. Charles hydrocracker project remains on schedule to be fully operational in the second quarter of 2013. On the macro side, we believe that Valero and other U.S. Gulf Coast refiners have several competitive advantages versus other Atlantic Basin refiners, including low-cost natural gas, increasing access to discounted domestic crude oil and larger, more complex and reliable refineries. These competitive advantages have enabled us to profitably take market share from less competitive Atlantic Basin refiners. This is exemplified by the high utilization rates in PADD 3 refiners and continued solid export demand for U.S. Gulf Coast products. Now, I'll turn it over to Ashley to cover the earnings model assumptions.

Okay. Thanks, Mike. For modeling our fourth quarter operations, you should expect the refinery throughput volumes to fall within the following ranges: the Gulf Coast at 1.45 million to 1.5 million barrels per day, Mid-Continent at 440,000 to 450,000 barrels per day, West Coast at 275,000 to 285,000 barrels per day and North Atlantic at 320,000 to 330,000 barrels per day, which is lower than third quarter due to a plant-wide turnaround at the Pembroke refinery during most of October. Refining cash operating expenses in the fourth quarter are expected to be around $3.85 per barrel. Regarding our ethanol operations in the fourth quarter, we expect total throughput volumes of 2.5 million gallons per day, and operating expenses should average approximately $0.40 per gallon, which includes $0.05 per gallon for noncash costs, such as depreciation and amortization. Also, we expect G&A expense, excluding depreciation to be around $190 million, and net interest expense should be around $70 million. Total depreciation and amortization expense in the fourth quarter should be around $405 million, and our effective tax rate in the fourth quarter should be approximately 36%. Okay, Christine. That concludes our opening remarks. We'll now open the call for questions.

[Operator Instructions] And our first question is from Evan Calio of Morgan Stanley.

This is Manav for Evan today. I had just a couple of quick questions. One was on the West Coast refining margins. They were -- they came in slightly below the indicated margins. Just trying to understand what happened there.

We really didn't have margin guidance, so not sure what to reconcile for you. Maybe we should -- we can talk about it offline with a little more clarity on what you want us to reconcile to.

I'm just trying to understand, because sequentially they were slightly lower, but the gasoline prices were higher in that region. So I'm trying to understand what happened there.

Yes.

As one would be that the branded prices as well as unbranded -- and you would be looking at the spot market prices. So as some of the markets were moving and a lot of that occurred in October, but it did occur some in September, that our average for gasoline products would be less than the spot market, than what we actually saw.

That's a contributing factor. Also some of our feedstock costs, we run a lot of EGO [ph] out there, even ANS. Some of those prices relative to benchmarks may not have kept up, so margins were impacted there, but there's no one key driver.

Okay. And just...

This is really by guess that it was somewhat on the 70-30 split. So that would raise our gas oil cost, as gasoline point of sale.

And one more quick question. In the first quarter of next year, you have pipelines connecting the Permian Basin down to the Gulf Coast, whether it's Permian Express or reversal of Longhorn, so how would your refineries benefit from that?

Well, these are WTI -- this is Gene Edwards. These are WTI-type crudes, sweet crudes and those pipelines come into the Houston area, so we can run those crudes in our Houston refinery along with the Guilford crude or any other crudes that -- such as [ph] sweet crudes in that area. We can also run some of that in our Texas City refinery as well.

Our next question comes from Jeff Dietert of Simmons. Jeffrey A. Dietert - Simmons & Company International, Research Division: You guys provided some capital spending guidance for 2012 a little bit lower, 2013 maybe a little bit higher than previously discussed. Could you talk about opportunities for growth CapEx and maybe the major buckets that you see opportunity, infrastructure, flexibility to use more light crudes and anything else that you might see on the growth CapEx front?

Well, Ashley is looking for some numbers, Jeff. But the guidance that we've given you for '13 has always been $2 billion to $2.5 billion. And so as far as I'm concerned, we're still within our guidance. We've also pointed out that retail spending in that number is about $188 million, I think we rounded to $200 million. So as far as I'm concerned, we're still within our guidance. Now some -- clearly and I've said this, our St. Charles project is what we'd lost about 2 to 3 months from our original schedule. So based on what I gave maybe on the last call, we're on time with that. But from the original schedule, we're behind. So we have some carryover into '13 from that project, and that's largely -- there's $100 million reduction for this year sliding into next year. But basically, I consider us still within our range. And Ashley has some numbers for you.

Yes Jeff, so next year it looks like we'll spend between $950 million and $1 billion on strategic projects. It's distributed across several areas, several segments, but mostly it's in refining. In those strategic buckets, there's some crude expansions and a bit, some flexibility projects. As Bill mentioned, McKee and Port Arthur, Houston, just small spending across several of those, looking at projects that might allow us to get some more throughput through those hydrocrackers, the new ones at St. Charles and Port Arthur, plus Meraux. And there's other various logistics and biodiesel and retail and pipelines of terminals, things like that. Jeffrey A. Dietert - Simmons & Company International, Research Division: Secondly, in shifting Aruba towards a terminal, what do you see profitability looking like as a terminal in 2013? And how does that compare to the cost in Aruba in 2012? How do we think about year-on-year change?

Well, we lost, over the last several quarters, somewhere in the $8 million to $10 million a month in Aruba. And this year we lost over the last year or 2, in the order of, on average around $100 million, $120 million. One year was higher than the other. So we don't usually give that kind of info out, but we've had a loss in Aruba. And we believe that a terminal operation will be a good project for us there. We're still fixing some tanks, fixing the dock, things that we're doing and have been doing. But we expect the business, it'll test out for us in '13. With all the volatility we see in the markets, the forward curve, once it gets into contango in certain products, there's just a lot opportunity to start. And Aruba has very deep water. You can pull a d [ph] right into the docks, so we think it's a good project.

Our next question is from Robert Kessler of TPH. Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: I had 2 questions for you. One is with the near elimination of light crude imports in the Gulf Coast, it begs a question in my mind. And that is ultimately, do you see the capability of loading some Gulf Coast-located light crude on a ship and moving it up to Quebec City and ultimately processing it there? I know it probably wouldn't work at today's spreads, but what sort of logistics might be involved? And what spread, let's say, between LLS and Brent or whatever benchmark you think is appropriate, might you need to make that happen? And then the other question is just if you would, remind me what your thoughts are on buybacks and when you might see a material program there?

On the first question on Quebec, some crude has already moved from the Gulf Coast to Canada, some out of Corpus Christi as well. That's actually where some of the economics work better. Freight cost average is maybe $2 a barrel or a little less, so it's all economic-driven compared as long as you have your license to export into Canada and some has already moved. And this is something that Valero will do, too, as other companies are looking at. We can run in Quebec somewhere in the 85% to 90% of our charge. There could all be basic -- basically light, sweet crude. And today, that's the -- even though it's a Canadian refinery, it runs imported oil, Algerian, CPC, North Sea, West Africa, it runs all those kind of crudes today. So for us, as we look at it, as the crude continues to cover the Gulf Coast, and we're quite convinced that the original premise we had a year or so ago is actually going to happen, there's going to be lots of light, sweet crude on the U.S. Gulf Coast, it's going to be looking for a home. Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: I think some people forget that refinery way up there might have seen the benefit from this, and thanks for that information. Can you tell me, do you guys have any kind of market analysis on what you think the Eastern Coast of Canada, the refineries on the Eastern side of Canada could ultimately take as far as Gulf Coast based light crude?

Well, there's 4 refineries up there, and some run some medium sours as well, Irvin [ph], but really you need to kind of look that up. We would have an opinion, but we know better what we can do. And just to be totally -- so that you understand the whole situation. We expect to take wider crude oil, Syncrude and other crudes from the West as well, moving it into Montréal and then getting it up to the Quebec refineries. So the feedstock slate for our Quebec refinery is going to change. Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Understood. And then buybacks?

Well, I've said all along that we think our stock, and actually, it's the whole refining industry but us in particular, we're undervalued when you sell it at 4x EBITDA. We have these projects coming on that I think separate us from the pack, so that when you -- our 2 hydrocrackers by the second quarter of next year will be major contributors. They are absolutely the right project for the right time. And so we think our stock is undervalued. But if I go to a ranking of -- and this is, I believe, absolutely consistent with what we said in the past, it's always safety and reliability first. We're improving our reliability around the system, and we continue to spend money to do that. Investment-grade rating is absolutely key. We have adequate cash to fund this business. As Mike said in his notes, we ended the quarter with $2.5 billion of cash. We have lots of liquidity, as he also said. We're going to fund our projects through completion here. The Diamond Green Diesel project spills over, and frankly, we will expand both our hydrocrackers pretty much right out of the chute here as we get our permits. We continue to look for excellent investment opportunities. To be honest, some of our shareholders want to see the cash, and some of our shareholders want us to invest in good projects. So we continue to look for that. But we match that up against the comment I started with that our shares are undervalued. So that when we get to returning our cash to the shareholder, we've raised our dividends several times. And I have said that we want to have a yield that's among the highest in our peer group. And we have purchased our stock, we didn't purchase any stock in the third quarter as we've got our retail separation underway here, and we were building some liquidity. But we bought -- last year, we bought 17 million shares and this year, we've already bought 6 million shares. So we've actually demonstrated that as well. And so I think that's pretty well, I think we've been very consistent as to what we were doing. Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Just a quick follow-up. Anything that precludes you from buying back stock between now and the time of the retail spin?

No, there is nothing that does.

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

I've got 2 or 3 quick ones, hopefully. We haven't really seen weight -- weight-heavy differentials in quite a while. We seem to be seeing them right now. I'm wondering if you can talk a little bit about what you're seeing in the market that caused that? And on the same token, if you look at your runs, it looks like you upped your heavy runs this quarter and also your light runs. So a little bit, maybe some color around how those 2 things are interacting. And I've got a couple of quick follow-ups, please.

Doug, this is Gene again. I think what's driving light heavy [indiscernible] has gotten a little bit weaker compared to where we had been. So with this running about $16 discount to Brent, so you've seen all the crudes follow that, including the Maya and the heavy sours. Probably more importantly, the medium sours. Those have been running in the $7 to $8 range discount to Brent over the last month or so, which is good. And WTF [ph] is also cheaper. So you throw all those in there, it's just given us better discounts on medium and heavy sour crudes.

So are you meaning for a change in your slate, Gene, to adjust to that?

Well, we're always optimized, and we run economics every day cargo by cargo, whether we -- sweets or TTT [ph]. LLS is trading about even to Brent. And remember that Brent is before transportation, so LLS is a big discount to Borden [ph] sweets. So we're always optimizing our slate every day because we have a lot flexibility in the system. And so we're just -- like I said, we're taking advantage of all.

Great stuff. So my follow-ups are really 2 strategic questions. Let me group them together and see how best you can, and I just want you to be able to answer them. The first one is, I think though in the past, you've talked backwards and forwards about whether California was actually a core region for you going forward given the regulatory spending. There was a little bit of charter in the market a few weeks back that maybe there was some movement in that regard. I wonder if you could comment on that. And on the same vein, Mike and I had the opportunity to talk a little bit about what was going on in the summertime over the MLPs that were being listed in the form of refining, mainly northern tier. Now we've seen that thing wash out with a fairly substantial multiple uplift for refinery, which I think was a little different than it was though in the summer. So I'm wondering how that might have changed your view around, for example, Ardmore, McKee, some of the high cash-flowing assets and whether that's something you might want to consider down the road? And I'll leave it at those 2, please.

Well, Doug, on California, I have said that we continue to look at our options. We work for the shareholder, and we think that the regulatory environment in California is not constructive to the California economy. It's not constructive to the working person, and it's not constructive to our industry. Whether it's AB32 or whatever regulations we're faced with, but in AB32 particularly, the academics and the extremeness have hijacked the process. And they've made -- they're coming up with regulations that are totally not workable. So we look at our options, and we continue to look at our options. But on the other hand, we do not comment on rumors. On MLPs, our organization is really working on the retail separation. We would still consolidate. See, there is some financial theory here in that we borrow -- borrowing costs are very low. We're not in need of any cash, and so there is a discussion about this from the company that says any funds at the lowest cost. However, in acquisitions, it's clear that the MLP is an excellent acquisitions vehicle, the market clearly likes that approach. And we have some pipelines and turmoils that we can contribute to an MLP. So our strategy is to finish our retail separation, and then as I think Mike probably told you and we've said in the past, that we're going to look for MLP. The third part of your question is on the refining. And clearly, NTI has traded better here, because initially, it did not trade that well. But it is these type of assets, as you know, and as the others on the call know, their high cash flow is, in fact, tied to the WTI, LLS or Brent spread. I mean refining is all about location today. And if you're in the right location, your cash flows are huge. But there is a forward curve or a forward expectation. And so you get into a conversation of what you could actually realize doing that today. We think that would not necessarily result in an advantage to our shareholders.

Could I push you a little bit on the pipeline and terminals, because obviously, new start, kind of, I guess, as all the legacy stuff, what is the appetite and what is the potential scale in terms of current EBITDA that you would associate with those pipelines and terminals because I was under the impression you did not have a whole heck of a lot left.

Well, we can -- we would have somewhere between $50 million and $100 million of EBITDA just dealing straight, like just taking terminals and pipelines. And remember, we are partners with Kinder Morgan on the Parkway pipeline. We have our big pipeline project in Canada, which is just about finished here, and again, ready to start up. So we have assets in our system. But also, we have package and other things that are being dropped in MLPs as well. So we would have -- it would be a small MLP, but it wouldn't be any smaller, I guess, than a couple of the others out there. And we would have the opportunity to drop other assets as we go through the future. So we'll look at it. We've said we were going to look at it, but our focus today is really on the retail separation, because we do believe that adds significant shareholder value. And I might add, we don't think the stock -- our stock reflects that value.

The next question is from Paul Cheng of Barclays.

A number of quick questions. Actually, can you remind me the retail spin of your ethanol facility is going to be included, or it's going to stay with the Valero?

Ethanol segment is going to stay with Valero. That's not part of their planned asset.

The retail spin in the United States -- the retail separation in the United States is the company-operated stores. It's 1,025. And it's the 775 stores, 250 of which we own, and the rest where we control the price or manage the price at the pump in Canada. That is the business that we are separating, including home heating and car block in Canada.

Okay, perfect. Secondly, if I look at the number, next year CapEx is 2.5. And I think Ashley said that strategic, there's probably 90 [ph] to a billion, and 200 is for retail. So that means that the remaining sustaining capital is about 1.3 for the refining and the ethanol together. Is that a reasonable proxy as ongoing sustaining capital, or that next year's particularly high or particularly low?

I've given out in the past with our business, and I would say DD&A runs for us about 1.4 billion. It's going to change a little bit with the hydrocrackers, obviously. It will go up probably 100 million. So then we have retail come out. I think the sustaining capital is really in the 1 5, 1 6, and that's the number that I've given to people. 1 5, 1 6, 1 7 in all the past. Next year, we're finishing some projects, it might be a little lower next year. Turnarounds catalysts are $600 million a year for us. So I think this 1 5 to 1 7, the numbers we've given in the past, are the right numbers.

Bill, the 1 5 to 1 7, is that including retail or not including retail?

Well, sustaining capital, it would include retail in my conversation...

So the retail sustaining is probably 150, 200 right?

It's very small for retail as sustaining capital. It's very small. So I think my range of this 1 5 to 1 7 is a good range for you guys to think of us as sustaining capital for the refining pipeline terminal business that we have.

Very good. Mike, on the North Atlantic, the sequential margin, up about $5 from the second quarter. If I look at the benchmark indicator, whether it's in Europe or in the Northeast market, does not go up by $5. So the question is that, is there any one-off benefit in the North Atlantic we should take into consideration? Or that you think is, really they're running well and is more like a normal run rate that we can base on going forward?

Okay. In the North Atlantic, I think the marketing operations performed fairly well during this period, which would have given it a little bit of margin above that.

Okay. I see. Mike, on -- in the past, as you guys mentioned that you have unplanned downtime, both with [indiscernible] and on penalties in Meraux. You have any kind of cost estimate, opportunity cost estimate related to this downtime in the quarter?

Well, the lost revenue for Meraux, which some spilt into October, but was $53 million. And then it took us about $16 million for the repair.

$16 million?

$16 million for the repair. Now, we did a lot of reliability work while the unit was down. But the lost opportunity was...

$53 million for the crude and then another $13 million just for the hurricane impact.

So between the 2, 66 between the 2 events just for Meraux.

Just from Meraux. How about the Isla [ph] impact on the other facility?

It's -- St. Charles was shut down, and it was about a $34 million impact on gross margin.

From the hurricane.

Yes, from the hurricane.

Okay. And can you guys share with us some, maybe market data about the retail in your only retail network that the gasoline same-store sales in October, how's that looked? And also that -- how's the export so far in October comparing to the third quarter?

So on this retail store sales in the October, how did they look compared to September?

No, comparing to the year ago October on a same store year-over-year.

We're running flat.

Running flat?

To last year.

How about export?

Okay. Now export back to the refining group, exports right now are back up from the third quarter level for diesel. And now in the third quarter, exports were down as the harbors closed for part of the time. On gasoline, they've been about -- they were running at 75,000 barrel a day range.

Okay. And for the hydrocracker, Bill, you had delay, as you say that on maybe 2 or 3 months, is that result in any change in your overall cost estimate, or it's pretty much still about the same?

No, it has changed our cost estimate. And again, these are numbers -- they're not changed, I think, from when I've seen -- saw you. But at our Port Arthur, we still expect to underrun that project. But at St. Charles, we are overrunning the project. And so on total, they're on budget, when you add them both together, very close to being on budget. But clearly, the delay at St. Charles is costing us additional money. Now, all I say to you is for Valero -- I know Exxon and these guys do big projects. For Valero, these are huge projects for us, and our people are managing these pretty darn gone well. But we're just a few months behind.

Two final questions. One, do have any committed to the Enbridge Line 9 reversal to ship barrel, so that you can take it from there, from Montréal up into Quebec City?

Well, the answer is yes, we do, assuming they can get their permits to reverse the pipeline into Montréal, and this was why I added that to the other question earlier. But we have a commitment to ship on that line along with Suncor.

Bill, can you share with us how big is that commitment?

Petro Canada.

Okay. Final one. On the hydrocracker, I guess that with the dividend growth, the next dividend increase or reconsideration by the board, do we need to wait until the hydrocracker, both of them come on stream or that even after Port Arthur will come on stream, you will feel more confident about your cash flow and would be able to relook at your regular dividend, given I think a lot of your loan accounts perhaps that may be more in kind [indiscernible] back of a dividend than the share buyback.

Right now on the dividend, management will have a recommendation either to hold it or stay the same but it is a board item. It will go through our forecast with our board. Our hydrocrackers, honest, they're not up and running yet but those are, as you properly stated, are significant. And so this will be a board discussion.

Is that discussion going to be, say, have to wait until after both of them come on stream or even after one of them come on stream that we'll have that discussion already?

Paul, I respect your question. I understand what you're asking, but I'm going to answer you that you're not going to be satisfied. And what I'm going to say is we as management will have a recommendation for our board, and we will discuss that it the board meeting. We want a dividend that we can sustain, and we also want a dividend that's going to yield, as I said, the highest among our peers. And we'll look at that as well as my other comment where we think our stock is undervalued. So I am just going to say to you that it's a board item and it will be discussed.

Our next question is from Blake Fernandez of Howard Weil.

I had 2 questions for you. One was on the Retail. If I understood correctly, you were previously evaluating either a spin or a sale. It sounds like if I'm reading correctly, you've eliminated the sale option and now just simply pursuing the spin, is that correct?

That is not correct. We are pursuing a separation, but our board has only authorized us to do the analysis around this. I know we used the words that things are moving forward, but we do not even have board approval for a separation. We have board approval to look at this, and we all realize that there's a shareholder value accretion that we've spoken about. But we are going through here to make sure that we maximize shareholder value and at the same time, treat the business and our people correctly as well.

Got it. Okay. And then the second was on M&A. I guess it's kind of a twofold question. One, obviously, Murphy seems to be a little bit more aggressive in exiting the R&M business, and it's always been, I guess, envisioned that Valero is a natural buyer of Milford Haven. Just curious if you have any thoughts there. And then secondly, just from a broader M&A standpoint, now that Texas City is off the market and Alliance [ph] has been removed, it seems like most of the major assets have been kind of plucked off at this point. I'm just curious, Valero, you've been historically fairly active on the acquisition front, is it fair to think that we kind of move away from that and more just to a free cash flow generator?

Well, there's a lot of issues there, Blake. As far as specific assets, whether it's Murphy, Milford Haven or other things that are in the market, we tend to look at these acquisitions, are they going to integrate with our system? That's why we like the Meraux, as it integrated with St. Charles and frankly, our other the Gulf Coast plants. We're of the mind in the U.S. that demand is not going to grow certainly for gasoline. Maybe there's some bounce if people get back to work but long term, gasoline is not growing. Diesel will have some growth, but it still hasn't recovered from the great recession, and it will be years before it does. So whatever we tend to look at, we're looking at in a way the Atlantic Basin and being able to be a stronger competitor in the export business. So all the things that we look at, we want to be able to say at the end of the day that we've been able to integrate this and actually are lowering the cost from the womb to the tomb. So we continue to look, and at least our experience here would be that other assets will come to the market because the refining industry is going to continue to consolidate the United States and Western Europe. There's just no doubt in my mind about that. So we'll continue to look. So I would not say that we're not an active player, but we are after things that make us more competitive as we have to deal in the export market.

Our next question is from Roger Read of Wells Fargo.

Just to, I guess, follow up a little bit on the export and maybe talk a little bit about global capacity you see on the horizon in '13. If I understood correctly 75,000 barrels a day of gasoline in Q3, I didn't catch the distillate number, but what do you see is the capability to grow that in '13? And then, what are you going to be pushing against in terms of identified global growth that you may be pushing back, could impact margins, et cetera?

Well, our exports in the third quarter were about 118,000 on diesel just so you have -- 118,000 barrels a day. That was actually down from where we've been averaging, which is somewhere just on average 175,000 barrels a day. Now, and our industry then has been exporting 1 million barrels a day of diesel. And somewhere in the 400,000 to 500,000 barrels -- 300,000 to 500,000 barrels a day of gasoline. So Valero is somewhere in the range of 20% or so of the export business in that range. Now there is capacity that comes into the market. Refining capacity is being built. Also the world demand is going up. We still expect for next year because you were talking about '13, that the world will increase, we think maybe 1 to 1.2 million barrels a day of consumption, so it can absorb some of this additional capacity. The U.S. is the most economic place here, low natural gas costs, some discounts or at least parity with world prices for sweet crude, and then we also have very fine operating people. So we think we can compete in the business and the business grows. It doesn't change my statement though that I've made in the past, and that is Western Europe is long refining for sure. And without exports, the United States is long refining for sure. So things will continue to rationalize in those markets going forward, but we think we can compete, one as a company and two as an industry. And the markets continue to grow. The third thing I would add to that conversation is all the Brazilian refineries that you read so much about, they're late and they're costing them a lot more. One is getting done here but the others are -- they're going to spend a huge amount of money if they actually proceed with them. The Venezuelan refineries are in disarray. And certainly, the debate continues as to what Mexico does, and the facts are the Mexican economies grow and the Brazilian economies are growing. So for companies like us located on the Gulf Coast, we think we can get into these markets and be doggone competitive. And Europe continues to be systemically short diesel on an annual basis.

Okay. So as a follow-up to that, where do you think your export volumes can go next year? I mean obviously you have the hydrocrackers coming online, which are going to grow volumes for you. Nobody I think believes the U.S. is going to be in a robust growth mode next year. So I mean, the exports are very much the outlet. Where are you in terms of actual keyside capacity and ability to roll this out?

That's a general -- and that's very fair question. It's a general statement because Motivo [ph] will eventually be back as well. And so Europe will basically take somewhere around half of our diesel exports, and the rest of the diesel exports are going to the Caribbean and other places. On gasoline, primarily Mexico, Colombia, Brazil and you may see a cargo or 2 go over to West Africa. Our Quebec refinery, just as a little side note, has been able to export diesel into New York Harbor. So -- but clearly, it's the same places as they continue to grow. Reaching out further, they would all be ad hoc. But remember, the Gulf Coast market is extremely liquid market.

Absolutely. Okay. And then my last question for you, on ethanol, obviously, a really tough quarter. Looking at the volumes you ran in the third quarter and what you're indicating as reasonable volumes for the fourth quarter, what changes, if anything, versus the fairly significant loss we saw in the third quarter as we look at the fourth? I mean, if volumes are going to be slightly higher, is that an indication that there's a little bit better margin story here than what we've been seeing?

This is Gene again. We've got good margins in probably 5 of our plants. We have 2 plants that are basically down. We're keeping the enzymes active, so we'll start up a couple of days a month on those, but there's 2 of them down and there's 3 plants that are cut back. So we're running 2.4, 2.5 million gallons a day of capacity of about 3.6. So we're running probably about right at 2/3 utilization. So we see margins improve. We had a big loss in third quarter. We're about breakeven on an EBITDA basis now with the plants on a consolidated basis, but it's still not nearly as good as it was last year in the fourth quarter. And inventories are still basically at 17.3 million barrels, which are up about 1.5 million barrels from last year. So until we work that off, I don't see that we're going to get a big pop in margins. But we did draw about 204,000 barrels a day last week. So if we keep drawing at that pace, in a month or 2, we can claim some of this off, so it just depends on the demand. Imports have been the big factor. You don't have a lot of imports from Brazil recently. They've announced they're going to go from 20% of their gasoline pool to 25%. I think we'll see some of those imports slow down a little bit and then plus they're at the end of their harvest season for sugar. So I think that should diminish. So I think the market will continue to clean itself up. It's just taking longer than it normally has.

And for us, corn prices have stabilized where they were moving around so much. They've kind of stabilized here at the $7.40 a bushel area.

Okay. And just a little follow-up on that. How quickly can you react within your ethanol plants to those market conditions changing? Are you as agile as in refining is literally a daily basis change or, any help along those lines on your flexibility?

Yes, it's pretty quick. If the margin were to improve next week, we can source more corn. The plants that are running obviously just seems to start increasing right away. And then the other 2 plants that have been down, we have been doing these monthly refreshes to keep the enzymes active, so you can get them started up on a short notice. We'll probably decide, going into the winter though you notice when you get colder weather there, do we -- if the plant is down, that's a big problem with a lot of water in the system, so we'll probably have to make a decision in the next month or so where we're going to try to start up here in the winter or just leave those 2 plants down throughout the rest of the winter. We'll be watching the market closely on that.

Our next question is from Rakesh Advani of Credit Suisse. Edward Westlake - Crédit Suisse AG, Research Division: It's Ed Westlake actually. So you mentioned an interesting number, which is $2 to get crude from, I guess, the Gulf up to your Canadian facilities. That seems low for a Jones Act ship. Is there something funny going on? And maybe talk to how much crude you could move with the existing shipping that's available on that route. And then I have a follow-on question.

Well, Ed, I'm surprised with you on the Jones Act ship. Canada is not the United States. It's still part of the British Commonwealth though. Edward Westlake - Crédit Suisse AG, Research Division: Right. Yes, indeed. And my wife is Canadian, so I should know that. So effectively you use just regular shipping, and that's why it's so cheap. Do you -- would you have a number if you had to ship crude up to -- do you think if the industry had to ship crude up to the East Coast?

Well, sure it would be -- it's 3x. So it's very, very... Go ahead, Gene.

Well, Phillips has announced something. It was in the press that they're shipping their barrels up to their neighbor refinery and I think they got a deal of $4.50 a barrel or so. Edward Westlake - Crédit Suisse AG, Research Division: Right. That's helpful. And then the follow-on question is around sort of the advantage position you have even in the Gulf, I think around 900,000 barrels a day capacity in Texas. Obviously, with the Eagle Ford and the Permian growing quickly, those refineries are kind of in the line of fire of that crude growth whereas it probably cost a little bit more and then maybe some bottlenecks to get crude over to the Louisiana refineries. Do you have any sort of numbers for us that could help in terms of quantifying how much of a dollar a barrel advantage you have in West Texas?

Well, I would say to you, Ed, Gene and I will try to answer you. It's probably $1. Once you put it on the ship, you got to load it, you have all these costs to get on a ship. So if you assume sweet crude oil, say, from Corpus Christi to Meraux, I would say you'd have at least $1 dollar advantage at Corpus.

Yes, I think it's $1 or $2. And furthermore, Houston and Corpus are probably going to be a similar parity. And what's going to clear the Houston to St. James market is going to be the SOHO line, which is going to be their quoted [indiscernible], $2 a barrel on that. So I think you got at least $1 a barrel to Houston, and probably 2 barrels -- $2 for Corpus Christi kind of the memo. And then as you get up to McKee, obviously the numbers get even more discounted because of the -- you've got to clear the seaway pipeline tariff, or the long-haul reversal or these type of tariffs too, and is an advantage for McKee and our board. Edward Westlake - Crédit Suisse AG, Research Division: Yes, so generally, you'd say that West Texas is about $2 discount to LLS in Louisiana and then so maybe some additional advantages for being initial off takers for some of the crude providers from the Permian and Eagle Ford?

Now we want to be clear on this. Once you get it to the water, Gene was speaking, if you have crude in West Texas, you have that tariff to get it to Houston or Cushing and then Cushing to Houston. So then that tariff on these pipelines being built. I thought we were answering your question as moving it on the Gulf Coast. You have it already in Eagle Ford and Corpus Christi or you have a crude in Houston. And those are the numbers Gene was giving you. If you're talking about Midland or Cushing, you have to incur that tariff as well. Edward Westlake - Crédit Suisse AG, Research Division: Yes, I know. I was just talking about moving stuff along the Gulf, so it's been very helpful.

A follow-up to that is we're talking to our crude traders about that, taking crude from Corpus to Louisiana by U.S. flag is about the $2 a barrel, is about the same as foreign flags into Canada at $2 barrel. Kind of amazing.

Our next question is from Doug Terreson of ISI.

Bill, the delivered cost advantage for U.S. exporters is pretty clear, but just to clarify something you said a minute ago, did you say that your exports were a little weaker recently? And if I heard that correctly, were there regional markets that were taking less product and why or was it something else?

In the third quarter, our distillate exports were down from second and down from what we expect in the fourth. And that had to do with the arb, it had to do with inventories. There was just a lot of reasons.

There's also the hurricane outage on the Gulf Coast.

And Gene is right, we had the hurricane on the Gulf Coast as well. So that -- and that's actually -- and what happened is the domestic markets were very strong so the arb wasn't open. And we run on economics.

High-quality problem. And then also, in California, you've been very consistent over the years with your views on the regulatory regime. And when you make your strategic assessment on your positions out there, is it the compliance cost for the new standards in '13 or '15 that represent the greatest concern or is it something more broad? And either way, is there an order of magnitude that you can give us as it relates to the cost structure that would be likely related to regulations in California?

Well, it's an excellent question. Actually, this AB32 -- so the cap and trade program that's starting now and the low carbon fuels that tend to restrict which types of crude you can run, these programs are all starting. So the basic issue on low profitability in the West Coast has actually been crude sourcing, so do people have an advantage crude source. And secondly, we still have over 10% unemployment now in California. California is 2/3 of the pack. So when you start to look at this, demand is down, and there's too much refining capacity. So you see this, Doug, and as the others on the call see, when there's an operating issue in California, the market quickly balances and margins improve. And then when everybody's back and running, we all tend to run down to cash cost. And that's what as you would imagine, that's what happens, but my concern and the concern of Valero, and our management team here is longer term, the policies that are going -- being discussed, the way they're talking about implementing them is bad, as I said earlier, for people, for business and certainly for our industry. So that's a longer term decision [ph]. The shorter term is really just basic supply and demand and a very sluggish economy in the West Coast.

Our next question is from Faisel Khan of Citigroup.

Just a quick question on the Eastern, the Northeast market, you saw a pretty wide basis differential in the Northeast this last quarter. And I'm just trying to think around exactly how much product you guys are pushing into the Northeast? You talked about the arb kind of closing, but I wonder if you can elaborate a little bit more in terms of how much gasoline you were pushing into the Northeast to take advantage of that and wide basis differential that we saw?

I don't think we would have that number. Remember, we tend to sell in the Gulf Coast markets and into the Southeast. And then Canada services it's local market and it's been able, as I said a few minutes ago, to put some barrels into New York Harbor. But we're not per se pushing anything domestically into the East Coast. Now from Pembroke, we export to the U.S. East Coast. And I don't think I know that number.

The only thing I'd add, we do sell to those people that ship on Colonial pipeline and maybe are taking our barrels to the East Coast, and then it's after we've already relinquished control.

Okay. Understood. You're selling the barrels to the Gulf Coast and somebody else is moving those barrels farther north and take advantage of that differential to some degree?

They have pipelines based on pipelines, so I guess that's right. Now we would have gotten advantage of it for Pembroke.

Our next question is from Paul Sankey of Deutsche Bank.

Bill, on the hydrocrackers, when will be the first quarter for each hydrocracker of complete uptime, if you will? When do we now expect them to be running at full operations?

Okay, Port Arthur, the full quarter will be the first quarter of '13.

So that will be a full quarter?

Full quarter. We expect to be up in December. And at St. Charles, to answer your question, the first full quarter might be the third quarter. But we expect to be up in April, okay? But I'm answering your question, full quarter, it will be the third quarter of St. Charles.

Right. And then...

Now if things go a little better, we could have the second quarter, but as I've said and I don't know when you joined the call, these are very large projects for us, and we're getting them done and we're getting them done safely.

Yes. And you've been pretty clear with the guidance on what they'll make based on some fairly conservative assumptions. Could you just remind me what those would be if the guidance still remains the same? What your expectation for let's say the quarterly or annual earnings would be for each unit for each project? And then if you could also roll that forward if possible into what it would be making in the current environment, that would be great.

Actually, we may have some numbers. But we've been typically have been giving you guidance, we give you all the assumptions in our appendix of our presentations, but it's about $1 billion worth of EBITDA. And we gave you all the assumptions. And you can see it when we have a case, I think it was $1.2 billion. We had another one, and I don't know what it would be today, but it's $1 billion of EBITDA. And we think they're going to contribute over $1 dollar share to earnings. Remember, it's natural gas, the hydrogen to distillates primarily, and we have a good distillate cracker as well.

Obviously the main thing is just to get them running.

That we all agree, and we're going to do it in a very orderly manner.

Surely. Forgive me, do you increase your CapEx guidance for next year? I know it's sort of a Mickey Mouse question, but could you just confirm what's on the CapEx numbers? I don't have full access to information yet.

Paul, we did, in my opinion, as we got the question earlier, we did not increase our guidance. I've said all along $2 billion to $2.5 billion. What we're doing here is saying we're at $2.5 billion. In that $2.5 billion is $188 million that has to do with retail. Assuming that we proceed with the separation of Retail, and Mike we're saying if that all happens, it's a second quarter event, late first quarter, early second quarter, then that amount of the capital would come down pro rata here for spending.

Yes, and then you've kicked off -- I was listening of course, so you've kicked around some numbers as for what we could assume -- I know it's early but for 2014, assuming that you're going to basically pursue a strategy now more oriented towards capital limitation and more towards cash return to shareholders.

Well, I would say that in 2013, we've given you the guidance, and it's been consistent with what we've been saying here for the last 6 months. We've said that we want to have a dividend yield that's among the highest with our peer group. But I'm not giving any guidance for 2014.

Okay. Just an observation that Sandy I think is going to have a pretty significant demand impact. As you can imagine, there's no traffic lights right now on Manhattan, which obviously conjures up a nightmarish image but at the same time there's so few cars around that is actually more or less safe to drive, but I guess again you made some observations on your best guess of what the impact will be, right?

Well, I don't think we would know any more than you. You're very astute at this. Obviously, the refineries either shut down or reduce significantly. But the facts are demand is going to be way off as well. And so I don't think we can -- we would have any better insight at this point than you do. But obviously, demand is off as well as the refineries. I will say this, at least reading some of the commentary and this is good for people and everything, that some of the refineries did not incur any damage.

Yes, I mean, what I would think is that because of the PADD 1 is essentially import-dependent from other places that the demand impact is more important than the supply impact, which doesn't seem that bad.

That's correct. And Paul reminds me, for all of you on the call here with this Hurricane Sandy, we thank you all for calling in, and we hope you didn't incur any damage or your loved ones or families. Hope everything is okay as you get your power back and everything else that goes with you.

Our next question is from Chi Chow of Macquarie Capital.

Back on the Retail separation. Bill, in the event of a spinoff to shareholders, does Valero intend to retain any interest in that new Retail entity?

We are working all options as you would expect us to. If we did, it would be in the financing vein. But we are, today, looking at cases of complete separation, but we have financing options.

Okay. I guess there's some chatter from the credit agencies when you made the announcement on possible changes to the ratings for Valero. With the separation of Retail, are you concerned about that at all? Have you had further discussions with the agencies? Can you talk a little bit about that?

Sure. Yes, one of the agencies did have some concern. And as we get our case solidified here, we'll go in and visit with them and show them our numbers. And we ended the quarter with $2.5 billion of cash, and so I think we're very strong financially. Our net debt to cap is 20%. But we're going to go in and we'll show them our numbers and we'll have the discussion that you would expect us to have.

Okay. In the event of any changes, does that change your position on buybacks going forward?

Well, I don't know the answer to the first question, but we think our stock is undervalued. But I've also consistently, and Mike has said this as well and Ashley, we believe with our size and the way we deal with our suppliers that having an investment-grade debt rating is extremely important to our business.

Right. Okay. And then on your comments on the growth CapEx, you mentioned you've got some projects looking at increasing crude throughput capacity. Do have any details on the specific plans and incremental capacity you're contemplating?

No. But as you would -- these would only be in situations where we're out of balance with feedstocks. So that we -- for instance in Corpus Christi, when you look at our capacity relative to our crude -- conversion capacity relative to our crude capacity, it's out of balance. And yet now we're in a world where there's a lot more crude oil production coming at us locally that's advantaged. Instead of buying imported feedstocks we need to be looking at generating our own feedstocks. So we have quite a study going on, for instance, at Corpus Christi and our Houston Refinery, where at the Houston Refinery we have a very large cat cracker and yet, we don't have a lot of crude capacity. So these are the things that tie to our whole strategy statement that I spoke about earlier where we look at things that continue to, in the essence, lower our overall cost to produce from the womb to the tomb. And those are the kind things we're looking at. Now at McKee, we've talked about it for about 2 years, we're getting closer to getting some of these permits, but we've said we wanted to expand McKee, and that's been out there. I think you guys are tired of hearing me talk about it. But as soon as -- we have -- we've broken the project into 2 pieces. There's a energy project but there is a crude expansion piece. And we do not have the permit for the crude expansion piece, and it's turned into perpetuity.

Our next question is from Harry Mateer of Barclays.

It sounds like you think your financial leverage is at an appropriate level, so do you see scope for further debt reduction? And I guess related to that, how should we be thinking about the, I guess, $480 million of maturities in the first half of next year? Is that -- are you thinking that's a use of cash or more like it would be refinanced?

No, we -- our plan today would be to take out the $480 million. Mike? $180 million in January, $300 million in June, July. And our plan today is to take it out. That will take our debt down -- our long-term debt down to $6.5 billion to date. And yes, we'll be very strong financially, but that is our plan for that specific model. Then you asked general debt. We do not have any other debt that we find economic to call or to redeem. And then in 2014, we only have $200 million of debt that is due. So in our particular case, we do not have debt that would go out and retire economically. We do $480 million and '14, we do the $200 million, but that's where we are.

And our next question is a follow-up from Doug Leggate of Bank of America.

Sorry, guys, for the follow-up. It's a very quick one, Bill. I wanted to come back to AB32. I know it's a bit of a thorn on your side. But in the event that you have to incur meaningful capital expenditure, at what point would you have to start implementing those projects? In other words, how early before 2020 does this actually become an issue for spending? Now if you could quantify it, that would really be appreciated.

Okay. I'm going to answer you, Doug, that we are all whispering here. There's no capital per se. Now part of the regulation is 1/3 of your power cost is going to come from renewables and -- in 2020. And our cost in California today for power is $0.12 per kilowatt, and that's like 3x the cost at McKee. And as you go to these renewables, and this would be at Wilmington, so L.A., as you go toward this direction, our power cost will increase more because renewables are not economic. And so we have some options to generate our own power and are looking at that project. But as a philosophy, right now, Valero is very reluctant to spend any capital in California. The other piece of this, to give you the whole 9 yards, we generate hydrogen at our Benicia Refinery, and the facts are we could build another hydrogen plant there, that would be $200 million to $300 million and would reduce our carbon footprint. But again, I would say those are out in the future year because quite frankly, these rules aren't even set yet. And at least some people in California are at least -- are now starting to talk about the financial impact this is going to have in the state on everybody. So I think some of it remains to be seen but generally speaking, there are no capital. There are expenditures if you have to start paying for tailpipe, carbon and certainly our stationary source. And I don't mind saying, I think the last number we have, our California stationary source is like 3.7 million metric tons a year. So you can start figuring out those kind of numbers as well. And all it's going to do is we're going to pass it through.

We have no further questions at this time. So I'll now turn the call back over to Ashley Smith.

So let me just say to everybody, good to know that a lot of you on the East Coast have issues, so thank you for making an effort to join our call. And as I said earlier, we hope that you have not incurred too much damage to your home or any of your friends or your loved ones.

Yes. Thanks, Bill. Yes, we wish all you guys in the Northeast a safe and speedy recovery, back to your normal situation. And thank you for listening to the call. If you have any questions or follow-up, just call the IR department. Thank you very much.

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