Valero Energy Corporation (VLO) Q3 2011 Earnings Report, Transcript and Summary

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

Evan Calio - Morgan Stanley, Research Division Sam Margolin - Global Hunter Securities, LLC, Research Division Paul Y. Cheng - Barclays Capital, Research Division Mark Gilman - The Benchmark Company, LLC, Research Division Blake Fernandez - Howard Weil Incorporated, Research Division Paul Sankey - Deutsche Bank AG, Research Division Jeffrey A. Dietert - Simmons & Company International, Research Division Doug Terreson - ISI Group Inc., Research Division Allen Good - Morningstar Inc., Research Division Rakesh Advani - Crédit Suisse AG, Research Division Chi Chow - Macquarie Research Jacques H. Rousseau - RBC Capital Markets, LLC, Research Division Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division Faisel Khan - Citigroup Inc, Research Division

Welcome to the Valero Energy Corporation Reports Third Quarter 2011 Earnings 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. Good morning, and welcome to Valero Energy Corporation Third 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; Kim Bowers, Executive Vice President and General Counsel; and Jean Bernier, Executive Vice President. If you have not received the earnings call -- 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 segment. If you have any questions after reviewing these tables, please feel free to contact me after the call. Before we get started, I would like to direct your attention to the forward-looking statement disclaimer contained in the press release. In summary, it says that statements in the press release and on this conference call, that state the company's or management's expectations or predictions of the future are forward-looking statements intended to be covered by the Safe Harbor provisions under federal securities laws. There are many factors that could cause actual results to differ from our expectations, including those we 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 that third quarter 2011 net income from continuing operations of $1.2 billion or $2.11 per share, compared to $0.53 per share in the third quarter of 2010. Our third quarter 2011 operating income was $2 billion versus operating income of $590 million in the third quarter of 2010. The third quarter refining throughput margins was $13.24 per barrel, which is a 63% increase over the third quarter of 2010. The increase in throughput margins over the third quarter of 2010 was due to higher margins for diesel, jet fuel and gasoline, plus wider discounts for heavy-sour crude oil, residual feedstocks and light-sweet crude oils in the Mid-Continent and in South Texas. In the third quarter of 2011, the Gulf Coast gasoline margins per barrel versus LLS increased 89% to $8.20 from $4.35 in the third quarter of '10. The Gulf Coast ULSD versus LLS margins per barrel increased 56% from $9.12 in the third quarter of '10 to $14.19 per barrel in the third quarter of 2011. So far, in the fourth quarter, Gulf Coast margins have moved lower, averaging around $1 per barrel for gasoline at nearly $13 per barrel for ULSD. The Maya heavy-sour crude oil discounts versus LLS increased to 22% from $11 in the third quarter of '10 to $13.48 per barrel in the third quarter of '11. The Maya discount has narrowed some in the fourth quarter with the average down to around $12 per barrel. These discounts are important in our Gulf Coast region where we have significant capacity to process heavy-sour crude oils. Another benefit for Valero came from Mid-Continent in Eagle Ford crudes pricing at a substantial discount to LLS. Over the last year, the WTI discount to LLS has increased by merely $20 per barrel, from $2.58 in the third quarter of '10 to $22.47 in the third quarter of '11. The WTI discount significantly enhanced the profitability of our McKee and Ardmore refineries, both of which process WTI or cheaper crude oils. The fourth quarter WTI discount to LLS has averaged around $25 per barrel, but recently, the spread has narrow in yesterday closed at less than $19 per barrel. We also continued to increase the use of the discounted Eagle Ford crude in our system. During the third quarter, we processed an average of 46,000 barrels per day of Eagle Ford, primarily at Three Rivers, but also some at Corpus Christi. That is an increase of 9,000 barrels per day over the second quarter and an increase of more than 40,000 barrels per day since 2010. This local crude replaced more expensive imported sweet crudes saving Three Rivers and Corpus around $15 per barrel in the third quarter. We also took delivery and ran discounted sweet crudes from the strategic petroleum reserve in the third quarter. Valero purchased 6.9 million barrels at a discount of over $5 per barrel to LLS providing $35 million in additional refinery throughput margin in the third quarter. At our Aruba Refinery, operational improvements combined with better commodity prices resulted in Aruba generating an operating profit this quarter. In the North Atlantic region, we had a smooth transition with the addition of U.K. and Ireland businesses, including the Pembroke refinery. The refinery has run well and we continue to integrate the businesses into our operations. On the West Coast, our throughput margins versus benchmark fracs performed well, mainly on wider crude discounts and increasingly huge of such crudes. In addition, operational improvements at our West Coast refineries helped to enhance our liquid volume yields. One final comment on refining margins is that international demand, particularly in the developing markets, has been the key driver for growth in 2011 and helped to elevate the margins to the levels we have seen so far this year. Our cost efficient refining portfolio will continue to take advantage of both domestic and international opportunities available in the marketplace. Our third quarter 2011 refinery throughput volume averaged to 2.6 million barrels per day, up 389,000 barrels per day from the third quarter of '10. The increase in throughput volumes was due to a combination of economic incentive from stronger margins, the addition of capacity from the acquisition of the Pembroke refinery on August 1 and the restart of operations at the Aruba refinery. Refining cash operating expenses in the third quarter of 2011 were $3.65 per barrel, which was lower than the second quarter of 2011 and our guidance, mainly due to high throughput volumes. Our Ethanol segment reported record-setting quarterly earnings with a $107 million in operating income in the third quarter, which was up $60 million from the third quarter of 2010 and up $43 million from the second quarter of this year on higher gross margins. Our Retail segment reported a solid third quarter with $97 million of operating income. U.S. Retail had $59 million of operating income in the quarter and the Canadian retail operation earned $38 million of operating income. In the third quarter, general and administrative expenses, excluding corporate depreciation, were $161 million; depreciation and amortization expense was $390 million; net interest expense was $88 million; and the effective tax rate on continuing operations in the third quarter was 36.4%. Regarding cash flows in the third quarter, capital spending was $684 million, which includes $69 million of turnaround and catalyst expenditures. Also in the third quarter, we paid a $28 million in dividends and $268 million to purchase 13.5 million shares of our common stock, or 2% of outstanding shares. We also spent $1.6 billion to acquire the Pembroke refinery and related to marketing assets, which included approximately $900 million for working capital and other assets. With respect to our balance sheet, at the end of September, total debt was $7.6 billion, cash was $2.8 billion and our debt to capitalization ratio, net of cash, was 22.4%. At the end of the third quarter, we also had over $4 billion of additional liquidity available. And as referenced in the release on October 1, we acquired the Meraux Refinery and related logistics assets for $586 million in cash. This payment included approximately $260 million for a preliminary estimate of inventories and other assets. And we do expect to receive in the fourth quarter a favorable true up adjustment that will reduce our price by approximately $40 million. Our completed growth projects are beginning to add to our earnings power. We realized the benefits from our St. Charles FCC revamp project during the third quarter, its first full quarter of operation. These benefits included improved liquid volume yield, lower energy costs, lower catalyst costs and reliability benefits. Using third quarter 2011 prices, we estimate the annualized EBITDA benefit from this project is approximately $150 million. Our remaining growth projects remain on budget and on time to complete in 2012 and we expect these projects to generate significant earnings and cash flow growth when started up. The hydrogen plants at Memphis and McKee should be completed by the end of 2011. Our 2 hydrocracker projects at Port Arthur and St. Charles are set to finish in the second half of 2012, along with the Montréal products pipeline and the Diamond Green Diesel joint venture. Most of the product -- projects were designed to capitalize on high crude oil and low natural gas prices while producing diesel and gasoline to meet the growing global demand. In summary, we had an excellent third quarter. We took the opportunity to return cash to our shareholders via stock buybacks. And last week, our Board of Directors tripled our quarterly dividend rate to $0.15 per share. These decisions are result of our strong financial performance, favorable industry conditions and a significant contribution that we expect from our major growth projects that are scheduled for completion next year. Regarding strategic activities, we added another quality asset to our portfolio, and then further improved our earnings power with the acquisition of the Meraux Refinery. This is a flexible high-quality asset with the distillate focus conversion capacity, including a 34,000-barrel per day hydrocracker. This first quartile refinery fits well into our Gulf Coast system and has excellent potential for synergies with our nearby St. Charles refinery. We have also restarted a formal process to seek strategic alternatives for our Aruba Refinery. In conclusion, the significant contributions expected from our major growth projects, which are independent of the WTI priced crude discounts, selective strategic acquisitions that improve earnings power, our strong financial position and our investment grade credit rating provide an excellent combination for future earnings and cash flow growth. 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 should be somewhere between 1.52 million to 1.56 million barrels per day; Mid-Continent at 430,000 to 440,000 barrels per day; the West Coast at 270,000 to 280,000 barrels per day; and the North Atlantic at 440,000 to 460,000 barrels per day in the fourth quarter. Refining cash operating expenses are expected to be around $3.85 per barrel in the fourth quarter. Regarding our ethanol operations, we expect total throughput volumes of 3.4 million gallons per day, and operating expenses should average approximately $0.36 per gallon, including $0.04 per gallon in non-cash costs such as depreciation and amortization. With respect to some of the other items for the fourth quarter, we expect G&A expense, excluding depreciation, to be around $175 million; net interest expense should be around $85 million; total depreciation and amortization expense to be around $390 million; and our effective tax rate should be approximately 36%. We'll now open the call for questions. John?

[Operator Instructions] And our first question comes from Doug Terreson from ISI Group.

Mike, you mentioned something just a second ago about -- it's about the strategic review process at Aruba entail[ph]. I may have misunderstood, but I want to say if we could get a clarification on what you said and also what you meant by that statement or that point?

Okay, we have started a process of looking for a strategic alternatives for our Aruba Refinery.

Yes, if I can add to this, Doug, our operations have improved a lot. Our people are doing a fine job. We have several excellent reduction -- cost reduction efforts under way. For Valero, we used it, really as we're looking at the refinery going forward as a feedstock source to our big conversion operations along in our large conversion operations along the Gulf coast. So in a way, it's a front end for us. We're looking at some reconfiguration as to where we actually do hydro-treating. But the facts are, we're still very interested in finding a partner or some relationship that allows us to process very sour, heavy crude or high-TAN crude, which the refinery can do.

Okay. And Bill, you've been a leader for the industry on a regulatory front over the last several years and over the past, or maybe longer than that, but over the past several months, there have been some commentary on new rules for U.S. gasoline for 2012, which I believe they're calling Tier III and resembled those in California, but for the entire United States. And so my question, do you have any insight into these new roles? Specifically, whether this movement appears to be significant? And what if any implications there might be for Valero?

Well, I don't know if I have any insight, but what's going on is under the Clean Air Act Amendments of 1990, there is a certain protocol passed by and the Clean Air Act was passed by congress. And so the EPA and when it looks at ethanol being added to fuels and other -- primarily, ethanol reflected then and vapor pressure and the emissions, feels like they need to drop the sulfur to honor the commitment of the Clean Air Act and drop it to 10 ppm average, but it's under debate still. Well, the whole issue is, but the ceiling as to whether it's going to be a 30 ppm max or an 80 ppm max. Today, we have an 80 ppm max, 30 ppm average and then Tier III, you'll have different numbers. So it's all being discussed. Our industry is against it. It will raise the cost for the consumer, and we think it is an extremely marginal benefit for the -- if any benefit at all.

Our next question comes from Paul Cheng from Barclays Capital.

Just a number of quick questions. Mike, can you give me what is the working capital, the market value of the inventory in excess of the book? And that all of the total debt, what's the long-term debt in the component?

Okay, sure. Total current assets are $15.9 billion, total current liability is $11.7 billion. Market value in excess of LIFO value is $7.1 billion. Our long-term debt and capital leases is $7.6 billion.

And that $15.9 billion current asset, I assume that's including cash, right?

Includes $2.8 billion of cash, yes.

Okay. And that, Mike, in your result, is there any trading gain or loss? And also that do you have any future hedging position?

The trading gain in the third quarter was very minimal, it's about $3 million.

Any hedging position that for the next several months?

No material positions.

And Bill, maybe you -- can you share with us what is the major turnaround you guys going to do in the first half of next year?

I'm going to let Lane Riggs answer you.

Paul, this is Lane Riggs. Our major turnarounds are in Wilmington, on the West Coast. It's accrued that coker net at the hydro trigger since bureaus officially have the refinery. St. Charles in February, which is the crude coker diesel hydro trigger, also low properties on SRE, so again, similar type turnaround, excluding the SEC. At the Houston, we have an SDC Alki in February. And finally, we have -- some March, we have Memphis, which is prudent diesel hydro trigger turnaround.

Let me add to this. The February 1 at St. Charles is a huge turnaround for us. We're going to replace the coke drums. Many of you that follow us know, we've had this coke drum issue at Port Arthur and at St. Charles, and -- which was an engineering design and what we are doing is replacing the coke drums we did at Port Arthur this year and next year, we're going to do it at St. Charles. To do this lift at St. Charles, extends this turnaround -- I think, we released it this morning and at 70 days. But it's a very large turnaround for us at St. Charles. But that will then put these issues we've had with the cokers, except for some vapor lines behind us.

Perfect. And that for Wilmington and Houston, how many days are we talking about?

On Wilmington, it's about 20 -- a month. And Memphis is also about a month.

Memphis is also month, and how about Houston?

It's 37 days.

Okay, Houston is 37 days. Mike, will you be able to share with us how much you make in Europe for the 2 months that end the quarter?

Let me just finish in the turnarounds. We announced that this morning and so the release went out as to our turnarounds in the schedule.

Yes, if you're interested in looking for details on this turnarounds and the timing, you can find those on our website.

Perfect. Mike, will you be able to share with us that how much you make in Europe for the 2 months you own in the quarter?

Yes. We made a little over $53 million in the first 2 months.

And then a final one, Bill. For the M&A market, can you share with us what you are seeing? Is the pricing condition in terms of acquiring us at the pricing condition become better or become worse over the next last several months for you guys? Or what you can see out there?

Well, I don't know if I can speak to the pricing conditions. But there's certainly several refineries for sale. We believe we bought the 2 refineries we purchased here recently at very, very good numbers. They fit into our portfolio, strategically too. We wanted to step out some, so if we could done that. When you look at where Valero trades relative to what we purchased in these refineries, we actually paid for -- purchased them for less than what we trade. Obviously, there's quite a few assets on the market. And then just to anticipate the next question, because I can't speak to the pricing except that I've said a couple of times it's a buyers market. And it continues to be that way, it's a general statement. But in Valero's particular case, we're only interested in acquisitions that fits us strategically and that is accretive and has to be both, if it's not fitting us strategically, we're not interested. And there is no case I can think of that we would issue any equity on any situation that's out there.

And you guys already did a little bit of the share buyback in the third quarter. In terms of the cash you generate, the free cash, over the next several quarters, are you going to become more aggressive in your share buyback given how cheap the stock may be?

Well, I think, as you look at us, which is a general cash question, in the volatility we see in the markets today, we will hold more cash than we would have historically. And I've said that, consistently. But when you have crude oil price move $5 to $8 in about a 3-day span, we just think you have to do that today. Now, what is happening with us is obviously, we're having much better financial performance this year. We think many of the things that contributed to this year's financial performance are going to continue next year. And so we're anticipating a good year next year as well. And then we have a very high capital spending. But those strategic projects are coming to an end, and we can see the light at the end of the tunnel. So when you begin to combine our performance, our cash balances, that our strategic projects will be completed, some as -- Mike said right now, some the big hydrocrackers next year. Clearly, we have more cash available. And then, you take the next step and we've demonstrated it here just in this quarter, and going into the fourth, we expect to pay one of the highest dividends among our peer group going forward. We will buy our stock periodically, especially as we think the stock is undervalued. And we, as management, clearly, think our stock is undervalued. As a little side issue or a side comment, the reliance discussion, this rumor that was out there, one of the benefits has been to point out to the investment community, the earnings power of our portfolio and our company. So that was actually a benefit here of a rumor, but we have lots of earnings power. Our projects are coming to an end, and we think our stock is terribly undervalued.

Our next question comes from Faisel Khan from Citigroup.

This is Faisel from Citi. Just back to the Aruba statement. If you can't find a strategic partner or alternative for Aruba, what's the next option after that?

Well – this is Klesse. We continue to improve the operation. We have several things that would reduce our costs, but it is a very good front-end of our refinery that can run very, as I said, heavies and high-TAN crudes. And so we'll continue to improve the operation. And it will be then that refinery, when we run around 200,000 barrels a day makes about 70,000 barrels a day of BGO. And we'll charge that to our hydrocrackers that come on next year. So for us, we see improving its cost structure and using it as a front-end of our refinery. There's 200,000 barrels a day of crude, vacuum coking there that completes our operations.

Okay. I think I understand that. And then going to your Memphis and McKee hydrogen plans, I mean, as those come on line at the end of this year, what do we expect from kind of the uplift going into the first quarter of next year from those plants? What are they going to do to the performance of those 2 plants?

So they're completed by the end of the year and then we'll start them up in the first quarter and we have a table we'll give you and we're looking for it here. Ashley?

Yes, Faisel, it's -- depending on what's price deck you use. We've given pretty much every slide deck for the past nearly a year. We've given them -- example, economic based on different price decks. If you use 2010 pricing, it's an extra $105 million a year of EBITDA, it's when the '11 pricing includes in the 4 curves less a couple of months. It's $150 million of EBITDA and that's incremental. And it's basically because you're making your hydrogen out in natural gas instead of destroying the expensive oil to do so. So you'll see margin uplift and it will basically drop down to EBITDA.

And that table's been in the appendix of our handouts.

Yes, our typical slide decks, which are publicly available to everyone and have been.

Okay, I'll take a look at that. And more on the Ethanol segment that you performed pretty well in Ethanol despite crush spreads coming down over the quarter. What caused kind of margins to go up even though crush spreads kind of came in?

Well, the crush spread isn't necessarily will tell you how to get to EBITDA because our margins are a little bit different because of distillerates [ph] and some by-products you make. We look at our average margin on an EBITDA basis to being about $0.35 a gallon over the quarter -- for the entire quarter. I think if you just look at the financial -- I mean, the markers with corn, ethanol and source rate, it would've been more like $0.30, but I think if corn prices dropped, we got a little bit of extra benefit there just on our corn position. So that we made up if you look at the some of the gallons we made and the numbers that Mike told you earlier, it is right at $0.35 a gallon.

Okay, and is the subsidy expires at the end of this year? I mean, what do you guys expect what kind of take place with your operations go into next year?

Remember, Faisel, it's still mandated. We're blending ethanols in about 91% of the total U.S. gasoline right now. I think that's going to continue. Ethanol is trading above gasoline now for about probably the first time this year as it turns out, we're about $0.35 a gallon over gasoline. So the worst case I look at it right now is if you go back to comparing the gasoline, our current EBITDA on our plants is around $0.69 a gallon. So if we lost $0.35 of that, we'd still have a very positive margin. But like I said it's driven by a mandate so the supply demand exports have been strong into Brazil and to Europe as well, so that's supporting the price. I think it's the supply/demand says that all plants need to run right now, including some of the peripheral plants that don't have a good acorn logistics. So we think that we'll have a good margins at our plants because they're well situated on the corn supply. But right now, margins are just excellent, though.

Okay, and last question for me as -- in theory, if Libya continues to ramp up, you guys have an outlook for the heavy light spreads going into next year?

Yes, I think they're going to continue to be somewhat similar to this year.

Our next question comes from Blake Fernandez from Howard Weil.

What I wanted to ask, what is the current authorization on the share repurchase program?

Okay, we have a Board approved program that is $3.46 billion of authorization.

Okay. Secondly, I wanted to ask about Pembroke. With so much capacity on the East Coast potentially at risk of closure, I guess, my general thought is that, that could be a direct benefit to Pembroke with the transatlantic arbitrage. Am I thinking about that correctly?

Yes, I think you are. This is Gene. Obviously, the European barrels do float to the U.S. East Coast and having that capacity to shutdown is going to create opportunity. However, there is -- it's a whole Atlantic basin market in those, the marginal refineries are going to be under pressure just like they have been this year. So but it does give an advantage to well situated refineries in Europe. We think Pembroke is at that category.

Okay, great, and the last one for you. I know the growth projects was stated that they're all on budget and on time. As I look at kind of first call estimate in 2012 and 2013, it does not really seem like the street is reflecting the incremental call of $2 a share of incremental earnings in these projects. Is there anything in the macro that you see the data puts a risk that number? I mean are we still pretty much on track for an incremental $2 a share from all of these projects?

Yes, I think the main factor is just with the crude in the $100 range for -- and the natural gas are in the $4 range. It gives these projects a good uplift because it's basically a gas to a liquids-type projects as far as the majority of the benefit. So just a crack is kind of a secondary compared to the volume lift you get from natural gas.

And our next question comes from Douglas Leggate from Bank of America.

A quick one fellows on Meraux. Can you just talk about exactly how you're operating that facility, how you plan to integrate it? And I guess really the -- are you trying to actually run the crude unit there or just use the upgrade units? I have a quick follow-up, please.

Yes, this is Gene again. We're basically operating how Murphy was operating before, but we are starting to cash through some synergies, we're going to integrate it in with our feedstock supply, so we pick up some synergies there. We also -- the products, there are a lot of Murphy was using supply their Florida business, we're just using and optimizing our overall system. We find the high cetane of the diesel that's produced there of the hydrocracker, we'll find that some synergies are blending that with St. Charles diesel. Procurement side, I think we'll see some advantages on our purchasing power going forward. So in that affect we're kind of running it as is today, pretty much the way McKee did just on -- I'll take a constant synergy.

[indiscernible] I'll just try one quick one then. Are you planning to change the feedstock at Meraux in terms of -- you've talked about Three Rivers and Eagle Ford and so on. Is there anything you can do to actually change the feedstock there? and how do you get it back?

Yes, right now, we can run medium-sour crude. It runs about 1/3 of sweet crudes, which -- well, we always try to optimize that based on where the light-sweet spreads are. We can go to sour to sweeten up even more if the economic say so. Right now, we're pretty much in this 2/3 sour, 1/3 sweet still.

Our next question comes from Mark Gilman from Benchmark.

A couple of things, if I could. Hey, Mike, did you book any goodwill on the Pembroke deal?

No, we did not.

And the $56 to the -- excuse me, the $53 million that you quoted previously in terms of the contribution in the quarter, I assume that, that's an operating profit number?

Yes, operating income. Operating profit after DD&A.

Okay. How much of that buyback authorization is remaining?

The number that I gave you, the 3.46 is what's remaining. And then in addition to that, we can purchase dilution under our benefit plans.

Okay. Just one more for me, make reference to discounted West Coast crude feedstocks, San Joaquin, Canadian Light, both fuel, more specifically if you could, please.

Yes, it's difficult rates we run out there. It's SJV, KLM, some South American grades like Oriente, Napo, Castilla, all those things actually kept -- had better pricing versus ANS. Versus ANS is the key there, Mark.

Yes, I know ANS is out of the market, all those other crudes seem to be in the market, so is it really discounted?

Well, I mean, if you compare to ANS, yes. It depends on what your benchmark is.

Okay, just let me speak one more. Byproduct benefits in the ethanol side in terms of the grains, seems like they're very substantial, can you help, over and above what Gene had to say a few minutes ago?

Well, the sellers grain do you get about -- only about 2/3 of your corn is converted, about 1/3 of it ends up at still storage grain and that has been a pretty strong market. So I don't have the exact numbers in front of me, but that's the primary byproducts you're producing.

Our next question comes from Rakesh Advani from Credit Suisse. Rakesh Advani - Crédit Suisse AG, Research Division: Just a quick question on Meraux, you guys have a put out in what kind of EBITDA contribution you think will come from that facility?

We have not yet, Rakesh. We have not disclosed it to historical financials.

So we closed October 1, so probably that's a question for the first quarter. Rakesh Advani - Crédit Suisse AG, Research Division: Okay. And just for the 2 hydrocracker projects that are coming onstream next year, can you guys talk about how much disruption there'll be to tie in the 2 projects into your existing facilities? Which kind of quarters will it take place in?

Okay. The Port Arthur hydrocracker will be finished midyear. So we're saying third quarter would start up, then third, fourth quarter. And the St. Charles hydrocracker will be finished by year end, would start up then occurring then, and then in the first quarter. Rakesh Advani - Crédit Suisse AG, Research Division: Okay. So then like should we -- how many days would we assume for the facility to go down or to tie them in? Would it be like -- should we use fiscal over like 30 days or something like that?

We will not go down to tie up time in. Everything will be where ever we have tie-ins, valves are hanger [ph] at things your hot, where ever there are tie-ins. Now if you're asking how long a start-up, these are huge projects, so 2 weeks to 1 month.

That's the base operations are generally going to be unaffected, not like take your big turnaround or something. It will just -- it will be incremental.

Our next question comes from Jacques Rousseau from RBC.

Just wanted to ask you on, if I heard correctly, the guidance for the Midwest volumes for the quarter? I believe you said 430 to 440?

That is correct.

So just curious that looked like a high number. Probably the highest quarter since you have since 2008. I guess, if you could give a little color on what's improved there?

It's still economic infinite to run, but also the last couple of quarters have either had turnarounds or other unseen outages like Memphis had some issues in the third quarter. It probably would've been up around that level, and that was the original guidance range until Memphis had justify a bit affected the crude, I believe. It's -- otherwise, it's what we would have expected.

Great. So outside of the maintenance that you've talked about, this is probably a normal run rate going forward?

That's correct.

Our next question comes from Jeffrey Dietert from Simmons & Company. Jeffrey A. Dietert - Simmons & Company International, Research Division: I was wondering if you -- you mentioned the startup of Pembroke and gave some contributions for the quarter. Could you talk about operations there, if there's anything that's surprised you? Anything that you're dealing differently than the way you perceived Chevron from operating the plant? I think many majors focus on maximizing throughput as far -- rather than maximizing profitability. Any comparisons you can make there?

I think that we will put our own spin into the plant. We're profit focused. We're in this business to make money. But as far as the statement of we run different than Chevron, for instance, Chevron's a very well-run company. So I would tell you just, hey, you're going to see our spin because we intend to make money. Jeffrey A. Dietert - Simmons & Company International, Research Division: Great. Any discussion on exports? I know when we look at the DOE statistics, both gasoline and diesel exports were a record in the most recent month. You're continuing to see gasoline and diesel exports increase what those volumes look like in 3Q and are there any constraints to your ability to export both products?

Well, we see the export market continuing to be very strong and Ashley is going to give you some numbers here.

Yes, in the third quarter, we were up a little bit for gasoline versus prior quarters, up around 75,000 to 80,000 barrels a day, and on diesel side, it was again up from the second quarter up to about 165,000 barrels a day of diesel exports. And the gas has been going where it has been going, pretty much south of the border to Mexico or other parts of Latin America. The diesel has been going to split between Europe and Latin America.

Jeff, this is Gene. Obviously, those are Valero's export numbers, the industry numbers are about 900,000 barrels a day, diesel are in about 500,000 barrels a day of gasoline, if you look at the DOE numbers. Jeffrey A. Dietert - Simmons & Company International, Research Division: Any restrictions in your ability to export more if the market demands there?

No, like I mentioned earlier. We're finding some synergies with Meraux and St. Charles, which typically the past did not export European grade, but by putting those streams together, we're finding out we can make any EN590 or European specs, so we're looking to see what we can do there.

Our next question comes from Paul Sankey from Deutsche Bank.

We put a note earlier this week just showing how tight PAD one markets are. Can you talk a bit about that from your point of view and I'm thinking Pembroke, I'm thinking Colonial, and I'm thinking any other potential you have for going off that market and the analysis we are running was before we had this analysis, so I guess it's -- I assume you'd agree that the market looks extremely tight?

I think, Paul, we don't understand your question. I think we missed a word that must've been missed in a sense.

So I'll just say the whole thing again?

Yes, say it if you like. We must've missed the word.

Okay, it's perfect. Perfect question, honestly -- asking, I should say. Okay, so let's start again. PAD one markets we've analyzed earlier this week, look very tight, northeast distillate markets particularly. And I wondered if you generally agreed with that and to the extent they are tight and to the extent that weather is likely to increase that tightness. I was wondering how from your point of view you can address that, that I'm thinking about the colonial pipeline, I'm thinking about Pembroke and any other access you have if you like to that particular area?

Okay, thanks. What we missed was the PAD one.

Yes, that was an important but I apologize.

It's okay. Gene?

Yes, the PAD one is tied on distillate, but if you look at the Continental Europe, it's also very tight so I think you're going to continue to see the exports from the Gulf Coast go on to Europe. And PAD one just put inventories, yes, they're existing well below their 5-year average and well below last year. So it was the refinery that's been recently shut down there, I think that market's going to be tight, which is going to require high to fairly high utilization rates throughout the weather to supply that market. So I think it's going to be a pretty strong market for distillates going forward.

And volume will be shipped in as well as going to Europe, but -- and then the East Coast.

Yes, so you can ship it for -- obviously from the Gulf to the East Coast because I'm assuming that pipeline capacity is limited from moving it in the other way?

Yes, I am sure, Colonial will go under pro-ratio.

Right, and so they're not going to expect the guesses likely to be higher at distillates margins on the Gulf coast as well?

Yes, the whole Atlantic basin market, like I said with the Europe tied and the East Coast tied, I think there's going to be a demand from Gulf Coast barrels to go rebook those markets.

Great. On -- just on the -- so that's a buyback. Are you stressing 20 as kind of a flow blow, which you buy back stock? Or are you thinking that you’re going to -- or you mentioned that the stock is undervalued and your opinion, is it just being the 20 flow recently and one that you may think about raising if you like, under which you'll buy stock?

I'm not really looking at it that way. It's much more opportunistic, but we did by 13.5 million shares below 20. And we manage our cash, so it's the whole balance.

Yes, okay so we can hope for more buyback going forward regardless of the stock price being above 20.

Clearly, we think our stock is undervalued.

Our next question comes from Chi Chow from Macquarie Capital.

I want to go back out to the West Coast, that was a pretty good results on realized margins given where the crack spread trend ended in this quarter. Was the improvement really just on the differentials you talked about earlier? Did you change up the crudes later at all during the quarter? And Mike, you also mentioned the liquid volume yield improvements, were there operational improvement that you undertook at the plants out there as well?

This is Lane. Operationally, we just came out of a term in our Benicia. So it's performance in terms of liquid volumes are improved versus prior to turnaround, but crude selection is essentially unchanged. We haven't really changed what we're running on the West Coast. It's the same crude value.

But we operated better.

Right.

Okay. California recently finalized their cap and trade rigs. Have you had the chance to take into the details and how you thinking about managing that program going forward?

Well, you can rest assured we've dug into it. We have a very good strategic position on the West Coast. We have very good operations. However, we think state policy, AB32, other fiscal policies, regulations, continue to adversely affect the economy. They adversely affect jobs. They have adversely affected consumer. We think all these policies seem to turn their back on the negative economic impacts. We are hopeful that the voters which consumers will eventually realize that these policies are economically ruining the state. AB32 was of 12-page bill. CARB has now spent over $100 million trying to develop regulations in 5 years. It is a going along policy. The people of California are going to pay. And as to us, we're looking at our options.

So do I take that as meaning that your -- the long-term viability is potentially in question on operating refineries in that state?

We're looking at our options.

Okay. got it. Okay, great. One other question on the Eagle Ford. We've noticed recently that the markers that we track, the pricing on the Eagle Ford crude has changed dramatically in mid-October, it's moved to pricing off a Brent versus previously of WTI. Have you seen this pricing dynamic in the market? And if so, has that impacted your decisions on crude slate down there?

This is Gene. I think if you look at Eagle Ford where prices erode at Brent if it's already on the water area where it could be delivered and compete with the foreign barrel with prices there. I think in the field, it's still pricing and the discounts. It's not at WTI, but still much less than Brent.

Chi, it's going to depend, I guess, the margin barrel that's on the water, of course, it's probably going to price like Brent at this point. But if you're in a field, or if you have a refinery on the field and you've cut deals then you get different pricing, and that's how things work.

So you're talking about Three Rivers versus corporates then, is that the difference?

Absolutely.

But clearly your observation is correct. Take away capacities being built in Eagle Ford, the crude is able to -- more of it is moving to the market. We have raised our postings in order to keep it in the area, but it's still discounted relative to the other crudes. An so, it's still -- we still think Three Rivers and the volume we're going to run at Corpus are going to be very economic crudes bars. And remember, we used to run all foreign crude at Three Rivers.

And our next question comes from Sam Margolin from Global Hunter.

I don't think you've ever done this before, but can you break out Memphis from the Mid-Con group or give like some maybe an assumption of what the Mid-Con realized margin was x that Memphis portion?

We haven't and we really don't plan to, Sam.

All right. Okay. Well, in that vein, on the last quarter's call you gave some indication that you were thinking about maybe a big capital project at McKee, an expansion or something on that order. Is there any progress with that line of thought or still in the evaluative?

Yes, we -- Sam, we have a project. We've engineered at McKee. It's less than $100 million project, but it does let us run more oil. It's a little bit over the same lines that Ashley talked about, the Eagle Ford crude where the refinery is in the field. We're seeing more and more crude discovered and available to the McKee refinery. So we have a project that would let us do that and right now, we're anticipating doing that project. However, it takes 18 months to 24 months to get a permit. We're just about to file our permit application or have filed our permit application. So depending on how long that takes, which is 1.5 years, and then some construction period after that. But the McKee refinery sits right there in the Panhandle we're seeing more crude and this is just a little de-bottlenecking, as I said. It's less than $100 million project.

Your next question comes from Evan Calio from Morgan Stanley.

I don't think you'll going to extend the desolate tightness commentary into China beyond PAD one and Europe. My question is -- it's a follow-up on Aruba and if other than strategic partnerships on heavy-sour crude -- I mean, is it possible you could find a cheaper fuel source instead of burning, I think it's 14% of crude there? I mean is floating rig gas, FSRUs, is that -- is there anything you guys explored?

Yes. We are working a project in conjunction with the government of Aruba in order to bring an LNG. And that project it's been under -- we've been working on it for many months and we're down into the -- where we're getting solicitations on supply right now. And the engineering is largely done. And yes, it has a very favorable economics, both for our refinery, including reliability. And it also is very favorable to the people of Aruba because of their power costs. So exactly correct, and we are working that project. And then on top of that, a little longer-term, I believe it's Repsol is looking as spudding a well there because they believe they're going to find natural gas there as well in the water. So there's many things changing actually all over the world on the CNP side.

That's great. That's good news. And other question if I could just lastly the line 9 reversal is announced to Umbridge Analyst Meeting. Do you expect down the road you could get a lift in Québec and how do you think about that or any partnership to move crude into that market to benefit that refinery?

Yes. We're interested in the line 9 reversal and obviously so is Petro Canada and others. But that only takes the crude oil to Montréal then you have to add some agreement to get it over to Portland. But yes, depends on the differentials between WTI and Brent now, in this case, but yes, we would think it would give us some advantage if we could get that crude.

Our next question comes from Blake Fernandez from Howard Weil.

Bill, I know you've covered the share repurchases, but just one final question on it. Is there a specific goal or target for the number of shares you're hoping to retire?

No, there is not.

Our last question is from Allen Good from MorningStar.

I was just wondering if I can get your current thoughts on your appetite for acquisitions. Or should we take the endue increase, share repurchases and willingness to hold a high cash balance sort of similar to what you've done with acquisitions right now?

Well, I thought I was addressing it, but we're still -- we're a refining company. We also have a marketing operation, Ethanol business and some of the assets are available for our numbers that are attractive. So if it's strategic, if it's accretive, Valero is still interested or is going to look. The last 2 acquisitions that we have done, we purchased for less than where Valero is trading. So we think we can add value. But on the other hand, we're extremely selective and I've said there's no intent whatsoever of issuing equity.

Is Europe still an area of interest or is it just sort of a broad geographic area that you're looking at?

Yes, Europe is still of interest. We've been very public in the fact that we now have established a position there, at least in the U.K. We have said there's a refinery nearby that Valero would be interested in. And -- but otherwise, we're not working on anything in Europe.

We have no further questions at this time.

Okay, thanks, John. I just want to thank investors for listening to today's call. If you have any questions, please contact me or Matt in the Investor Relations department. Thank you.

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