Ashley M. Smith - Vice President of Investor Relations Michael S.

Ciskowski - Chief Financial Officer, Principal Accounting Officer and Executive Vice President William R. Klesse - Executive Chairman, Chief Executive Officer, President and Chairman of Executive Committee Lane Riggs - Senior Vice President of Refining Operations Joseph W.

Gorder - Chief Operating Officer and Executive Vice President Gary Arthur - Corporate Senior Vice President and President of Retail

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division Paul Y. Cheng - Barclays Capital, Research Division Robert A.

Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division Roger D.

Read - Wells Fargo Securities, LLC, Research Division Edward Westlake - Crédit Suisse AG, Research Division Faisel Khan - Citigroup Inc, Research Division Blake Fernandez - Howard Weil Incorporated, Research Division Jeffrey A. Dietert - Simmons & Company International, Research Division Cory J.

Garcia - Raymond James & Associates, Inc., Research Division Sam Margolin - Dahlman Rose & Company, LLC, Research Division Evan Calio - Morgan Stanley, Research Division Paul Sankey - Deutsche Bank AG, Research Division Chi Chow - Macquarie Research Harry Mateer - Barclays Capital, Research Division

Okay. Thank you, Trish, and good morning, and welcome to our earnings call.

With me today are Bill Klesse, our Chairman and CEO; Mike Ciskowski, our CFO; Joe Gorder, Chief Operating Officer; Kim Bowers, our Executive Vice President and General Counsel; and several other members of our senior management team. If you have not received an earnings release and would like a copy, you can find one on our website at valero.com.

Also, attached to the earnings release are tables that provide additional financial information on our business segments. If you have any questions after reviewing these tables, please feel free to contact me after the call.

Before we get started, I'd like to direct your attention to the forward-looking statement disclaimer contained in the press release. In summary, it says that statements in the press release and on this conference call that state the company's or management's expectations or predictions of the future are forward-looking statements intended to be covered by the Safe Harbor provisions under federal securities laws.

There are many factors that could cause actual results to differ from our expectations, including those we 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 a second quarter 2012 earnings of $831 million or $1.50 per share.

In addition, our Board of Directors has authorized company management to pursue a separation of our retail business from the remainder of the company. We believe a separation of our retail business by way of a tax-efficient distribution to our shareholders will create operational flexibility within the businesses and unlock value for our shareholders.

As independent companies, both retail and the remaining business will be better positioned to focus on their industry-specific strategies. We expect to have more details in the coming months.

I should also note that our Board of Directors recently approved an increase in our quarterly dividend from $0.15 per share to $0.175 per share, the highest level in company history. Returning to our second quarter results.

Operating income was $1.4 billion versus operating income of $1.3 billion in the second quarter of 2011. The increase in operating income was primarily due to higher throughput margins in the U.S.

Mid-Continent, the U.S. West Coast and the North Atlantic refining regions, combined with higher throughput at our refineries and higher margins in our U.S.

retail business. These improvements were somewhat offset by lower refinery margins on the Gulf Coast and lower ethanol margins.

Our second quarter refining throughput margin was $10.63 per barrel, which is a slight decrease versus the second quarter of 2011, the margin being $11.41 per barrel. The decrease in refining throughput margin was mainly due to lower discounts on crude oils and feedstocks, lower margins for gasoline in the Gulf Coast and lower margins for other products such as petrochemical feedstocks.

However, we did see higher margins for diesel in all of our regions, except the West Coast, and higher gasoline margins in the Mid-Continent, the West Coast and the North Atlantic regions. Our second quarter 2012 refining throughput volume averaged 2.7 million barrels per day, up 342,000 barrels per day from the second quarter of 2011.

The increase in throughput volumes was mainly due to the addition of capacity from the acquisition of the Pembroke and Meraux refineries. Refining cash operating expenses in the second quarter of 2012 were $3.59 per barrel, which was lower than our first quarter 2012 and our guidance due to higher throughput volumes and lower maintenance expense.

Our Pembroke and Meraux refineries showed significant improvement during the second quarter, combining to contribute over $130 million in operating income. The increase in performance of these refineries is a result of operational improvements we have been diligently implementing since the acquisitions.

For example, at Pembroke, we have improved the feedstock selection, reformulated the SEC catalyst and optimized the product slate and blending. Examples at Meraux include improvements in the ROSE unit operations and in refining optimization.

Subsequent to the second quarter, we had an unfortunate event in late July at the Meraux refinery when a power outage during storms brought the plant down, a fire occurred when restarting the crude unit. No one was injured, but all units at the refinery are currently shut down.

Repairs are in progress and we estimate the refinery will resume operations at normal rates by the end of August. In the meantime, certain units may be restarted while repairs continue.

The impact on throughputs for the third quarter will be reflected in guidance that Ashley will provide in a few minutes. The export market remains solid as our Gulf Coast refineries continue to benefit from low cost of natural gas and increasing access to discounted domestic crude oil.

We believe these competitive advantages enable Valero and other U.S. Gulf Coast refiners to profitably take market share from less competitive Atlantic Basin refiners, particularly in Europe and the U.S.

East Coast. Our retail business had a great second quarter and reported its highest ever quarterly operating income of $172 million, consisting of $134 million in the U.S.

and $38 million in Canada. Our retail business continued to perform exceptionally well.

The Ethanol segment reported $5 million of operating income, which was down $59 million from the second quarter of 2011, mainly due to lower gross margins as ethanol prices were pressured by excess industry supplies. With Ethanol margins under further pressure in the third quarter due to rising corn prices, we recently stopped production at the Albion and Linden plants and have trimmed utilization at the other plants.

In the second quarter, general and administrative expenses, excluding corporate depreciation, were $171 million, which was in line with our guidance. Depreciation and amortization expense was $386 million.

Net interest expense was $74 million and the effective tax rate in the second quarter was 35%. Regarding cash flows in the second quarter, capital spending was $800 million, which includes $106 million of turnaround and catalyst expenditures.

Our expected capital spending for the full year of 2012 is around $3.6 billion, an increase from prior guidance, mainly due to acceleration of certain projects originally scheduled to be completed in 2013. We expect 2013 capital spending will be in the range of $2 billion to $2.5 billion.

Also in the second quarter, we returned $124 million in cash to shareholders as we paid $83 million in dividends and we spent $41 million to purchase 1.8 million shares of our common stock. In addition, we used $862 million to pay down debt and received $300 million from the reissuance of tax exempt bonds.

With respect to our balance sheet at the end of June, total debt was $7 billion, cash was $1.3 billion and our debt-to-cap ratio net of cash was 25.7%. At the end of the second quarter, we also had nearly $4.7 billion of additional liquidity available.

And in July, we renewed and increased the size of our accounts receivable sales facility to $1.5 billion, providing an additional liquidity of $500 million. We continue to make progress on our key growth projects.

Our Port Arthur hydrocracker project is on track to be mechanically complete during the third quarter of 2012 and is expected to achieve full operation during the fourth quarter of 2012. The St.

Charles hydrocracker project is expected to reach mechanical completion by the end of the year, with full operation in the second quarter of 2013. Through our recent actions to increase the dividend and the potential separation of our retail business, it is clear that we are working to maximize shareholder value.

We look forward to the improvement in our free cash flow from the planned decline in our capital spending, the expected contribution from our growth projects and the favorable industry trends that continued to accrue to our assets. So now I'm going to turn it over to Ashley to cover the earnings model portions.

Great. Thanks, Mike.

In modeling our third quarter operations, you should expect the refinery throughput volumes to fall within the following ranges: Gulf Coast at 1.43 million to 1.47 million barrels per day; Mid-Continent at 430,000 to 440,000 barrels per day; West Coast at 265,000 to 275,000 barrels per day; and the North Atlantic at 430,000 to 450,000 barrels per day. Refining cash operating expenses in the third quarter are expected to be around $3.85 per barrel.

Regarding our ethanol operations in the third quarter, we expect total throughput volumes of 3 million gallons per day and operating expenses should average approximately $0.36 per gallon, including the $0.04 per gallon for noncash 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, and net interest expense should be around $70 million.

Total depreciation and amortization expense in the third quarter should be around $395 million. Our effective tax rate in the third quarter should be approximately 37%.

Trish, that concludes our opening remarks. We will now open the call for questions.

So fellows, the -- my question, I guess, is on the step-up that you're expecting on free cash flow. Your dividend, even with the increases, is -- if I'm not mistaken, is somewhere around $400 million a year.

It's fairly -- it's still fairly small. So I guess I'm trying to understand what is the priority for the use of cash?

And then answering that should give us an idea of what you think the right debt-to-cap level is for the -- for this portfolio at this point.

Doug, this is Klesse. Our use of cash, as we're generating more cash and next year, we clearly expect to be generating more cash, is first, we're going to maintain our investment-grade credit rating.

Second, we're going to hold a little more cash than historically as we have it just because of the volatility in our business. You watch the screens, you know how much things move, so we just think we need to hold some more cash.

And then we've been very clear, we're going to return additional cash to the shareholder. And having said that, on the last 1.5 years, we've paid off about $1.5 billion of debt.

And next year, we have $460 million or so of debt that becomes due, and our plan will be to pay that off as well. So I think we're demonstrating of returning cash to the shareholders with the previous things I just said.

And you asked, well, what is the proper or our target debt to cap, and I'm just going to tell you, we're going to maintain the investment credit -- investment-grade credit rating and maybe our debt to cap just goes a little lower. And today, it's 25%, I think.

The -- several quick question. Mike, can you tell me what's the working capital and also the inventory in excess of the book?

Yes. The working capital, total current assets are $14 billion, total current liabilities is $10.8 billion and then our inventory above the book value is $6.5 billion.

Do you have a number you can share, what is in your retail business, the taxable base?

Yes, we do. The tax basis in our retail at June 30 was approximately $900 million to $950 million.

So that means that from a tax efficiency standpoint, the offer, if anyone want to buy it, they need to be really high in order for you to feel comfortable because it's going to be a huge tax buy?

I think you have -- this is Klesse. First off, we need to establish, we have about $500 million of EBITDA from this business and Mike can walk you through that.

You have to consider some overheads. And we have the split between Canada and the U.S., so we have certain tax issues in each jurisdiction.

That's why we're very carefully saying we're going to work a tax-efficient distribution. However, and I know on this phone call, we have a refining analyst, but if you'll look at the freestanding retail companies, certainly Couche-Tard and Casey's, you'll see that their multiple is up around 10, and today our EBITDA multiple is around 3.7 or a little less than 4.

So if we -- and let's stop and look at our retail business. We're very well run, we're excellent financial performers, they've had very good returns, we're extremely well located, with nearly 2/3 of the units access, in the U.S.

And in Canada, we have an excellent market share in Québec. We own a lot of units.

They're not leased. And if you look at our data, which we'll provide, you'll see that many of our units are owned.

So the whole business is an extremely solid business. So then it's your job to, okay, what is the correct EBITDA ratio for this business, and I'll tell you, we're up there with the very best, if we're not the best.

And so the number becomes large. So that's why we've been very clear about tax efficient's been, however, all options are on the table.

Sure. Bill, is ethanol going to stay with Valero or is it going to go to the retail?

Ethanol stays with Valero. We're really a wholesale provider, a plant operator producing ethanol.

Retailer is the marketing business.

Paul, it's Ashley. Just 2 things.

First of all, if you want any more of the balance sheet items, that's now on Page 5 of our earnings release tables.

Okay, great. And 2 final one.

One, that is an interesting development. Someone put the refinery into a variable MLP.

I don't know if you guys have looked at that and whether that this is something fundamental. Do you think that you're really against it or that you think that it could be interesting?

And then finally that, acquisition is -- how important is that a part of your strategy for the next 1 or 2 years?

Okay. So on the variable MLP, of course, we've looked at it.

We watched what happened to one of the other refining companies, and we're open to increasing long-term shareholder value. On the other hand, having said that, we saw how this traded and we don't really think, and I don't know what it is today, that a 19% yield is really providing the value to the shareholders.

So in the sense of values all around, what the assets worth and then the return. So I think it remains to be seen whether that's really something that's in our shareholders' interests.

And then on acquisition, we look at assets that are in the market. But today, there's really nothing happening.

And we have confidentiality agreements, obviously.

A couple of questions. One is just quick and that is, do you have an estimated repair cost for Meraux?

And then a more conceptual question, and forgive me for this being of a conceptual nature, but Bill, if we entered into a scenario where the Gulf Coast coking margins came under pressure and that is the spread between, say, LLS and Maya came down to a minimum level, how low could that go and still have cokers operate on the Gulf Coast, whether in your own portfolio or others? And really, where I'm going with that is, trying to reconcile with you that LLS comes under pressure, which I think you all may subscribe to.

And also a view that I think you have that the coking margins are maintained at a level that continue to support continued coking utilization rates.

So Robert, on the repair costs of Meraux, about $10 million. We're going to start some of the units up here in the next week or so, but the full plan won't be up, like Mike said, until probably the end of the month.

And then -- so coking margins, I've given in the sense into a sunk coker, I believe that you can get somewhere down in 8% to 9% -- somewhere not much lower than 8%, I think, you agree? And know a sunk coker.

But then what we've done in the past and some of the people on the call will remember, as other companies did, when coking margins came under pressure several years ago, we started to produce more fuel oil [ph]. It was more economic to make fuel oil [ph] and cut back on coking.

And so I'm sure that if such a situation happened, you would see us start to spare cokers, just like our competitors would, putting as much light into the units as we can and optimizing it daily, but it's sunk coker. I've been very clear in my opinion that after [indiscernible] of this plan, you're not going to see grassroots coking built on the U.S.

Gulf Coast. Something's going to happen to dramatically change.

And yes, we do subscribe to the fact that we do believe LLS is going to sell us the Brent and we're saying, I guess, that pretty well next year, you're going to push out all the light sweet crude out of the U.S. Gulf Coast.

It seems like as long as you're still pulling in some imports, it gets that Brent support for relative parity and maybe you have sort of a gap down once you push out that last barrel. Is that the right way to think of it as sort of binomial rather than a ratable price degradation?

Well, I see your point. So you still have some light sweet imports into the East Coast, but on the Gulf Coast, I think it will just be mediums and heavies, and it's where you draw the line.

And I think you're still going to see the freight advantage, at least, of $2 or $3 versus Brent. And -- but that's why this whole conversation is the reason that Valero is very supportive of bringing Canadian heavy sour crude oil to the U.S.

Gulf Coast. Then I think it'll price where you can still put it into a SUN coke.

And just so I understand your number, you said 8%. I'm assuming that's a rate of return on a SUN cost and a coker.

What spread do you assume to get that return?

Oh, it would be 8% of the price of oil. I was trying to put it in terms -- because it moves around on us and it does -- it is dependent because of the liquid volume loss as to the absolute price of oil.

So yes, 8%, I'm saying of the price of -- $100, you need at least -- be at least at $92, I guess. Now it's into a sunk coker, and you're not making much money there.

I guess, just to hit on the retail a little bit. I mean it seems like as an industry overall, the thought always seems to be, be vertically integrated.

Can you address maybe a little of how this spinoff would affect that aspect of the business for you?

Well, this is the company-operated retail that we're talking about in the United States. And in Canada, it's our company-operated retail, but we have a little different business model in Canada.

We actually manage the street price even where we have our agents. But also in this segment, includes our home heat business that's in Canada and our cardlock business.

But we have, on top of that, a wholesale marketing business. So this, if you add this up, it's 1,027 units in the States and 775 units in Canada.

But in addition to that, we have 4,000 branded Valero outlets, and we will still run a branded, wholesale business. So if you think of Valero then after the spin of our retail company or separation, whatever transpires, Valero's really going be a refining and wholesale marketing company with some petrochemical feedstock production, ethanol production, power generation, hydrogen and associated logistics, so we're just a manufacturing company with a wholesale marketing business.

So we're still vertically integrated. We just don't have in the States, about 120,000 barrels a day of our production that's actually going through the hose.

And then we're not going to be selling twinkies and beer and cigarettes. We're going to leave that to the retail group.

Well, there's a lot to be said for twinkies, beer and cigarettes, I'm sure.

There is, quite frankly.

A separate question, I guess. If you get some proceeds from the EBITDA of the -- from the retail spinoff and also as your free cash expense from your CapEx reduction and also the EPS uplifts, is there any debt that it makes sense that you should bring in early, I'm thinking about restrictive covenants or just that you feel you could reprice at a low rate?

No, there's not really any debt that we have that would make sense to try to prepay it or bring it in early or call it.

Yes, and we actually did a little of this last year, where we cooked the stuff that was -- some of the debt that was economic for us to take off the market, we did.

All right. And then the Gulf Coast margins, I mean, obviously, globally you make the point that product inventories are low.

It's just surprising, given the weak economy, that margins are so strong. I mean any thoughts as to the sustainability of the margins?

Well, we do think they're sustainable in this sense. Now they move seasonally and every other factor that I spoke about and volatility in our business.

But our business, whether it's Valero or any of our competitor, anybody in the refining business, exports are a key part of the future for the U.S. refining industry, and there is -- from the U.S.

Gulf Coast and we're very competitive. You have personnel that has terrific skill sets and very productive.

And then we have low-cost natural gas and we're going to have a crude advantage, that's beginning to materialize significantly. So there's no question if you're a Mid-Continent refiner, you're making a lot of money and that's good and we benefit from that at a couple of our plants.

But we believe that you can compete in the world market and certainly in the Atlantic Basin even by coming out of the U.S. Gulf Coast.

And so -- but exports are a key part of it and they're allowing our whole industry to operate at a higher operating rate. Domestic demand, as you properly stated, is not very strong command and that reflects a very slow economy, even though it's growing and very high unemployment.

Companies like Valero, over 80% of our output is fuels. And if people aren't working, you just aren't consuming the fuels.

And then a final question, just my impression is that you have a high degree of turnaround costs and activity in the first half of this year. Do you expect that 2013 will be a sort of a lighter turnaround schedule as a result, as you look forward in your plans?

We did have high turnaround this year. This is Lane Riggs.

He's going to answer you.

Yes, I would say next year, we had a big refiner -- we had a large refiner turnaround at Québec in the first quarter of next year and we have some other -- we have a big turnaround -- we had a recently large turnaround at Corpus Christi City also in the first quarter. So it stays roughly about the same size in the first quarter of next year versus this past first quarter --

So for us in turnaround and catalyst, in seems to be running about 500 million...

Million. That's right.

And that's -- it moves up and down a little bit around there, but around 500 million a year. And catalysts costs have come down some this year.

Can you guys give us an update on Aruba? I believe you guys have an offer there and any associated inventory levels you have there that you've either liquidated or holding onto for the sale of the asset?

Well, in Aruba, the only inventory, really, out there now is for our other businesses, where we're taking advantage of [indiscernible]. So we don't have any inventory per se associated with the refinery, except that we do provide fuel oil to the utility and we also provide gasoline and diesel to the island, so -- which is part of our marketing distribution effort there.

But basically, we have no inventory there that's in support of refining per se. And then as far as Aruba, we're still working the transaction.

We did disclose most of the information in -- I guess it was last quarter's 10-Q.

In the 10-Q, yes.

And we're still working the transaction and the government of Aruba is extremely supportive. And we'll see how it turns out.

Okay. Then on St.

Charles, with the hydrocracker, I believe that the hydrocracker was supposed to be up and running in the fourth quarter, if I remember from some of your previous sort of presentations. But it looks like now it's going to be in the second quarter of 2013.

Am I reading that wrong?

Well, you're not reading anything wrong. I have said the St.

Charles hydrocracker would be finished by the end of the year, and we'd get it up in the first quarter. But now we are going to say it's the second quarter, we'll get it up.

So to be -- this would be my schedule, and to be honest, some of my people will say that this was my schedule, not theirs. But I would tell you, we have slipped a month or 2 on both projects.

However, these are big projects for Valero, each $1.5 billion plus there's some other stuff around it. Our people are doing a terrific job.

If you can imagine the miles of cabling, this is what we're really finishing up at Port Arthur, is miles of cabling, and people are doing terrific. And we just are going to be a month or 2 later.

Just a few quick ones for you on the retail spin. Bill, you mentioned your intention to maintain investment-grade credit rating.

I'm just wondering if the credit rating agencies have [indiscernible] on the spin yet? Secondly, on the retail, is it a strategic situation where the retailer was being starved of capital and as a standalone, maybe they undertake some additional capital projects or higher growth?

And then finally, from a CapEx standpoint, the $2 billion to $2.5 billion next year, could you tell us what the breakout is associated with retail on that?

Okay. So on the debt, I'll just answer you.

No, we have not talked to the rating agencies, but we will because our investment-grade rating, as I said, is very important to us. And we think, we're a very large player in this business, buying today over 2 million barrels a day of crude.

We think that's important for our suppliers to know that we're investment-grade. On the second question -- I'm sorry, what was it, Blake?

Just to remind you, the second question was basically from a strategic standpoint, as a standalone, I guess, was the retail somewhat being starved of capital or are they now allowed to maybe pursue higher growth options?

There is no question that we had a capital budget raise really in the U.S. of about $80 million, and in Canada, it was around $30 million.

We have all the detail that they have both of those businesses have thrown off cash to the parent. And so clearly, as standalone businesses, they will be able to execute a strategy that the management feels is appropriate.

Okay, great. And the third was on the CapEx.

If you could just provide a breakout of next year, $2 billion to $2.5 billion, what portion was associated with retail, please?

Typically, retail spends about $130 million in CapEx for the whole segment, so that would be U.S. and Canada.

My question is associated with product exports. I was hoping you could talk about what you exported on gasoline and diesel in the second quarter and really, what your capability of exporting is.

Is there substantial ability to export more than what you're already exporting and potential for any capital projects that might expand that capability?

Sure. Jeff, this is Joe.

Jeff, in the second quarter, we exported about 165,000 barrels a day of diesel, primarily to Latin America and Europe, with really the bulk of it going to Europe. And the reason that, that number moves around, really, from month to month has more to do with the economics of the [indiscernible] than our ability to do it.

We saw diesel strength adhere domestically, we kept it at home. When the arms [ph] to Europe or to Latin America, we go ahead and put it on the water and move it out.

Gasoline exports in the quarter were 75,000 barrels a day. The bulk of that goes to Mexico, and then also into Latin America.

And we're seeing continued strong demand for both as we go forward. And there's a host of reasons not much has changed in the market which would lead us to believe that those exports weren't going to be there going forward.

As far as capacity, we would estimate that our capacities for gasoline are 250,000 barrels a day, give or take. And on the diesel, 275,000 to 300,000 barrels a day.

And we continue to look at logistics projects. The team has been very active in assuring that we were going to have continued access to export markets and the logistics wouldn't be an issue.

And there's some projects that have been identified, but nothing significant.

So it's a global market business and what happens is the exports tend to pull from domestic supplies. So it's only when pricing is actually better than the domestic market that we tend to export, and it's all driven on economics.

And then the fellows here are telling me that to Roger's question earlier, where we -- I said 120,000 barrels a day in the U.S., but remember, our plan is that this will be a branded job for us and we'll still supply from the refining group to the retail group. I thought it was obvious, but the guys here are saying it's not.

So we'll still sell from refining to a freestanding retail business.

Joe, is Valero participating in West Coast product exports as well?

No, we're not. Jeff, I mean, the barrels that we move -- no, we're not.

Okay. If I could slide in another question, I was curious about the Port Arthur and St.

Charles startups, and is there an impact on existing operator -- operations at Port Arthur and St. Charles or what's exactly involved in this 8-week start-up process?

Could you help me with that?

Jeff, this is Lane. So once our project group hands it over, it's a 6- to 8-week project that just sort of started up.

It really doesn't -- the size is just stacking up and have all the technical people we need to oversee the startup. It doesn't really affect the rest of our operations.

But sort of a breakdown of the 6- to 8-weeks, the first part of it a leak check and do some other things just to sort of get the unit ready, and that could be 2 to 4 weeks. Then we got to load the catalyst.

There's 2 million pounds of catalyst we got to load in this thing. After that -- and then after that we have to prepare and condition the catalyst, which can take about 2 weeks, so that's really all the things that we have to do to get ready to put oil in.

I just have, I guess, a quick question with regard to Meraux. Obviously, recognizing that the current focus is going to be bringing that online, back online safely, following the incident, but just want to maybe get a little better understanding on the potential integration between that plant and St.

Charles. I know that was sort of a talking point when you guys purchased the refinery.

Aside from any sort of feedstock and product optimization between the 2, are there any other sort of hardware or larger integration efforts that you guys are currently working on?

Yes, there is. At Meraux, what we intend to do is install another reactor and we will convert some of the process units so that we can make more distillate.

So if you look at Valero's system, today, we make 33%, 34% distillate. Obviously, the margins are in distillate.

Distillate is growing in the world much more rapidly than gasoline. And with our 2 big hydrocrackers that get finished this year, we'll be up to 39%, 40% distillate yield.

Actually, one of the highest in the industry in the U.S. And then we have this project we're working on, Meraux, which will take us another 1.5 years to 2 years to complete.

Installing this reactor, that will allow us there to make a much higher distillate yield. And so you will see that refinery produce distillates as opposed to gasoline in the long run.

And then we'll integrate the gas oils between the 2 facilities. We have an [indiscernible] plant there that we might have some integration opportunities with all the butanes we're seeing coming into the market.

So there's a lot of opportunity on the U.S. Gulf Coast for all of our plants to work together and we optimize it as a system as best we can.

I just had a -- could you give us a quick update on Eagle Ford volumes and to Three Rivers and maybe even elsewhere now that some infrastructure gets built out down there?

Sure. In the second quarter, we ran just over 140,000 barrels a day of Eagle Ford crude.

Of course the bulk of that was at Three rivers, and then down at Corpus Christi. One of the interesting things is, is that we're running a lot more Bakken now.

We're running about 130,000 barrels a day at Bakken, and a lot of that is going out into the Memphis refinery.

Okay, great. Yes, I did notice that Midwest margins were higher year-over-year.

I assumed there was something going on in Memphis with the crude slate, so that's helpful. Secondly, this is a bit of a longer question, but there's been some acceleration of discussion of RFS mandates in the media.

Assuming that the government is going to be pretty slow on this or resistant, is it your understanding maybe from intelligence that you have on the ethanol distribution side that the industry is in possession of a surplus of credits and the gasoline market can effectively tighten as blending reduces, even without changes in the mandates in the near term here?

Okay, I'm not sure we're going to know that, RINs are at $0.04, so that doesn't necessarily imply that there's an excess of RINs. I'm going to say -- but I know this is an issue for everybody on the call.

Yes, we're in the ethanol business, but there's 8000 barrels a day of ethanol going into the gasoline pool. So by the mandate, you took market share from refiners and gave it to farmers.

Now -- but to eliminate that is extremely difficult, and we've had almost $8 corn, I think, a couple of years ago. But remember, ethanol has high octane.

Under the EPA rules, we get a 1-pound waiver. So we have tankage, system limitations, CARBOBs, RBOB, CBOB, this is a far more complicated conversation than having the hog farmers in Washington asking for a release.

I apologize if I missed it. I jumped in a little late.

Any timing estimate on the retail spinoff and how you think about appropriate leverage on that asset coming out? And then I have an additional question.

Yes. We are still evaluating the leverage and how much leverage to place on that.

I mean it'll be comparable to the other C store companies in that segment. As far as timing, around 6 months, we could probably do the spinoff.

We've got a lot of work to do yet with our SEC filing and we need a private letter ruling, so let's just say around 6 months.

That's great. And then another question.

I know you've had an additional quarter to kind -- to think about it and even witness a temporary widening on Brent LLS spread and any new thoughts as your engineers have spent maybe another quarter analyzing an ability to either run or make any investment to shift your slate a little bit to the lighter side?

Well, we're -- so on the U.S. Gulf Coast, where we tend to be a heavier refiner, now Three Rivers is relatively light, Houston is light, Memphis runs are basically Gulf Coast light barrels.

So really, for us Texas City, Port Arthur, St. Charles, and even Meraux, we are looking at obviously being able or having the capability to run a higher percentage of lighter oils.

And our people are working on these, and -- but the issue in our business is if it's deemed that we need a permit, permitting is very long now. And if it has to have a CO2 permit, it's even longer.

So -- but we are working on all this, I'm sure just like every one of our competitors.

I think you covered a lot of the questions I had, particularly on ethanol. I was going to ask, but obviously you slightly covered that.

I'm still not quite clear how you see the market playing out here if we don't have enough RINs. And then the shortage of ethanol, could we -- can you simplify the answer on that one?

Well, right now, there is not a shortage of ethanol. But plants are cutting back.

We, as Mike said, have shut down 2 plants, we've cut back the others. We're probably running at 50%.

If you look at the numbers, it was about 19 million barrels of ethanol. It's dropping rapidly.

So you want to know how I think it plays out? So this is how I think it plays out: I think ethanol price is going to go higher here relative to gasoline.

And because obviously, today, we're losing money in ethanol.

Sure, but then you have to meet the mandate. I guess the question is are you going to meet the mandate?

Well, not you, but I mean, the industry.

That is a valid question. About 93% or so of all the gasoline sold in the country has ethanol in it and we're going to hit the blind wall here, gasoline volume is down, RINs are at $0.04.

I don't know if I can answer you.

Yes, well, and Paul, there's one thing that you can take into consideration. We carry forward 20% of the RINs from last year to this year, so I don't think that we're looking at an issue this year.

But in the out years, as the obligations continue to go up, it is going to be a challenge and RINs are going to be more expensive.

Yes, that's helpful. The -- on -- forgive me if you've kind of feel like you've covered this.

But on M&A, particularly I'm thinking about BP saying Texas City and Carson [indiscernible] available for sale and people are interested, do you have anything to add on that?

I really don't. I've said in the past that we have looked at it and we have a confidentiality agreement, but the thing is still on the market.

Bill, I want to go back to this topic on the global distillate export market. I know there's been outright refinery shutdowns in the Atlantic Basin on the less competitive plants.

But it looks like -- on our analysis, it looks like there's potentially 8 new hydrocrackers, including your 2, set to come online in the Atlantic Basin over the next 12 months. Can you comment on -- and by the way, that's about 400,000 barrels a day of capacity from what we see, can you comment on what you see the potential impact on supply/demand balance on the distillate market in the Basin going forward here?

Well, I think there are hydrocrackers coming on, as you say, so there's no disagreement there. Some of those are in the Med.

I think the Med is different than Northwest Europe, so I do think that there's a difference. I look long-term, and I see a lot of pressure in the Mediterranean for making money in Refining.

But in the Atlantic Basin, we still have growth, Mexico, Colombia, Brazil. You saw, I know you know, Chi, that the sugarcane harvest is bad in Brazil, so they are going to wind up importing more gasoline.

And I know you asked about distillate, but we believe that we will still competitively be able to go into these markets. Whether Mexico builds the Tula refinery, I think, is a very open question, especially with a new government.

The numbers they're talking now about 10 billion or 12 billion for this refinery. You've also seen -- and we're not participating today but we have in the past, actually shift some ULSD to Australia, and you've seen where the Australians are shutting down quite a few refineries.

So I think it all comes down to the arms, [ph] as Joe mentioned earlier and the economics in the U.S.-produced stuff is going to be in -- on a cost basis, very, very competitive. Whether we can squeeze it into the market, we think we'll be able to.

But you're clearly right that there are hydrocrackers being built. Everybody sees this distillate growth.

We just happened to be in a good spot here. I wish I had the hydrocrackers today, right?

That's right. Can you expand a little bit on the difference between the Northwest Europe market and Med, what is the critical difference there between the 2?

Because I think some of this -- longer term, you're going to see supply come from the Middle East into the Med. And demand, obviously, if you -- I know you look at all this stuff, look at the Italian demand and some of the Greek demand numbers are -- so I mean they're just very, very long refining.

So you have a very long refining situation on top of some competition coming from the Middle East.

Yes, it just seems a bit concerning with Europe, the situation there with demand, China slowing down. And does it really get down to Latin America, South America just staying strong for this export market to kind of keep going here?

In this -- so I would like to hope that Europe does eventually recover, but I can't argue that it might. So I would say it does come down.

And when Joe spoke, our gasoline exports go to Latin America and about half of our distillate exports go to Latin America.

And in Australia, are you sending out of the Gulf Coast?

That was a couple of years ago, and we did send some out of Gulf Coast.

And one final question. It looks like, looking at your stats, that your Gulf Coast light sweet crude run has actually got up to 240,000 barrels a day this quarter.

I think last quarter you said your -- the capacity was around 200,000 a day. Are you finding ways, obviously, to get more of that crude into your system?

No, but we're finding ways. Our capacity, we actually had -- we said that's what we were running.

The 200,000 was not our capacity last quarter. That's actually what we were running.

But we're going to continue to close that gap. And this is based on economic availability and then economics.

If the discount's large enough, then you can get enough of it. You'll -- it'll make sense versus some marginal medium sour, but these are the economics that we're working with and we'll just continue to increase that.

So what is your capacity then in the Gulf Coast right now on the light sweets?

Yes, 0.5 million barrels a day.

Does that -- includes Memphis, though, right?

That would include Memphis.

Two questions. First, you answered a few questions on investment-grade ratings.

I was just wondering if you could put a slightly finer point on it. And specifically whether your current ratings or what's important to you, mid-BBB or is it just investment grade so you guys might be willing to go down the low BBB as part of this retail separation?

And then the second question, what's the priority for you in terms of considering the retail separation, is it maximizing the amount of cash you take out of the business or is that less of a focus given Valero's liquidity disposition?

Okay. So on the first question, we don't see any reason at all why there would be any concern about our rating, but we want to be investment-grade.

I'm just going to leave it at that. And then -- and we'll work with the rating agencies if they have any issue.

But I gave some other data points for how much we paid off here [ph], our coverage ratios and everything looked very, very good. And then on the -- on the second question, it was...

Cash priorities.

Yes, the priorities are kind of -- in this spin sale, we want to do a tax-efficient spin. We are working on shareholder value, as you would expect us, so we want to maximize our shareholder value.

And so it's a point of being tax-efficient and generating shareholder value.

I think I actually got cut off earlier, Bill, I apologize for -- I was talking to myself there for a couple of minutes. Nothing unusual there.

So my couple of follows-ups were basically, can you walk us through the timing of the -- or how you would expect to take the cash tax benefit of the mechanical completion credit that you'll get for the 2 projects? And then I do have a follow-up before I get cut off again.

Okay. On the timing of those benefits, we're estimating the benefit of $650 million to $700 million.

The timing would be spread out over the next 4 to 5 quarters, and a lot of that depends on, obviously, the profitability of the company over the next 1.5 years. So I'm just going to say, probably over the next 4 quarters, we'll receive all that benefit.

So starting in third of 2012?

That's correct.

Okay, great. And my final one, then, is I wanted to go back to Robert's question about LLS discounts, potentially versus Brent.

In terms of your optionality of being able to run medium and heavy and sour crude in the Gulf, how would you expect, if you, let's say, you did increase your LLS runs, or your light sweet crude runs, domestically more than perhaps your coker limitations would dictate, how would you expect the pricing of medium and heavy sour to move? And what I'm kind of getting at is that our thinking is if LLS moves, that probably benefits your medium and heavy feedstock as well.

I'm just trying to get some color as to whether that's the right way to think about this or not.

No, Doug, I do think that's the right way to look at it. Certainly, the medium sours will be tightly linked to the light sweet prices.

Heavy sours, I think, are going to be competing with medium sours for space in the refinery. And so as we get more supply into the Gulf, I think what we're going to see is kind of a downward pressure on the entire complex.

And Bill mentioned what the discounts needed to be on heavy sour crudes relative to light sweet crudes. You need at least 8%, so you're going to see those have to price in if they want to move into the system.

I would add that, so what happens then is LLS is discounting the Brent, then you're going to have these other crudes discounting and that this -- but it's on the world market, which is pricing against Brent, so the freight becomes the factor. And we know that some Venezuelan crude and Mexican crudes have been moving to China and other places and Venezuelan crudes moved to China, so you wind up with a freight being the flywheel in there, and of course, available tankers.

But -- so there'll be a limit for how wide that spread goes then relative to freight. And that's why, I think, we see LLS at a couple of bucks, which is really the freight that tends to be the driver here.

So Bill, theoretically, that couple of bucks would translate -- and I'm not trying to be too simplistic here, but to your entire Gulf Coast fleet, is that the right way to think about it?

Yes, I think that is right, and that's why we say the U.S. refining industry, it's not necessarily Valero, is in a very competitive situation in the world.

And that's why going back to several of the other questions, we believe that the U.S. refining industry can be competitive in the export markets when we face the domestic demand that is challenging.

So it applies to Valero, but it's applying to our industry.

Just 2 quick follow-up. One, Bill, when you're looking at your retail network in July month-to-date, what is your same-store gasoline sales?

Secondly, that what is your total WTI link crude that you run in the second quarter?

Okay, so let's do the crude link first, Ashley, WTI link crude, how much we run in the second quarter?

In the second quarter, it's still right around 250.

But I mean you also running Bakken, in Memphis, right, so it seems like you say you run about 140. So shouldn't that now be more like in the 350 to 400 then?

No, no, because the Bakken crudes that we run at Memphis actually comes from St. James.

It's priced like LLS.

It is out of discount, the LLS and the deals that Joe's people have done, but it -- we don't have the receipt facility so it tends to go to St. James and come back up Capline.

That's the answer to that. Now Gary Arthur's here and your question was in July same-store volume?

That's correct.

We're down just a little bit under 3% same-store on gasoline.

That's in the U.S.

Okay. Thanks, Trish.

And thank you, investors and analysts for listening and if have any questions, just contact Valero's Investor Relations department.