瓦萊羅能源 (VLO) 2012 Q2 法說會逐字稿

Welcome to the Valero Energy Corporation reports second-quarter 2012 earnings conference call.

My name is Trish and I will be your operator for today's call.

At this time, all participants are in a listen-only mode.

Later we will conduct a question-and-answer session.

Please note that this conference is being recorded.

I would now like to turn the call over to Ashley Smith.

Ashley, please go ahead.

Thank you, Trish and good morning.

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 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 will turn the call to Mike.

Thanks Ashley and thank you for joining us today.

As noted in the release, we reported 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 cents 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 US Mid-Continent, US West Coast, and the North Atlantic refining regions combined with higher throughput at our refineries and higher margins in our US 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 feed stocks, lower margins for gasoline in the Gulf Coast, and lower margins for other products such as petrochemical feed stocks.

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 at these refineries is a result of operational improvements we have been diligently implementing since the acquisitions.

For example, at Pembroke we have improved feedstock selection, reformulated the FCC 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 natural gas and increasing access to discounted domestic crude oil.

We believe these competitive advantages enable Valero and other US Gulf Coast refiners to profitably take market share from less competitive Atlantic basin refiners, particularly in Europe and the US 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 US 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 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 share holders 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 continue to accrue to our assets.

Now I'm going to turn it over to Ashley to cover the earnings model portions.

Great, thanks, Mike.

For 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 $0.04 per gallon for non-cash costs such as depreciation and amortization.

With respect to some of the other items for the third quarter, we expect G&A expense, excluding depreciation to be around $175 million, 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.

Thank you.

We will now begin the question-and-answer session.

(Operator Instructions)

Doug Leggate, Bank of America.

So fellas, my question is on the step up you are 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 still fairly small, so I guess I'm trying to understand what is it priorities to the use of cash.

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

Doug, this is Klesse.

Our use of cash as we are generating more cash and next year we clearly expect to be generating more cash is first we are going maintain our investment grade credit rating.

Second, we are going to hold a little more cash than historically as we have it just because of the volatility in our business.

You watch the screen, you see how much things move so we just think we need to hold more cash.

And then we have been very clear, we are going to return additional cash to the shareholder.

Now having said that on the last year and a half we 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 is to pay that off as well.

I think we were demonstrating a return of cash to the shareholder with the previous things I just said.

And you ask, well, what is the proper or target debt-to-cap?

I'm going to tell you we will maintain the investment grade credit rating, and maybe our debt-to-cap just goes a little lower.

And today it's 25%, I think.

Paul Cheng, Barclays.

Several quick questions.

Mike, can you tell me what is the working capital and also the inventory in excess of the book?

Yes, working capital total current assets are $14 billion.

Total current liabilities is $10.8 billion.

Then our inventory above the book value is $6.5 billion.

Thank you.

Do you have a number you can share what is your [weed-out] business, taxable base?

Yes, we do.

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

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 bite?

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 and you have to consider some overheads.

And we have this split between Canada and the US, so we have certain tax issues in each jurisdiction.

That's why we are very carefully saying we will work a tax efficient distribution.

However, and I know on this phone call we have the refining analysts, but if you'll look at the free-standing retail companies, certainly [Kustard and Kasich], you will see that their multiple's up around 10 and today our EBITDA multiple is around 3.7 or a little less than 4. And let's stop and look at our retail business.

We are very well run.

We are excellent financial performers.

They've had very good returns.

We are extremely well located with nearly two-thirds of the units in Texas in the US and in Canada we have an excellent market share in Quebec.

We own a lot of units, they are not leased.

If you look at our data which we will provide you will see that many of our units are owned.

So the whole business is an extremely solid business so then if you jump to, okay, what is the correct EBITDA ratio for this business and I will tell you we are up there with the very best if we're not the best.

So the number becomes large.

That's why we have been very clear about a tax efficient spend.

However, all options are on the table.

Sure.

And curious, ethanol, going to stay with Valero or is going to go to the retail.

Ethanol stays with Valero.

It's a fuel, we're really a wholesale provider, a plant operator producing ethanol.

Retail is a marketing business.

Sure.

Paul, it's Ashley.

Two things.

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

Okay.

Great.

And two final one.

One that is an interesting development.

Someone put a refinery into a variable MLP.

Don't know if you guys have look at that and whether that this is something fundamentally you think that you are really against it or that you think it could be interesting.

Then finally, that acquisition, how important is as a part of your strategy for the next one or two year.

Thank you.

On the variable MLP, of course, we've looked at it and we watched what happened to one of the other refining companies.

And we are 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, at a 19% yield is really providing the value to the shareholders, in the sense of values all around, what the asset's worth, and then the return.

So I think it remains to be seen whether or not that really something that is in our shareholders' interest.

Then on acquisition, we look at assets that are in the market.

But today there is really nothing happening and we have confidentiality agreements, obviously.

Robert Kessler, Tudor, Pickering.

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.

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 and others?

Where I'm going with that is trying to reconcile a view that LLS comes under pressure which I think you all may subscribe to.

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

So Robert, on the repair costs of Meraux, about $10 million.

Okay.

And we are going to start some of the units up here in the next week or so.

But the full plant won't be up, like Mike said until probably the end of the month.

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

You agree?

Yes.

Into a sunk coker.

Then what we have 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.

It was more economic to make fuel oil 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 have been very clear in my opinion that after Motiva's plan, you aren't going to see grass roots coking built on the US Gulf Coast.

Something is going to have to dramatically change.

Then, yes, we do subscribe to the fact that we do believe LLS is going to sell less than Brent.

Sure.

And we are saying, I guess that pretty well next year you are going to push out all of the light sweet crude out of the US Gulf Coast.

It seems like as you are still pulling in some imports, it gets that Brent support for relative parity and maybe you have a gap down once you push out that last barrel.

Is that the right way of think of it as binomial rather than a ratable price degradation?

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 are still going to see the freight advantage at least of $2 or $3 versus Brant.

But that's why this whole conversation is the reason that Valero is very supportive of bringing Canadian heavy sour crude oil to the US Gulf Coast.

Then I think it will price where you can still put it into a sunk coker.

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

What spread do you assume to get that return?

It would be 8% of the price of oil.

Got you.

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 8% I'm saying of the price.

$100 you need at least, to be at least a $92 I guess, in that range.

Now it's into a sunk coker and you aren't making much money there.

Okay.

Thanks for that.

Roger Read, Wells Fargo.

I guess just to hit on the retail a little bit.

Seems like as an industry overall the thought always seems to be, be vertically integrated.

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

Well, this is the Company-operated retail that we are 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 to street price even where we have our agents.

Also in this segment includes our home heat business that is 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 is really going to be refining and wholesale marketing company with some petrochemical feedstock production, ethanol production, power generation, hydrogen, and associated logistics.

We are just a manufacturing company with a wholesale marketing business.

We still are vertical integrated.

We just don't have in the States about 120,000 barrels a day of our production that's actually going to the hose.

We are not going to be selling Twinkies and beer and cigarettes.

We are going to leave that to the retail group.

There is a lot to be said for Twinkies, beer, and cigarettes, I'm sure.

(laughter)

There is, quite frankly.

Thank you.

Thanks, Roger.

Ed Westlake, Credit Suisse.

Congratulations on the move -- or discussion of the move this morning.

A separate question.

If you get some proceeds from the EBITDA of the retail spin-off and also as your free cash expense from your Cap Ex reduction and also the EPS uplifts.

Is there any debt that it makes sense you should bring in early?

I'm thinking about restrictive covenants or debt that you feel you could reprise at a low rate.

No, there is not really any debt that we have that will make to prepay or bring it in early or call it.

Right.

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

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

It's surprising given the weak economy that margins are so strong.

Any thoughts as to the sustainability of the margins?

We do think they are sustainable in the 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 US refining industry, from the US Gulf Coast.

And we are very competitive.

You have personnel that has terrific skillsets and very productive.

And then we have low cost natural gas.

And we are going to have a crude advantage that's beginning to materialize significantly.

So there is no question if you are Mid-Continent refinery you are 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 US Gulf Coast.

Exports are a key part of it and they are allowing our whole industry to operate at a higher operating rate.

Domestic demand as you properly stated is not very strong 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 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 lighter turnaround schedule as a result as you look forward in your plans?

We did have high turnaround this year.

This is Lane Riggs, going to answer you.

I would say next year is we have a big refinery turn -- we had a large refinery-wide turnaround in Quebec in the first quarter of next year.

We have a big turn, a reasonably large turnaround in Corpus Christi and Texas City also in the first quarter.

I would say it's roughly about the same size in the first quarter of next year versus this past first quarter.

For us in turnaround and catalyst it seems to be running about $500 million a year.

That's right.

And it moves up and down a little bit around there but around $500 million a year.

Thanks very much.

And catalyst costs have come down some this year.

Faisel Khan, Citigroup.

Can you guys give us an update on Aruba?

I believe you have an offer there and any associated inventory levels you have there that you've either liquidated or are holding on to for the sale of the asset?

In Aruba the only inventory we really have there now is for our other businesses where we are taking advantage of [performance].

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, which is part of our marketing distribution effort there.

Basically we have no inventory there that's in support of refining per se.

And then as far as Aruba, we are still working the transaction.

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

In the 10Q, yes.

And we are still working the transaction and the government of Aruba is extremely supportive.

And we will 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 the fourth quarter if I remember from some of your previous presentations.

But it looks like now it's going to be in the second quarter of 2013.

Am I reading that wrong?

You aren't reading anything wrong.

I have said St.

Charles hydrocracker will 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 will get it up.

So 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 two on both projects.

However, these are big projects for Valero.

Each $1.5 billion bucks plus there is some other stuff around it.

Our people are doing a terrific job.

If you can imagine, the miles of cabling, which is what we are really finishing up at Port Arthur -- it's miles of cabling.

And our people are doing terrific.

And we just are going to be a month or two later.

Fair enough.

Thank you.

Blake Fernandez, Howard Weil.

Just a few quick ones for you on the retail spend.

Bill, you mentioned your intention to maintain investment grade credit rating.

I'm wondering if the credit rating agencies have opined on the spin yet.

Secondly on the retail, is it a strategic situation where the retail was being starved of capital and as a standalone maybe they undertake some additional capital projects or higher growth?

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

Thanks.

On the debt, I will 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 are very large player in this business.

Buying today over 2 million barrels of crude.

We think that's important for our suppliers to know we are investment grade.

On the second question.

I'm sorry.

What was it?

What was your second question?

Sorry.

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

There is no question we had a capital budget race really in the US of about $80 million and in Canada it was around $30 million.

We have all of the detail.

That they have, both of those business 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.

Great.

Thank you.

The third was on the CapEx, if you could provide the 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.

That would be US and Canada.

Okay.

Thanks, guys.

Jeff Dietert, Simmons & Company.

My question is associated with product exports.

I was hoping you could talk about what you exported 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 are already exporting and potential for any capital projects that might expand that capability?

Sure, Jeff.

Good morning, it's 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 number moves around really from month to month has more to do with the economics of the fuels than our ability to do it.

We saw diesel strengthen here domestically.

We kept it at home when the ARBs open to Europe or 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.

Now we are seeing continued strong demand for both as we go forward and there is 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 is some projects that have been identified.

But nothing significant.

It's a global market business and what happens is the exports tend to pull from domestic supply.

It's only when pricing is actually better than the domestic market that we tend to export.

It's all driven on economics.

And then the fellas here are telling me that, to Roger's question earlier, where I said 120,000-barrels a day in the US, but remember, our plan is that this would be a branded jobber for us and we will still supply from a refining group to the retail group.

I thought it was obvious but the guys here say it's not.

So we will still sell from refining to a free-standing retail business.

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

No, we are not.

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

If I could slide in another question.

I was curious about the Port Arthur and St.

Charles start ups.

And is there an impact on existing operations at Port Arthur and St.

Charles?

Or what's exactly involved in this eight week start up process?

Could you help me with that?

This is Lane.

Once our project group hands it over, it's a six to eight week project to start it up.

It really doesn't, besides just staffing up and having all of the technical people we need to oversee the start up it doesn't really affect the rest of our operation.

But breakdown of the six to eight weeks -- the first part, we have a leak check and do some other things to get the unit ready and that could be two to four weeks.

And then we have to load the catalyst.

There's 2 million pounds of catalyst we have to load in this thing.

Then after that we have to prepare and condition the catalyst which can take about two weeks.

That's all the things we have to do to get ready to put oil in.

Thank you.

Cory Garcia, Raymond James.

I had a quick question with regard to Meraux, recognizing that the current focus is going to be bringing that back online safely following the incident.

Just wanted to get a little better understanding on the potential integration between that plant and St.

Charles.

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

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

Yes, there is.

At Meraux, what we intend to do is install another reactor [technical difficulty] and will convert some of the process units so we can make more distillate.

So if you look at Valero 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 two big hydrocrackers to get finished this year, we will be up to 39%, 40% distillate yield, actually one of the highest in the industry in the US.

And then we had this project we are working on Meraux which will take us another year and a half to two years to complete.

Installing this reactor that will allow us there to make a much higher distillate use.

And so you will see that refinery produce distillates as opposed to gasoline in the long run.

And then we will integrate the gas oils between the two facilities.

We have an alki plant there that we might have some integration opportunities with all of the butanes we are seeing coming into the market.

There is a lot of opportunity on the US Gulf Coast for all of our plants that work together.

And we optimize it as a system as best we can.

Sam Margolin, Dahlman Rose.

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 that we are running a lot more Bakken now.

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

Okay.

Great.

I did notice that Midwest margins were higher year-over-year.

I assumed there was something going on in Memphis with the crude slates.

That's helpful.

Secondly, this is a bit of a longer question.

There has 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 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?

I'm not sure we are going to know that.

The RINs are $0.04?

Yes.

RINs are $0.04 and that doesn't necessarily imply that there is an excess of RINs.

Okay.

I'm going to say -- I know this is an issue for everybody on the call.

Yes, we were in the ethanol business.

But there is 800,000 barrels a day of ethanol going into the gasoline pool.

So by the mandate, you took market share from refineries and gave it to farmers.

But to eliminate that is extremely difficult.

And we had almost $8 corn I think a couple of years ago.

Remember ethanol has high octane under the EPA rules we have 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 relief.

Okay.

Thank you so much.

Evan Calio, Morgan Stanley.

Congrats on the announcement.

Apologize if I missed it, I jumped on a little late.

Any timing estimate on the retail spin-off and how you think about an appropriate leverage on that asset coming out?

And I have an additional question, thanks.

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

It will be comparable to the other C-store companies in that segment.

As far as timing, around six months we could probably do the spin-off.

We have a lot of work to do yet with our SEC filing and we need a private letter ruling.

Let's say around six months.

That's great.

Another question.

I know you had an additional quarter to think about it and even witness a temporary widening on your Brent-LSS spread.

Any new thoughts as your engineers have spent another quarter analyzing an ability to either run or make any investment to shift your slate a little bit to the lighter side?

On the US Gulf Coast where we tend to be a heavier refiner -- now Three Rivers is relatively light, Houston is light, Memphis runs basically Gulf Coast light barrels.

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.

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.

We are working on all this I'm sure like every one of our competitors.

Paul Sankey, Deutsche bank.

I think you've covered a lot of the questions I had, particularly on ethanol.

I was going to ask but 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 shortage of ethanol.

Could we simplify the answer on that one?

Well, right now there is not a shortage of ethanol.

Plants are cutting back.

We, as Mike said, have shut down two plants; we cut back the others.

We are 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 prices is going to go higher here relative to gasoline, because obviously today we are losing money in ethanol.

Sure.

But then you have to meet the mandate.

Will you meet the mandate, and not you, but the industry.

That is a valid question.

Now 93% or so of all the gasoline sold in the country has ethanol in it.

And we are going to hit the blind wall here, gasoline volume is down, RINs are $0.04.

I don't know if I can answer that.

And Paul, there is one thing to take into consideration.

We can carry forward 20% of the RINs from last year to this year.

I don't think we were 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, thanks that's helpful.

I know if you say you don't know it's okay for me to say I don't know either.

That's great.

(laughter)

Forgive me if you kind of feel like you covered this, but on M&A, particularly I'm think about BP saying Texas City and accounts available for sale and people are interested.

Do you have anything to add on that?

Thanks.

I really don't.

I said in the past that we have looked at it and we have a confidentiality agreement.

The thing is still on the market.

Chi Chow, Macquarie Capital.

Thank you.

Bill, I want to go back to this topic on the global distillate export market.

I know there has been outright refinery shut downs in the Atlantic basin on the less competitive plants.

But looks like on our analysis, it looks like there is potentially eight new hydrocrackers, including your two, set to come online in the Atlantic basin over the next 12 months.

Can you comment -- and by the way that's about 400,000 barrels a day 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?

I think there are hydrocrackers coming on as you say so there is no disagreement there.

Some of those are in the Med.

I think the Med is different than northwest Europe.

So I do think that it'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.

I know you know Chi, that the sugar cane harvest is bad in Brazil.

So they are going to wind up importing more gasoline and you asked about distillate.

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.

And numbers they are talking now about $10 billion or $12 billion for this refinery.

You have also seen -- and we are not participating today but we have in the past.

Actually shifts of 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 ARBs as Joe mentioned earlier and the economics and the US produced stuff is going to be on a cost basis very, very competitive.

Whether we can squeeze it into the market, we think we will be able to.

But you're clearly right that there are hydrocrackers being built.

Everybody sees that distillate growth.

We just happen to be in a good spot here.

I wish I had the hydrocrackers today, right.

Can you expand little bit on the difference between the northwest Europe market and Med?

What is the critical difference there between the two?

I think some of the longer term you are going to see supply come from the Middle East into the Med.

Okay.

Got it.

And demand obviously, I know you look at all of this stuff, look at the Italian demand and some of the Greek demand numbers are -- I mean, they are just very, very long refining.

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

Just seems a bit concerning with Europe, the situation there with demand, China slowing down.

And does it get down to Latin America, South America staying strong for this export market to kind of keep going here?

So I would like to hope the Europe does eventually recover, but I can't argue.

I would say that it does come down and when Joe spoke, our gasoline exports goes 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 the Gulf Coast.

Got it.

Thanks you for that.

One final question.

Looks like looking at your stats that your Gulf Coast light sweet crude runs got up to 240,000 barrels a day this quarter.

Last quarter you said your capacity route was around 200,000 a day.

Are you finding ways obviously to get more of that crude into your system.

We are finding ways or capacity -- we actually we said that's what we were running.

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

We are going to continue to close that gap.

This is based on availability and then economics.

If the discount is large enough and you can get enough of it, it will make sense versus some marginal medium sour.

These are the economics that we are working with and we are continuing to increase that.

What is your capacity then in the Gulf Coast right now on the light sweets.

0.5 million barrels a day.

That includes Memphis, though, right?

That would include Memphis.

Got it.

Okay.

Great.

Thanks a lot.

Harry Mateer, Barclays Capital.

Two questions.

First, you answered a few question on investment grade ratings, I was wondering if you can 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 might be willing to go down to low BBB as part of this retail separation.

Second question, what's the priority for you in terms of considering the retail separation?

Is it maximizing the amount of cash in the business or is that less of a focus given Valero's liquidity position?

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 going to leave it at that.

And then we will work with the rating agencies if they have any issue.

I gave some other data points on how much we paid off here.

Our coverage ratios and everything looked very, very good.

And then on the second question, it was --.

Cash priorities.

Cash 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.

We want to maximize our shareholder value.

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

Okay.

Thank you.

Doug Leggate, Bank of America.

My couple follow-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 two projects.

And then I do have a follow-up before I get cut off again.

On the timing of those benefits we are estimating the benefit as $650 million to 700 million.

The timing would be spread out over the next four to five quarters.

And a lot of that depends on obviously the profitability of the Company over the next year and a half.

I'm just going to say probably over the next four quarters we will receive all of that benefit.

Starting in third of 2012?

That's correct.

Great.

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 sour crude in the Gulf, how would you expect, if 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 getting at is our thinking is if LLS moves that probably benefits your medium and heavy feedstock as well.

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

Doug, I do think that's the right way to look at.

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.

As we get more supply into the Gulf I think what we will see is a downward pressure on the entire complex.

And Bill mentioned what the discounts needed to be, on heavy sour crudes relative to light sweet crude you need at least 8%.

You are going to see those have to price in if they want to move into the system.

So then I would add that, so what happens then is LLS is discounting to Brent, then you are going to have these other crudes discounting, and that -- it is on the world market which is pricing against Brent.

So the freight becomes the factor.

And we know that some of Venezuelan crude and Mexican crudes have been moving to China and other places.

Venezuelan crudes move to China.

So you wind up with a freight being the flywheel in there and of course, available tankers.

So there will be a limit of how wide that spread goes then relative to freight.

That's why I think we see LLS a couple of bucks which is really the freight that tends to be the driver here.

Relative to freight.

So Bill, theoretically that couple of bucks would translate -- I'm not trying to be too simplistic here, but to your entire Gulf Coast slate.

Is that the right way to think about it?

I think that is right.

And that's why we say the US 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 US refining industry can be competitive in the export markets when we face a domestic demand that is challenging.

Terrific.

Thank you.

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

Thank you.

Paul Cheng, Barclays.

Just two quick follow-up.

Bill, when you are looking at your retail net worth in July, month-to-date, what is your same-store gasoline sales?

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

So let's do the crude one first, Ashley.

WTI lane crude, the second quarter.

How much we are running in the second quarter -- It's still right around 250,000.

I mean, you are also running Bakken in Memphis, right.

So it seems that you say that you run about 140,000.

So should that now be more like in the 350,000 to 400,000 than --

No, no.

Because the Bakken crude that we run at Memphis actually comes from St.

James.

Oh.

It's priced like the LLS.

It's at a discount to LLS and the deals that Joe's people have done.

We don't have the receipt facility.

So it tends to go to St.

James and come back up cap line.

Interesting.

That's the answer to that.

Now Gary Arthur is here.

And your question was in July same-store volume?

That's correct.

We are down just a little bit under 3%, same store on gasoline.

That's in the US

Okay.

Thank you.

And we have no further questions in queue at this time.

I will now turn it back to you.

Thanks, Trish.

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

Thank you, ladies and gentlemen.

This concludes today's conference.

Thank you for participating.

You may now disconnect.