Valero Energy Corporation (VLO) Q2 2011 Earnings Report, Transcript and Summary

Jean Bernier - Executive Vice President of Corporate Communications, Information Services and Supply Chain Management Michael Ciskowski - Chief Financial Officer, Principal Accounting Officer and Executive Vice President Clay Killinger - Senior Vice President and Controller Joseph Gorder - Chief Commercial Officer and Executive Vice President of Marketing & Supply S. Edwards - Chief Development Officer and Executive Vice President of Corporate Development & Strategic Planning Lane Riggs - Senior Vice President of Refining Operations William Klesse - Executive Chairman, Chief Executive Officer, President and Chairman of Executive Committee Ashley Smith - Vice President of Investor Relations

Edward Westlake - Crédit Suisse AG Jeffrey Dietert - Simmons & Company Evan Calio - Morgan Stanley Mark Gilman - The Benchmark Company, LLC Paul Cheng Douglas Leggate - BofA Merrill Lynch Doug Terreson - ISI Group Inc. Cory Garcia - Raymond James & Associates, Inc. Chi Chow - Macquarie Research Blake Fernandez - Howard Weil Incorporated

Welcome to the Valero Energy Corporation's Second Quarter 2011 Earnings Release Conference Call. My name is John, and I'll be your operator for today's call. [Operator Instructions] Please note that this conference is being recorded. I will now turn the call over to Mr. Ashley Smith, Vice President, Investor Relations. Mr. Smith, you may begin.

Okay, thank you, John, and good morning and welcome to Valero Energy's Second Quarter 2011 Earnings Conference Call. With me today are Bill Klesse, our Chairman and CEO; Mike Ciskowski, our CFO; Gene Edwards, our Chief Development Officer; Joe Gorder, our Chief Commercial Officer; Kim Bowers, EVP and General Counsel; and Jean Bernier, EVP and President of Ultramar. If you have not received our 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 about reviewing these tables, please feel free to contact me after the call. Before we get started, I would like to direct your attention to the forward-looking statement disclaimer contained in the press release. In summary, it says that statements in the press release and on this conference call that state the company's or management's expectations or predictions of the future, are forward-looking statements intended to be covered by the Safe Harbor provisions under federal securities laws. There are many factors that can cause actual results to differ from our expectations, including those we've 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 second quarter 2011 net income attributable to Valero's stockholders from continuing operations of $745 million or $1.30 per share. Our second quarter 2011 operating income was $1.3 billion versus operating income of $904 million in the second quarter of 2010. The second quarter refining throughput margin was $11.41 per barrel, which is an increase of $1.84 per barrel over the second quarter of '10 and our highest second quarter margin in nearly 3 years. The increase in throughput margins compared to the second quarter of '10 was due to higher margins for gasoline and diesel, plus wider discounts for heavy-sour crude oils on the Gulf Coast and light-sweet crude oils in the Mid-Continent. One of the drivers of our year-over-year gain in throughput margin was the increase in gasoline and diesel margins. For example, the Gulf Coast gasoline margin per barrel versus LLS increased to 29% from $7.97 in the second quarter of '10 to $10.26 in the second quarter of '11. Looking at the Gulf Coast ULSD versus LLS, margins per barrel increased 16% from $9.88 in the second quarter of 2010 to $11.49 in the second quarter of 2011. So far in the third quarter, margins have moved significantly higher to average around $13 per barrel for gasoline and $16.50 per barrel for ULSD. Another driver for our margin gain over last year was crude oil discounts. The Maya heavy-sour crude oil discount versus LLS increased to 21% from $12 in the second quarter of 2010 to $14.58 per barrel in the second quarter of 2011. The Maya discount has narrowed some in the third quarter with the July average down to around $12 per barrel. An additional benefit for Valero came from WTI-type and Eagle Ford crudes pricing at a substantial discount to LLS. The WTI discount to LLS increased more than $13 per barrel from $2.26 in the second quarter of 2010 to $15.47 in the second quarter of 2011. The discount helped our McKee, Ardmore and Three Rivers refineries where their crude oil is priced at or below WTI. In the third quarter, the WTI discount to LLS has continued to widen with the July average of just above $16 per barrel. As noted in the release, we are increasing the use of discounted Eagle Ford crude in our system. During the second quarter, we processed an average of 37,000 barrels per day of Eagle Ford, an increase of 12,000 barrels per day over the first quarter. This crude replaced expensive waterborne sweet crudes saving around $16 per barrel in the second quarter. We are continuing to look for additional ways to use more of this discounted crude. We plan to process 25,000 barrels per day of Eagle Ford crude at our Corpus Christi refinery during the third quarter and our Three Rivers refinery should have the ability to process nearly 60,000 barrels per day of Eagle Ford crude by the end of this year. Continuing with other items, our second quarter 2011 refinery throughput volume averaged to 2.3 million barrels per day; that was up 136,000 barrels per day from the second quarter of '10. The increase in throughput volumes was primarily due to the restart of operations at the Aruba refinery. Refining cash operating expenses in the second quarter of 2011 were $3.86 per barrel, which was higher than guidance due to the higher than expected maintenance, catalyst and chemical costs. Our Retail segment reported a record high for a second quarter with $135 million of operating income, mainly attributable to stronger retail fuel margins. U.S. retail had $87 million of operating income in the second quarter and the Canadian retail operation earned $48 million of operating income in the second quarter, which was its highest quarter on record. Our Ethanol segment earned $64 million of operating income in the second quarter, which was up $20 million from the first quarter of 2011 and up $29 million from the second quarter of last year on higher gross margins. Also in the second quarter, we achieved our highest ever quarterly production rate at 3.4 million gallons per day. In the second quarter, general and administrative expenses, excluding corporate depreciation, were $151 million; depreciation and amortization expense was $386 million; net interest expense was $107 million and the effective tax rate on our continuing operations in the second quarter was 37.6%. Regarding cash flows in the second quarter, capital spending was $664 million, which includes $133 million of turnaround and catalyst expenditures and we paid the $29 million in dividends. Also in the second quarter, we repaid $208 million in maturing debt and spent $37 million to acquire a terminal and pipelines in eastern Kentucky. With respect to our balance sheet at the end of June, total debt was $7.6 billion, cash was $4.1 billion and our debt to capitalization ratio, net of cash, was 18%. At the end of the second quarter, we also had approximately -- or we had $4.1 billion of additional liquidity available. We remain focused on our strategic priorities. In addition to making progress on our cost savings goal, we progressed on key investments at our St. Charles and Memphis refineries and our hydrocracker and hydrogen projects remain on track to complete in 2012. We also look forward to the closing on our acquisition of the Pembroke refinery and the marketing and logistics assets in the U.K. and Ireland on August 1. In conclusion, Valero is in great financial position with plenty of liquidity and investment-grade credit rating. Going forward, we have substantial potential for earnings growth with improved refining margins, the Pembroke acquisition and the expectation of significant contributions from our economic growth projects. Now I'll turn it over to Ashley to cover the earnings model subjects.

Okay, thanks, Mike. For modeling our third quarter operations, you should expect refinery throughput volumes to fall within the following ranges: the Gulf Coast at 1.42 million to 1.46 million barrels per day: Mid-Continent at 420,000 to 430,000 barrels per day: the West Coast at 270,000 to 280,000 barrels per day: and Northeast with Québec only at 200,000 to 210,000 barrels per day. After we close on the Pembroke acquisition, our Northeast region will be combined with -- it will be changed to North Atlantic region and the Pembroke refinery will be combined into that region with the Québec refinery. And we expect throughputs for the third quarter to average between 370, 000 and 380,000 barrels per day. Refining cash operating expenses are expected to be around $3.80 per barrel across our system in the third quarter. Regarding our ethanol operations in the third quarter, we expect total throughput volumes of 3.3 million gallons per day and operating expenses should average approximately $0.37 per gallon, which includes $0.03 per gallon for non-cash costs such as depreciation and amortization. With respect to some of the other items for the third quarter, we expect G&A expense, excluding depreciation, to be around $175 million; net interest expense should be around $95 million; total depreciation and amortization expense should be around $390 million; and our effective tax rate should be approximately 37%. We will now open the call for questions.

[Operator Instructions] And our first question comes from Ed Westlake from Credit Suisse. Edward Westlake - Crédit Suisse AG: Just a quick question. I guess in Q1, there were some one-offs and there was also the hedge and you add that back and all calculation was up to just under $1 of earnings. And then in Q2, you got to $1.30 in a stronger macro environment. So I'm just wondering, how -- were you disappointed with the level of Q2 earnings? Or is Q2, do you think, a good expectation as a base to go forward given some of the volatility we've had in Q1 and Q2 in terms of EPS estimates?

I think we were pleased with the results. We'd always like to have higher results but if you look at our capture rates given the market environment, we captured right in line with historical averages or we beat those averages in most regions. Costs were a little higher than expected, but not too much. So all in all, I think it's a fair representation of what we can achieve in this market environment. Edward Westlake - Crédit Suisse AG: And then my second question is more of a question around as we get closer to the EBITDA increases that should come with the investments that you're making, particularly in some of the hydrocrackers, can you talk about whether you're going to give some of that cash back to shareholders in terms of a -- as the debt comes down and as the cash flow increases?

This is Klesse, Ed. We'll look at all of that. Right now, we want to have adequate cash to go ahead and finish these projects. We've told you in the past this year's capital spending will be, as Mike said, and it's $3 billion to $3.2 billion, we believe. And next year's probably going to be in the same range as we finish our projects. So for guidance, I tell you we're at $3.1 billion for 2012. That will let us finish our projects, and then we'll see how our cash position is affected. Obviously, we're going to close on Pembroke in the U.K. and Ireland with cash, crude oil prices up some, so our intent is to buy all that inventory. So clearly, we'll pull our cash down here in the next week, but then we expect to build it back up because we see a very good third quarter, just as you see. Where we missed consensus, which I think is your question and looking -- when you actually look at what happened, we had a lightning strike at Port Arthur, we had a couple of other things that in a way were act of God. Our mechanical reliability is improving everyday so I mean, we have these acts of God but as you go through the third quarter, July's just about done. It's going to be an excellent month for us. So we missed consensus here in the second quarter but right now, we're going to beat consensus in the third quarter. Edward Westlake - Crédit Suisse AG: And just to be clear in terms of the thought process around returning cash, you just want to make more progress in terms of the hydrocrackers before making such a decision?

That is absolutely correct.

Our next question comes from Doug Terreson from ISI Group.

Bill, industry-wide, we've obviously had some demand destruction over the past couple of months. And on this point, I wanted to see whether or not you guys were seeing any improvement in demand for gasoline and diesel in your major markets. Is there any bounds anywhere out there?

We have not seen that. I'm going to let Joe -- Joe Gorder is going to answer you. I think [indiscernible]

It's been fairly flat, and we're off a little bit on gasoline and diesel here today. We keep looking for those glimmers of hope. But I think on the gasoline side, as long as you got unemployment where it is, it's going to be very tough here, in the States, anyway, for gasoline demand to pick up. Distillate demand we're getting mixed signals. You've got some of the trucking indicators looking positive and some of them looking negative. The same is true with the rail and the marine cargoes, the Port of Los Angeles data looks a little different than the Port of Long Beach data. So we're not seeing any significant improvement, but we're not seeing things crater, either.

Sure. Okay, and on the same topic...

Let me just tell you a little more, though, we'll give you a little more here on Retail. Jean Bernier is going to tell you some about Retail for us, which will give you a good indication.

Okay. So on Retail, our overall demand in the second quarter is soft, it's down about 2% in the U.S. and on a same-store basis, it's down about 3.5%. However, July is looking a bit better than that, so that is an encouraging sign. And in Canada, on the Retail side, actually our volumes have been very strong, overall growing about 3% on a same-store basis between 4% and 5%. So we see different trends in different regions and different areas.

Okay, good. And also on the same topic somewhat. We're starting to see prices approach record levels for end-users in some of your important export markets in Latin America. And so I just wanted to see if Joe or somebody could give us on update on trends in export markets that you guys have exposure to? Are they still pretty strong there as well?

Yes, Doug. Things look good there. I mean, our gasoline exports in the quarter were 69,000 barrels per day and our diesel exports were 143,000 barrels a day. Now the gasoline is primarily being drawn into Mexico, but we moved some to Ecuador and Chile also. On the distillates side, 70% went to Europe in the quarter and 30% to South America. And if we look out to the third quarter, those numbers are generally in that same range. Distillates might be a little higher than the second quarter, but generally in that same range. And Doug, the key for me is that we continue to see an open arm to Europe for the EN590 grade distillates. And so when I look at our distillates for the second quarter, they were down a little bit from historical numbers, but it was more related to availability of supply for us to move out than it was demand abroad. And then if you'll look out to the quarter, the third quarter and going forward, we still have Mexico demand exceeding their supply as imports grow. I think Mexico is now importing 425,000 barrels a day of gasoline and 130,000 barrels a day of diesel and both of those are up from last year. We still have supply problems with Venezuela. Petrobras is purchasing gasoline. And so looking out, things look like they're going to continue that way and so we should see continued strong demand on the Gulf Coast.

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

The project is obviously kicking in next year, if I could just ask you to give us a quick update. I guess this year, we were looking at the 2 FCC revamps. Could they get completed on time, in which case should we expect some improvement, I guess, on the cost lane for the balance of this year? And related, can you just clarify whether or not you will benefit from any tax credits related to the accelerated depreciation of your capital? I guess it's up some fairly substantial numbers. In which case, would you accrue more taxes in 2012? And I have a follow-up, please.

Lane Riggs is going to tell you about the stats, and Clay Killinger will tell you about the taxes.

Okay. This is Lane, our SEC grade job was completed pretty much on time and on budget. It's performing quite well. We're still sort of trying to optimize it, but we've already seen a significant improvement in operations. This is on the St. Charles. In the Memphis SEC, we have the oxygen supply and so we are -- those 2 projects are complete. So we should, on a go forward basis, we should certainly see an improvement in our sort of earnings ability with both of those 2 projects.

I would add that the St. Charles, which was a conversion from a millisecond to a conventional cat, we've seen at least an 8 percentage point increase in our conversion or yield to where we get the 4- to 5-year run. At Memphis, hanging the cat cooler because there's no vacuum tower in there, allows us to go ahead and heavy up our crude slate and we'll also get a 4- to 5-year run. So these are tremendous projects for us when you look at our reliability or mechanical availability going forward, as well as our just general yield because when you get these conversion yields when you have $100 oil, you can see that it's worth a lot of money to us. Taking that slurry to a clean product. Now on the taxes.

Yes. Doug, this is Clay Killinger, the Corporate Controller. Most of these, not significantly all of these projects, will qualify for the bonus depreciation under the tax law. And we've computed at a 6.5% interest rate that for each $100 million of qualified capital expenditures will relate to about $5 million of net present value of benefits to the company.

So your tax guidance for 2012 and you will start accruing that on January 1? In which case, can you give us an idea what you expect the impact to be in terms of percentage on the typical tax guidance that you guys have.

I have -- we haven't calculated what the number will be, but it will come into effect when those projects get completed. But when they get done, we'll update you on that.

Great. My follow-up...

Doug, on -- sorry, I just want to finish then on the hydrocrackers there. We're still looking for Port Arthur to be completed in the third quarter of '12 and St. Charles to be completed in the fourth quarter of '12. So they are big. This is -- overall, this is over a $3 billion capital project between both clients. And this environment we have today will be significant profit contributors as the numbers we've given you in the slides that we've shown.

Bill, my follow-up is really a broader kind of strategic question. You guys have got a feel-good type record of when you buy one asset, you tend to sell another kind of, I guess overall high-grade portfolio. But Pembroke kicking up here and I guess with your exit from more or less from the East Coast, at least for the lower 48, how are you feeling about the broader portfolio? And I guess specifically, I would ask how you're feeling about the West Coast as a core part of the portfolio on a go forward basis? And then I'll leave it at that.

Doug, it's a very good question. And if you think about us strategically, we continue to work on geographic diversification, execution every single day, keeping our investment grade rating. These things are important, but then you get to our portfolio and when we look at demand in the United States, the world is growing, the United States is much more sluggish and it's grown, but we will continue to work on our portfolio. And so we are looking at it again. Obviously, the West Coast has depressed cracks. I think you've noticed in our earnings tables that we actually lost money at the refinery in Québec in the second quarter. And so we tend to look at all of these with the whole portfolio. These are long-term decisions, we'll analyze it in a long-term approach, but we are continuing to work on our portfolio so that we are, in fact, more competitive.

Our next question comes from Blake Fernandez from Howard Weil.

A question for you on Pembroke. I know there was an issue recently, I believe it was a fire of some sort. And I just wanted to make sure, as of the August 1 close date, will that facility be up and running fully operational the way you had projected in your slide back when you announced the acquisition?

Yes, this is Gene Edwards. The refineries are running fine today. There really has been a big impact on operations because of this and there's going to be some possibly rebuilding the tanks. But this occurred on the teller's watch and they're taking care of these expenses.

Okay, great. And secondly, Joe, I know you went through the export environment looking fairly robust through the balance of the year. I was just curious if you have any, I guess, thoughts on next year. Per the IEA, it looks like we've got a quite a bit of capacity coming online globally, about 2.5 barrels a day. Are you expecting any impact on the Gulf Coast's ability to export or how that might factor into what you're seeing?

Blake, I really think it's going to be this way for a long a time. It's almost getting to be a chorus here instead of verse that we've got strong export sales in Gulf Coast. I read an article this morning that Reliance is moving their barrels now to Asia. Asian demand is still strong and we expected them to come to the states at some point in time, we just haven't seen it. So you've got growth in other parts of the world which are pulling those barrels. The Gulf Coast refineries, as we've said before, are very cost competitive. And you have natural markets for those barrels and those barrels are into Mexico, Central America, South America and then over to Europe. And I just expect that this is going to be with us for some time.

Our next question comes from Mark Gilman from Benchmark.

I had a couple of things, if I could. Just by way of a clarification on the tax issue mentioned previously. I assume that, that bonus DD&A is not going to affect the effective rate, but rather cash tax and that you'll be providing deferred taxes. And I correct in that regard or wrong?

Yes, you are. You are correct.

Okay. Couple of other things, if I could. I noticed pretty significant increase in high asset crude runs in the quarter and was wondering is that a permanent shift and what's given rise to it?

Well, this is Joe, Mark. It's the economics that are giving rise to it and you're right, we ran much higher volumes of marlum [ph] and Friday in the second quarter. We also ran more volumes of M-100. But it was all economically driven.

Okay, with respect to the intent to increase the Eagle Ford volumes, Joe, Jean or Bill, anything entailed in doing so, other than the logistics of getting it there from a hardware catalyst or any other type modification that would have to be made?

Mark, we're running now 40,000 a day down there. And we've got a turnaround scheduled in September and Lane can speak more to this if he'd like, but there's no major changes in the turnaround as a result of the turnaround, that are going to allow us to take those volumes up to 60,000 a day. So in addition to the volume we're going to run there, we're going to try to run the 25,000 that Mike mentioned with Corpus Christi and the great thing about running more of this Eagle Ford crude is we've got it priced in there at a WTI-type price and we're backing up CPC and Sahara and then more of the expensive foreign suites. So Lane, anything on the plant?

I just -- during the turnaround, we're going to hang some valve on the top circulating reflux of the pump ground to be able to handle it. It's a lighter crude and so it will allow us to once we get up around 60, we're still trying to determine, but we think we'll build around even more than that but essentially, we're hanging the valve and having the exchanger will allow us to do that after the turnaround.

So Mark, we'll spend somewhere in the neighborhood of $10 million around Three Rivers to do some of this that the fellows are talking about. To go above that would cost more money and, of course, we'd probably need a permit. So these are longer conversations, then. And at Corpus, it's all been to this point really trucking, pipeline construction, getting the oil to the plants. Some of you may remember, I've mentioned to you we have a project at our McKee Refinery which is the same kind of thing, just not Eagle Ford, but the issue we have at McKee is we need a permit. We would spend about $100 million to have a modest expansion there which has good economics, but the permit is probably an 18- to 24-month conversation.

Okay. Guys, I've listened very carefully to what Mike said about the crude discounts in the Mid-Continent. But I guess from that standpoint, my thought was the capture rate in that region really doesn't seem to reflect that. Am I missing something?

I think you are, Mark but we'll be glad to walk you through.

Why don't we -- why don't you call, Mark, because I don't mind telling you guys, our most profitable refineries are McKee, Three Rivers and Ardmore. So we're capturing but I'm not sure -- what I'd like you to do maybe is to call Ashley after the call and he'll walk you through it.

Yes. And I think there's one more item that the broad public should understand is in our Mid-Continent system includes Memphis. So roughly 40% of our Mid-Continent region doesn't participate in WTI. Memphis is an LLS-base refinery. So if you assume that all that throughput is catching the WTI base margin, you made a very bad assumption.

Okay, last one for me. Where were you in the quarter and where might you expect to be in terms of being buyer brands?

Mark, we're up definitely by our grids. And we're now to the point where we're blending probably over 80% of our gasoline volumes with ethanol. So that's not the issue, but it's really the biodiesel RINS that become the challenge for us. There's just not enough biodiesel up here to blend for us to meet it with blending this year. We have plans underway to put in blending facilities for biodiesel at a handful of our racks. And we expect that by the end of 2012, we'll be blending at volume to satisfy that obligation, but it will be a build-up until that time. So we are a short grid.

It's an expense of well over $100 million. And maybe I can just leave it at that. This is a big program and Joe is telling you things we're doing to mitigate that, but for Valero, it's well over $100 million.

Bill, is that annual or quarterly?

Annual. It's over $100 million.

Okay, does it go up from here until you get in position to be able to achieve that blending?

No. No. Unless the market for the RIN -- and frankly, Mark, it's all related to these biodiesel RINS. Those are very expensive. The market forms about $1.34 and you look at that compared to an ethanol RIN, it's $0.035. So the market for the biodiesel RINS are very high because they're just not available out there. We are going to be blending more though, as I said, and as a result, that expense should go down as we proceed forward.

Relative then to the price of wherever they're going.

Right. And it's more biodiesel's blended price of the RIN should come down, too.

Our next question comes from Jeff Dietert from Simmons. Jeffrey Dietert - Simmons & Company: On the Eagle Ford volumes, as you think about some of the light-sweet crudes coming on the Eagle Ford Permian, Bakken, Cushing area, their major pipeline is coming from the Eagle Ford in the Houston Longhorn reversal into Houston, the Keystone XL Enterprise, Enbridge lines going into Houston. If production grows as fast as many of the producers believe it will, are you looking for incremental volumes? Could you use incremental light-sweet volumes in your Houston area refineries over and above what you've already talked about?

Some are going to Houston, some are going to Port Arthur, but Joe's going to answer you.

Yes, I mean, Jeff, clearly, the Mid-Continent refineries are benefiting now, right? We all see that. But to the extent that we do move sweet crudes down into the Gulf, you're going to see pressure on LLS prices. And so would we like to see some of the crude end up in the Houston market where we could run it or over at Memphis? Absolutely. I don't think that we're going to see this get resolved, though, anytime soon. I don't know what your view is, but you've got so much production coming on stream up there as you describe, that I think we're going to see significant volumes continue to pour into the market, both from the regions you mentioned, the Bakken area from the Panhandle area and then Canadian barrels coming in. And it's going to be 18 months or better for the pipelines to be put in place to carry it out. So I think you're going to see continued pressure on those discounts in the Mid-Continent. One thing that's interesting, Jeff, that we saw is that Cushing tank capacity is coming on stream big time. We used to use 40 million barrels as a number of tank capacity, it's up to 62 million now and in the next 6 months, we're going to add 13 million barrels which is going to take it up to 75 million barrels a storage. So clearly, the market is getting ready for a lot more of this Mid-Continent crude to be available and to be stored. Jeffrey Dietert - Simmons & Company: Joe, are you starting to see some Saudi -- attractive Saudi barrels coming into the U.S. Gulf Coast? They've talked about -- they raised production in June and they're talking about further increases in July. Are you guys seeing some of those barrels? Are they getting priced attractive enough to find their way to the Gulf Coast?

We are. We're running now some pair of extra lights in the Gulf. We're also going to be bringing in more Kuwaiti barrels. The Kuwaitis have lifted their imposed reduction of contract volumes. We were operating for a period there where we had a 10% reduction in our contract volume. They notified us that they were taking that off and that we were able to take more barrels. I do think we're going to see a lot more medium-sour barrels coming into the market. Jeffrey Dietert - Simmons & Company: How significant are those volumes?

I understand that Saudis are going up to 10 million barrels a day of production. So that would be, what, another -- not entirely to the Gulf, but they're going to put that in the market. Jeff, I don't know how much you'll see. Jeffrey Dietert - Simmons & Company: Okay. On Pembroke, you've provided some guidance on $0.25 a share of accretion on 2010 outlook. Do you happen to have an updated number based on where the forward curve is today?

I think the forward curve -- Jeff, this is Jean again. Forward curve looks pretty similar to our forecast. Although rig prices are obviously very high right now, so there is some concern on that. But if you look at the 211 to Brent today from $13 a barrel, it's really not at all that bad. So I think -- we haven't really redone our economics since we did the acquisition, but I think it looks more or less in line. Jeffrey Dietert - Simmons & Company: Okay, all right. And do you have any comments on the status or the impact of the ethanol tax credit repeal? And how that might influence Valero or the industry as a whole?

Yes, it's Gene again. I'm not sure when it's going to get repealed. The senate was talking about July 31; said that's going to happen, but maybe it'll happen at the end of the year. We're watching it, but in reality it doesn't really have much impact on us right now. The blenders' credit is really being captured by the blender, not the ethanol producer. Just to use an example, ethanol today is right around $3 a gallon, CBOB and RBOB in New York are both $3.05, $3.10 a gallon, so there's margin to blend even if you don't have the $0.45 credit. So in fact, as the blenders who patron it, we capture a little bit of it at our retail. And our wholesale is passed on to the wholesale customers. At Retail, from our analysis, like it's more or less competed away when we have good ethanol blending margins, our overall margin at Retail doesn't seem to be affected much by that blenders' credit. So I think it's competed away the business, whether it be wholesale or retail. So net effect to Valero really is pretty much nothing.

Our next question is from Paul Cheng from Barclays Capital.

Number of questions. In Corpus Christi, do you have -- how much you can run Eagle Ford? Right now you're saying that in third quarter it's about 25,000 barrel per day. Assume that you face no major restriction in the logistics side, how much more of that you can run it up to?

Paul, this is Lane Riggs. We have 2 crude units there. We have our West plant crude unit which can run about 40,000 barrels a day, so that would be pretty much -- you're able to run about 40 a day of Eagle Ford from all those economic. And then our other plants is our East plant. And it's predominantly medium-sour, heavy-sour. But at the end of the day, it's all about economics. We can run Eagle Ford in that crude units, it's just a matter of it being available and the economics are right. So that's about 100,000 barrel a day, so we can run quite a bit.

The reason Lane is answering you this way is the East plant has a coker, so you tend to run the coker, but if you get enough discount, you don't run the coker.

This plant is your original plant, right, with the recent cracker?

The West plant has the recent cracker.

That's the original.

That's the original Valero plant is the West plant. The east plant is the old coastal plant.

Okay, all right. I see, I see, very good. Can you give me some balance sheet data in terms of working capital, long-term debt, market value of the inventory in excess of the book?

Yes. On the current assets, it's $14.7 billion; current liabilities, $10.2 billion; total long-term debt, $7.6 billion; and then our market value in excess of a LIFO on the inventory is $7.9 billion.

Okay. And that maybe that this -- I supposed that this maybe is for Ashley. On the Québec, is there any particular reason why margin realization seems like, sequentially at least, half from the first quarter, have dropped so much comparing to the benchmark indicator?

Québec. Yes, typically -- and if you go back and look at our capture rates versus typical indicator like a Brent 211, it falls from first quarter to second quarter. Mostly on the light end, the butane, LPGs out there, the market always gets weak because you can't blend them into the gasoline pool and you'll see it fall from 4Q and 1Q are typically a higher-capture rate. It falls in second quarter and then kind of holds and builds back up as you can start blending into back in the gasoline.

That seems like it's pretty substantial because the benchmark indicator seems to be flat to slightly down on it.

It does look substantial and it has been substantial in the past.

So do you think that this is still normal on the seasonal pattern?

That's absolutely. Go back -- we've been posting our Québec-only performance for that region. We posted that to the website a few months ago, right up to the first quarter. And you can see historically how Québec has done over the past 5 years and in the first quarter to second quarter, it falls anywhere from 20 to 30 percentage points on capture rate. And this is the key driver.

I see. And Aruba, did you guys make money in the second quarter?

No, we did not. We had margin, but we had many operating issues.

Bill, is it a primarily an operating issue or that the configuration just, even in today's market, this cover light, heavy defense or you still won't able be to make money?

I'm going to take the second part first. The configuration is an issue when you have $100 oil running at coking refinery, you just have to have a big discount. And that's all -- I mean, it's just as simple as that.

Right, so the current discount is not big enough?

The discount would've been big enough in the second quarter then if we had run better. And we had a lot of problems to start up, which basically we started a year ago, getting ready to start up has been very tough for people who've worked very hard. We've had a lot of issues in getting back to a good rate. Today, we're running revenue 200,000 barrels a day, but we've had issues getting there.

Okay. So do you think that now the bulk of the issues is behind you?

I think we have clearly make progress on running -- being able to run reliably, but I would tell you that the second half on the P&L, not necessarily cash flow totally but P&L, will be challenging unless we get a change in the discounts.

I see. And Bill, for then -- this is for Mike, for the remaining 2 spending for the hydrocracker in St. Charles and Port Arthur, how much is the remaining that you have to spend?

It's about $1.3 billion.

Together?

Combined. $600,000 -- $600 million, $700 million, then we have a couple of other projects around it. So I would basically tell you that it's about a $1.5 billion to finish the 2 hydrocrackers, some of the crude work that's going on around it.

Bill, do you have a rough number that what's the CapEx look like next year?

The capital spending next year? Yes. I'm going to say it's the same as this year, $3 billion to $3.2 billion and I think I said we'll go $3.1 billion kind is where we are sitting at this point. Now having said that, that's kind of like a ballpark number because like most companies you guys will talk to, we're in the middle of starting our budgets for next year and our planning, so...

Two final questions. One, Bill, historically, Valero, the strategy is that you left there large coastal refinery with a high conversion capability to win a lot of discount group, that kind of flexibility. With the last 6 or 7 months drastic change in the Mid-Continent TI spread, does it in any shape or form change your view about the criteria? Or that you think that this is just too short-term of a phenomenon there for you to really change your strategic thinking?

It's a very fair question, Paul. Obviously in today's market, it is all about location. So just -- it's a given. And to solve some of the switch and Valero's benefiting by it, we have already told you that McKee, Ardmore and Three Rivers. So for the industry then to cause the LLS, WTI types to narrow, it's really, probably an 18-month to 2-year conversation because some of the things that I think Doug mentioned earlier, or maybe it was Jeff, they're not all happening yet. So this is 18 months to 2 years away for pipelines to move this volume out of the Mid-Continent. So location, it's all about location today. However, I would still say to you that at the end of the day, it's just like we've talked about in the past, it's location, it's complexity, but it's also being able to operate. And executing, executing, executing all the time. And that's the piece that you will notice over the next, as these projects are getting done, you're going to see our executing is dramatically improving. On our mechanical availability now, we are borderline first class -- first quartile and a couple of years ago, we were third and fourth quartile. So you will see that as these data keeps coming out. But today, it's all about location. Bottom line.

But you do not believe that if longer -- if we need to spot the long terms of you and not changing the way how, in terms of M&A, in consideration of that criteria?

I'm not going to say not changing. I'm going to say it; a few minutes ago I said complexity matters. Where Valero's expertise is, is running high complexity refineries and that is our institutional knowledge here. However, we are looking at an expansion at the McKee refinery. We've already talked about what we're doing in South Texas. Those are projects that we would not have considered 2 years ago for sure. Would not have considered one year ago, for sure. So there is obviously some change in our approach. On the other hand, to give you the whole story, you can see our Québec numbers, as Ashley said. We have a currency, currency's gone up in Canada and that makes their conversion to dollars. You can see when you look at their operating costs, it's moved up dramatically. Obviously, they're buying light sweet crude. So where we have an emphasis on in Québec is going to be much more on the cost side and the products realization side because they've lost that currency buffer that they had previously. And the advantage crude oil being foreign. So clearly, this market that we're in with these differentials or spreads that we've not seen before are certainly biasing our -- certainly our strategy. But it is still about executing and complexity and being able to take these barrels and make very clean products out of them reliably every day.

And finally, can you tell us that, is there any major turnaround from you guys then in the second quarter -- I mean, the second half and the first half of next year?

I think Bill Bay just released our turnarounds, but we have them at Corpus Christi in October and Three Rivers in September. The Three Rivers refinery, the entire plant's down. And it's down for 3 or 4 weeks and the Corpus Christi one is…

The East plant crude coker, for 3 weeks.

The larger crude unit, the East plant we talked about, down for 3 weeks. The crude coke. But these turnarounds that are just scheduled turnarounds. The heaviest turnarounds we had was in the first quarter.

And our next question comes from Evan Calio from Morgan Stanley.

A couple of questions for you. A question for you on the macro, it really feeds into the prior response that you had on Arab light volumes. And frankly, it actually may highlight complexity versus location. If we look into the year-end, excess PR, you could see over 1.2 million barrels of incremental crude demand with low sulfur Libyan barrels out, it looks as though x the SPR, that would be met with primarily sour Arab light barrels. What are your views in terms of the global market setting up for heavy-sour imbalances in the back half of the year? And can clearly benefits to your system, any comments? And I have couple of questions.

Evan, this is Joe. If you think about heavy-sour in general, okay, we've got a discount right now, Maya related to LLS that's around $14-a-barrel, which is a decent discount. The SPR release certainly depressed LLS briefly which compressed that Maya discount, but now it's moved back out. But if you look more broader than just Maya, you've got a market right now that sees Pemex production stabilizing at $1.4 million of exports a day, somewhere in that range. You got Columbia increasing their heavy-sour production by 140,000 barrels per day. They're up to 870 barrels now, which is significant increase over year. You've got Brazil increasing their production by about 150,000 barrels per day. We're seeing a lot more Basra in the market today. As we mentioned earlier, we've got the Saudis putting more barrels into the market, as are the Kuwaitis and then ultimately we're going to have Keystone come on and it's going to allow us to move more of these Canadian barrels into the market. On the medium-sour side, you've had somewhat reduced production in the U.S. Gulf Coast because there's been some maintenance been taking place on the Mars platform. And of course we had the spill which delayed subsequent drilling, but that will pick back up here at some point in time. So when we look at the market for sour crudes, both heavy- and medium-sours, we're pretty optimistic about these discounts.

Right. It looks that way, in my opinion. And one -- just a question on Maya, how should we think about the K factors? I mean, do you see that being moved to offset some of the WCS impact in that pricing formula that's being impacted by Cushing inventory levels or pressured Cushing?

Yes. Clearly, the biggest part of the formula is that. The K factor is what the Mexicans use to try to keep the market, the oil price at what would be a market. And certainly, when you get heavy-sour Canadian crude coming into the Gulf, it's going to put -- anytime you get more supply, you're going to have pressure on these discounts. And so we expect that that's probably going to happen. They have been very good, they're very capable, they've been very good at trying to keep the Maya price somewhat similar to a medium-sour crude alternative. And we expect they're going to try to continue to do that in the future. But again, if you have more crude supply into the market, it shouldn't pressure those discounts.

A question on Québec. I know you mentioned focusing on cost, but is there any potential solution to move Canadian discounted lights that are really getting backed out from the U.S. Mid-Continent and sands growth that may be able to move to the east and give you a TI-like discount into that market? Is that -- how do you guys think about that?

Ah no, Evan. There's really not any logistics in place. You can always route it. You can do -- you could put it, I guess, on a barge or a ship, but it's really, the logistics don't fall that way.

Okay. But real economics don't work then?

Well, you have to get the cars. I don't know what people are telling you. Ours now are probably almost a year lead time. Certainly, you'd have to build the facility. We have a rail facility, but it works for products. And our pipeline won't be finished until the end of next year. So we're looking at all of these items, including what Ashley mentioned on the butanes, as well, and on the general operating cost side. But your specific question is -- it's a little -- it's harder than just putting it on a ship and shipping it in.

Okay. I appreciate that entirely. On Three Rivers, I mean I know you're working with Harvest Pipeline to bring a line from Eagle Ford into the asset, but is there any magic about 60 in terms of 95 CD capacity? I mean, is there a potential to increase compression and take that number higher or is that, as you think about the asset, the right maximum amount for you?

This is Lane. We can -- we will see. Ultimately, we may think we can run up to 80,000 barrels a day. It's just a matter of whether it's filled out parts of the refinery properly. But you're right, the Harvest Pipeline will be there. We've put in a big truck rack. We will not be logistically limited on Eagle Ford availed in the refinery. It will all be about the economics of Eagle Ford in refinery which today, we would run as much of it as we could.

I got you. And just lastly, briefly, on the SPR and SPR release. I know you're the single largest purchaser, like close to 7 million barrels. How did it benefit you guys? Can you explain maybe the process?

Well, I mean, we certainly can run the crude and we were able to pick it up and a $5.11 discount on average to LLS. And so it's a simple math. You do the $7 million barrels times the $5 and we've had huge benefit for bringing it in.

We'll have some cost moving it around, but what we did is -- the oil fits us in many of our locations so we just decided to bid, it was a bid process. And so as Joe said, we got it for a little bit of a discount against the metric. Joe's supposed to get that discount every day.

That's great. And maybe I just want to add one other question, I know you guys are running a lot more crudes through your program. I mean is that, does that -- but it hasn't yet impacted inventory levels. I mean, is there some correlation with running more crudes and having higher inventory levels since you kind of want to blend out so you don't beat up your units as much?

I'm trying...

I would say no because we typically -- and I guess one of you guys correct me, our crude inventory number runs about 20 days, 22 days, so we're turning our inventory over 20, 22 days here in that range. So it just goes through our system. And we'll -- our supply people are always balancing our system. So moves a couple of million barrels, we have over $100 million of barrels of total inventory and moves a couple of million barrels, but the system is always trying to get optimized.

Our next question comes from Chi Chow from Macquarie Capital.

We've beaten this topic to death today, but I'm going to ask one more question on running this inland crudes through your system. Well, just one more here. So assuming a couple of years down the road, this is, I guess, hypothetical, that Saudi's pipelines and trends come in, assuming you can get all the volumes of inland crudes you want down to the Gulf Coast, is there an upper limit of how much of these light-sweet inland crudes you can run through your entire Gulf Coast system?

All right. I'm going to answer you and say because we got into this conversation today, it all depends on the price. So today, we run different crude oils at our Houston refinery. We could put a lot of lighter crude in there. You could put lighter crude into all of our refineries. You'll underutilize your coker and then as Lane was explaining earlier because it's lighter, you'll overload your vapor handling capabilities, so that's where you'll have to stop. But it all depends on price.

So you've got 1.6 million, 1.7 million barrels a day, something like that of capacity. I mean, theoretically, you can run a full dose of that without any sort of impacts on operations?

No, I would say, we would not be able to run that much. We would get limited out on being able to handle the vapors. But you might make more money.

Right, right. Okay.

So the way we do it, it's just like all our competitors do it, we run the LP.

Do you ever see the U.S. as being an exporter of LLS or WTI down the road?

I doubt it. I mean, we're still bringing forward sweeps in.

I think we would answer this to say our opinion is going to be no better than yours, I think is the best way to say that. The U.S. is still a big importer. The U.S. imports over 9 million barrels a day of crude oil. And so it would have to be some issue with the refining capacity which you were just asking us for that to happen. But of our knowledge would not be any better than yours here.

Okay, great. I guess, one other quick question, Bill. I think last quarter, you mentioned that you thought Valero could beat the $3 EPS for the year. Is that -- do you still feel pretty good about that?

Yes, I do.

Our next question comes from Cory Garcia from Raymond James. Cory Garcia - Raymond James & Associates, Inc.: Try to sneak one quick one in here. In regards to your sort of stay-in business maintenance capital, seeing that's been running about $1.7 billion and I believe several quarters back you guys were talking maybe $1.3 billion to $1.4 billion. Bearing in mind that obviously the regulatory environment can change on a dime, I'm looking at sort of how your portfolio has changed. Are you still thinking maintenance cap could get back down toward $1.3 billion, $1.4 billion in the years ahead or are looking at more of a $1.7 billion, $1.6 billion type of level?

I think that eventually we can get to that number. And what it is, is basically, we spend DD&A. And then you always have to consider these environmental rights or other type of regulations. But yes, we can get there, but what we're doing today is we're spending in a little hire rate in that area just because we have many things going on to improve our reliability through our system. And as we're replacing bad actor pumps as we're addressing problem exchangers and that in the system, they are causing us to have a little higher capital spending. But our target would clearly be that we are going to able to do it around DD&A, with some subject to inflation there, but basically, a DD&A. And for Valero, total DD&A is about $1.5 billion. So for the refining group, it must be about $1.3 billion.

We have no further questions at this time.

Okay, thanks, John. And I just want to thank shareholders for listening to today's call. If you have questions, please contact the Investor Relations department. Thank you.

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