瓦萊羅能源 (VLO) 2007 Q3 法說會逐字稿

At this time I would like to welcome everyone to the Valero Energy third quarter 2007 earnings conference call.

All lines have been placed on mute to prevent any background noise.

After the speakers' remarks, there will be a question-and-answer session.

(OPERATOR INSTRUCTIONS)

I will now turn the call over to Mr.

Ashley Smith, please go ahead, sir.

Thank you.

Good morning, and welcome to Valero Energy Corporation's third-quarter 2007 earnings conference call.

With me today are Bill Klesse, our Chairman and CEO; Mike Ciskowski, our CFO; Rich Marcogliese, our Chief Operating Officer; and other members of our executive management team.

If you have not received the earnings release and would like a copy, you can find one on our website at Valero.com.

There are also tables attached to the earnings release which provide additional financial information on our business segments.

If you have any questions after reviewing these tables, please feel free to contact investor relations after the call.

Before we get started, I would like to direct your attention to the forward-looking statements 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 Security laws.

There are many factors which 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, our third-quarter earnings came in at $1.34 per share from continuing operations and $0.75 per share from discontinued operations.

Excluding the effect on diluted earnings per share related to the Company's $94 million settlement payment for the accelerated share repurchase program which was $0.16 per share and a $91 million pretax gain or $0.10 per share after taxes resulting from the repayment of a loan by a foreign subsidiary, the third quarter 2007 diluted earnings per share from continuing operations were $1.40.

You should note that the gain on the sale and the operations of the recently divested Lima, Ohio, refinery are classified as discontinued operations in the financial tables that accompany the earnings release.

Third-quarter 2007 operating income was $1.2 billion, compared to $2.3 billion reported in the same period last year.

The $1.1 billion reduction in operating income was primarily due to lower throughput margin per barrel of $9.94 which is down $3.23 per barrel versus the third quarter of 2006.

The key driver of the lower margin was the higher price for light sweet crude oils and smaller discounts for sour crude oils and other feedstocks.

On average our feedstocks were approximately $3 per barrel more expensive versus WTI and reduced operating income by more than $700 million as compared to the third quarter of 2006.

Additional factors that negatively affected operating income include substantially lower throughput margins in the West Coast region which reduced operating income by approximately $110 million, lower margins for many of the Company's other products such as asphalt, blue boils, and petrochemical feedstocks, the impact of Hurricane Humberto on the Company's Port Arthur refinery as well as operational issues at the Company's Port Arthur, Aruba, and Ardmore refineries.

Going through some of the key numbers for the third quarter, refinery throughput volumes averaged over 2.8 million barrels per day, or 50,000 barrels per day higher than the second quarter.

Refinery operating expenses excluding noncash costs were $3.96 per barrel.

The $0.09 per-barrel increase over the second quarter was primarily due to an unfavorable adjustment arising from sales tax accruals that were charged during the quarter.

This was partially offset by lower energy costs and higher throughput volumes.

General and administrative expenses excluding corporate depreciation were $152 million.

The $25 million decrease from the second quarter was mainly due to additional charges incurred in the prior quarter for charitable contributions and the cancellation of a services agreement with Newstar Energy.

Total depreciation and amortization expense was $343 million.

Interest expense net of capitalized interest was $123 million.

The $40 million increase in net interest expense versus the second quarter was primarily due to an increase in average borrowings and an increase in interest on taxes arising from the previously mentioned sales tax accruals.

Our effective tax rate on continuing operations was 28.7% in the third quarter, which was below the prior quarter due to the use of state tax credits and a greater than expected proportion of earnings from our Aruba refinery which pays no income taxes.

Regarding cash flows for the third quarter, capital spending was $619 million, which includes $108 million of turnaround expenditures.

For 2007, we expect our total capital spending to be around $3 billion.

In the third quarter, we continued our stock buyback program by spending $475 million to purchase approximately 7 million shares of our common stock.

So far during the fourth quarter, we have purchased over 1 million shares.

Year to date we have returned approximately $5 billion to our stockholders, through $205 million in dividends, plus $4.8 billion to purchase 70 million shares, which represents approximately 11% of our outstanding shares at the end of 2006.

To reach our $6 billion goal, we intend to purchase an additional 1.2 billion of our shares by the end of the year.

With respect to our debt position at the end of September, our total debt stood at $6.9 billion which is unchanged from the end of June, and we ended the quarter with a cash balance of just over $3 billion.

As to the fourth-quarter operations for your modeling purposes, you should expect to see the Gulf Coast refinery throughput of approximately 1.6 million barrels per day.

Mid-continent throughput should be between 435,000 to 445,000 barrels per day.

Due to some planned maintenance activities, West Coast throughput should average between 240,000 and 250,000 barrels per day.

And then the Northeast system should average in the range of 550,000 to 560,000 barrels per day.

Refinery cash operating expenses are expected to be about $3.90 per barrel.

With respect to some of the other items for the fourth quarter, we anticipate G&A expense to be around $145 million, net interest expense should be around $95 million, total depreciation and amortization expense should be around $350 million.

And finally, for the fourth quarter, you should be using a 34% tax rate for your modeling purposes.

Now I'll turn the call over it Rich.

Okay.

Thank you, Mike.

Before I discuss our growth project in St.

Charles, I'd like to review some operating highlights from the third quarter.

In July, we commissioned a 16,000 barrel-per-day distillate hydrotreater at our Venetia refinery.

And in August a 50,000 barrel-per-day mild hydrocracker at our St.

Charles refinery.

These projects were part of our overall plan for making ultra low sulfur diesel.

Also we are pleased that our Houston and Paulsboro refineries were each recertified as VPP star sites under OSHA's voluntary protection program during the quarter.

In addition, our Ardmore refinery was recommended for recertification on November 1.

These recertifications were made under OSHA's more rigorous national emphasis program.

VPP star site certification continues to be an important part of Valero's commitment to occupational and process safety.

Regarding operations in the fourth quarter, we have been executing several major unit turnarounds in our refineries.

We are just completing a large crude unit turnaround in Paulsboro and are nearing completion of a CAT cracker turnaround in Texas City.

On the West Coast, Venetia has its fluid coker down for turnaround, and our Wilmington refinery has its CAT cracker down to support a revamped project on the Appalachian unit.

As Mike referenced earlier, these turnarounds will impact throughput rates on the West Coast in the fourth quarter.

Also in the fourth quarter, we anticipate the start-up of a new distillate hydrotreater in Corpus Christi in December.

This is a 55,000 barrel per-day unit and essentially completes our ULSD production plans except for the Northeast.

Turning to projects, we are very pleased that our Board recently approved a major expansion project for our St.

Charles refinery.

The St.

Charles hydrocracker project includes a new 50,000 barrel per-day hydrocracker, a 45,000 barrel-per-day expansion of the crude unit, and a 10,000 barrel-per-day expansion of the coker.

The project will increase diesel production by 49,000 barrels per day and gasoline production by 11,000 barrels per day as part of our strategy to increase the proportion of ultra low sulfur diesel produced in our system.

This project is expected to come on line in 2010 and costs $1.4 billion.

This is one of the largest capital projects in Valero's history.

Now I'll turn it over to Bill.

Thanks, Rich.

Good morning, everybody.

In general, industry gasoline and other product margins have been low so far in the fourth quarter.

The seasonal changes in supply and demand and the high crude oil prices have squeezed gasoline margins to very low levels, though they have improved a couple of dollars here in November.

Diesel margins have been very good, and unlike the third quarter, we're seeing wider discounts for medium and heavy sour crude oils that we process.

For example, the Maya heavy sour crude oil discount to WTI in October averaged over $15 per barrel compared to the September.

Today it is over $16 per barrel.

And the Mars medium sour crude oil discount is averaging over $11, one of the widest Mars discounts we've ever seen.

And the Saudi discounts for the month of December have increased over $4 per barrel.

As many of you know, we recently held our annual strategic planning meeting with our Board and our executive management team.

The meeting from our perspective went very well and affirmed the strategy we have been executing.

Going forward, we will continue to upgrade the quality of our refining portfolio by investing in strategic growth projects at our flagship refineries that will make them even more competitive.

A good example of this is the project Rich just mentioned, the St.

Charles hydrocracker project.

Additionally, we continue to solve our issues or have projects in development that will accomplish our goals of a safer, more reliable, and more efficient operation.

Another outcome of our strategic planning meeting is that we have decided to explore strategic alternatives for our Aruba refinery.

The Aruba refinery does not make U.S.

specification products, nor does it make finished gasoline.

A large capital investment is required to make this competitive in the long run, thus we have decided to look at our strategic alternatives.

Regarding our cash flow, we will continue to take a balanced approach to investing in our key refineries as discussed, buying back our stock, increasing dividends, and maintaining our investment-grade rating.

Looking out into 2008, we expect another excellent refining environment of strong product demand, favorable discounts for medium and heavy sour crude and feedstocks, a tight refining capacity market, as the world economies continue to grow.

And with that, we'll open it up to Q&A.

(OPERATOR INSTRUCTIONS) Your first question will come from the line of Doug Terreson with Morgan Stanley.

Good morning, guys.

Hi, Doug.

Bill, you mentioned just a minute ago that, and the press release I think suggested that you guys are actively considering strategic alternatives for Aruba.

And I just had a couple of questions on that point.

First, would you consider some type of joint venture upgrading project with another company?

And if so, would any specific conditions need to be met or are you solely considering outright divestiture?

And the second question is -- is how would you characterize the interest level towards either type of strategic activity at this time?

Which is more of kind of a -- an industry-general strategic question?

To your first question, we're sincere in when we say strategic alternatives.

But of course, that includes a sale all the way through the sum of processing agreement even.

What we're in business here for is to maximize our shareholder value for the long run.

Good.

And how would I classify the environment?

Well, the interest level toward strategic activity at this time?

I think it's still very high.

Okay.

I think it's exampled by the recent announcement in California.

Sure.

Okay.

Thanks a lot, guys.

Your next question will come from the line of Jeff Dietert with Simmons.

Good morning.

I was hoping you could give us an update on the Port Arthur expansion and the Quebec hydrocracker, those were projects you talked about in early September that did not go in front of the Board.

But where do those projects stand?

Rich is going to go ahead and address that for you.

Hi, Jeff.

We are still very active in the development process for those two projects.

For Port Arthur, we envision an identical hydrocracker to be installed at that refinery.

Also related to that project will be the installation of a 45,000 barrel-a-day grassroots coker.

Now, that project is on a different timeline from St.

Charles, and this largely is an outgrowth of kind of assessing total plant workload.

We have got a plant light turnaround scheduled for Port Arthur in 2009, which incidentally includes replacement of all six coke drums on the existing coker.

So taking a look at plant-wide workload between turnaround and construction, we've pushed back the Port Arthur schedule about a year.

And it will be more like a 2011 project compared to a 2010 project for St.

Charles.

For the Quebec refinery, we have active development underway for a combination project that would include about a 35,000 barrel-a-day deasphalting unit and a 50,000 barrel-a-day hydrocracker which would make the Quebec operation more efficient in terms of reduced fuel oil production and more flexible in terms of the varieties of crudes it can run.

And that is also envisioned as more of a 2011 project implementation schedule.

So we're still very active in development on both.

I see.

Very good.

If I could, on a second question, if you could provide some -- some color, there's been a pretty severe change in the crude markets with the market moving into backwardation.

Could you talk about how that's influenced your crude purchases?

Has it reduced your purchases, led you to reduce inventories, buy shorter haul crude?

Could you provide some color on how that's influencing your activity?

Sure.

Jeff, this is Joe.

It -- I mean all those things you mentioned are things that we're -- we're certainly taking a look at.

Obviously, it doesn't pay to carry crude today.

So we are managing the inventories much more aggressively.

And we're keeping an eye on it.

As far the short haul crudes go, we're absolutely running them to the extent that we can.

It also obviously impacts our Mid-continent.

Probably has changed our crude costs into our Mid-continent refineries, a couple dollars a barrel from the carry to the backward.

Thank you.

Your next question will come from the line of Arjun Murti with Goldman Sachs.

You allude to wanting to finishing up the $6 billion stock buyback goal by the end of this year, and that you will continue to do various cash return to shareholders next year.

Is the timing of announcing a new stock buyback figure tied to whatever you decide to do with Aruba or simply getting to year end and finishing up this program and you'll take a fresh look at where things stand for next year?

I would say the latter.

Arjun, we will complete -- our plan is to complete this program.

We still have some authorization that's left that carries into next year.

So to be technically correct here, we'll still have a couple of billion dollars of authorization.

And we'll see how we see the world as we get into the first quarter and then as we look to the second.

But our -- our plan is to continue as we have discussed.

That's great.

So you obviously already sold Lima.

You've now announced Aruba.

You've just completed the strategic review with the Board.

Should we take that to mean -- should we expect there to be continuous high grading as we get into next year, and you're kind of taking it one refinery at a time, or does the conclusion of the review process mean you've done Lima, you're going to do something with Aruba and that's it in terms of I guess selling or high grading the existing refinery asset base?

Arjun, it's a continuing process, and so you should assume that as we go forward we're constantly looking at these refinery assets.

Some really capitalize on our expertise of basically boiling and coking heavy crude oils.

Some have very unique locations.

And others might be worth more to other people.

That's great.

Thank you very much.

Your next question will come from the line of Doug Leggate with Citigroup.

Thank you, good morning, everybody.

A couple from me real quick I guess.

What does the tax rate look like ex Aruba for the rest of the firm?

What does the CapEx?

The tax rate?

The tax rate.

Got you.

Okay.

It would be about 1% or 2% higher.

So instead of 34 for the fourth quarter, you'd look at 35 to 36%.

Okay, great.

Second one from me is given what's going on in Europe right now, there seems to be some pretty incredible diesel cracks.

Can you describe how you see the export opportunities over there?

Yes.

The [ARP] is open clearly from the U.S.

to Europe.

We're taking advantage of it today.

We've got cargos that are in the process of heading that direction.

Okay.

So actively taking advantage of that.

If you could take us to how long you expect that market to remain as strong as it is, given down time, the number of refineries over there?

I don't think we would know any better than you do.

We read the paper on the down time that's happened as well as you.

So we wouldn't -- the ARP is open.

Our business is a global business.

Products move with the ARP.

So we'll take for our Company advantage of the ARP while it stays open.

Okay.

Final one from me is I wonder if you could just bring us up to date with your view on ethanol.

There was a lot of discussion obviously about the volumetric impact.

But at the same time we're seeing some pretty incredible discounts when you take the tax credit into account.

Big incentive there for you folks.

But can you -- can you sort of discuss the financial benefit versus the infrastructure bottlenecks as you see it, in terms of whether ethanol is a threat or an opportunity for you as you move into 2008?

I'll give you some general comments and see if I can give you some numbers.

But today it is advantageous to discretionary blend even against butane.

So where you can you, where the logistics are available, the infrastructure, you would probably be blending.

We are blending because of the economics, as you properly state, where we can.

But there is also a lack of infrastructure in many of the markets.

So we can't take advantage of that.

Because with the butane when we blend it you can ship it in the pipeline for winter spec, but here with ethanol it's got to be done all locally.

So that's the constraint.

Now some of the numbers aren't compelling as you say.

You have any--?

Well, we've got -- we've got prices that we're seeing, $1.80 to $1.90 a gallon for ethanol.

So it clearly pays to blend it.

And we're blending about 25,000 to 30,000 barrels a day.

And we are blending it where we can.

Are you getting any octane benefit on the bulb that you're blending it with, like for example, an 83 versus an 87 regular?

The effect on the gasoline?

Yes.

It would be true, you get the octane.

But unless we can send to some of the terminals the suboctane, then you don't get it.

Okay?

Because we don't have -- we have to have the tankage and the logistics.

If we're low on that the refinery will try to take advantage of it.

But logistics or infrastructure here really restricts your ability to fully capitalize on this.

But you have to get the suboctane to the terminal.

But you're correct, ethanol has got a great octane.

So you try to take advantage of it.

That's great, gentlemen.

Thanks a lot.

Sure.

Your next question will come from the line of Paul Sankey with Deutsche Bank.

Hi, guys.

Good morning.

A couple of follow-ups from me on Aruba firstly.

I guess it's a bit more complicated as a sale.

Do you have a best guess for the kind of time scale over which it will take to get something done?

Well, we're looking at strategic alternatives.

I'm going to tell you we're going to let the process run.

It takes -- most things take months.

Right.

But possibly a bit longer than Lima?

I really wouldn't know.

Fair enough.

Are there any -- you mentioned the tax rate, the tax impact, obviously.

Are there any other major impacts it's going to have on your metrics and thinking of OpEx or anything else worth highlighting that would change post -- post a potential sale?

Not really.

On the Gulf Coast throughput, post the sale would be down roughly $200 million a day--.

200,000--.

200,000 barrels a day.

On OpEx, Aruba is one of our lower refineries on an OpEx per barrel basis because it's a low conversion plant, there's no CAT cracking on Aruba for example.

To answer you, our operating costs in the Gulf Coast would move up, but if you deal in a complexity barrel it wouldn't be that way.

Sure.

I got you.

Just going back to another follow-up from me.

The contango backwardation issue, I think it was an earnings impact effectively this quarter, and I guess it will continue to be that as long as we remain in backwardation.

Is that a fair statement, and can you quantify how much the impact was?

It is a fair statement certainly for the Mid-continent refineries.

It gets very complicated because Louisiana grade crudes tend to price their oil into them, and in WTI we have their oil very visible.

But to give you, because it is significant, it comes up every time we have it from contango to backward, it's in the, between the second quarter and the third quarter, if you include our estimate for Louisiana on a roll, it's probably about a $58 million hit in our crude costs.

Okay.

So that's the trailing.

And I guess you expect that just to continue as long as the situation continues with the curve?

Yes.

I was trying to give you a comparison.

But clearly, you can look at the roll and you can look where the contango was in our Mid-continent volumes and you can figure out that it raised our crude costs that much.

But yes, it was those numbers I gave you were second quarter to third quarter.

I got you.

Okay.

Thanks.

Just a last one from me.

I guess to roll up what you said about the change in the environment.

You mentioned gasoline I guess weaker, diesel better, differentials helpful.

On balance, are you expecting a better quarter this quarter than we saw in Q3 on an ongoing basis, obviously, worse or how are we panning out quarter to date for earnings?

Thanks.

Well, we usually don't give you any guidance on this.

But I will tell you, you can look at the industry cracks.

Obviously October was a weak month.

And that cracks are strengthening.

If you look at where we are today, it's going to be a weak fourth quarter.

But it is strengthening.

Some of the markets are recovering, as I said.

Gasoline is a couple dollars better.

The discounts are wider.

The Maya, Mars is absolutely almost a record.

I can't remember $11.

So the quarter is improving.

It's hard for me to tell you at this point time whether it's going to be better or worse than the third quarter.

And I'll also tell you it's this time of year.

Gasoline season for us is generally over, even though we have good demand still.

And distallates, we're like everybody, winter's coming.

Yes.

And I guess that's the basis for you being positive on '08, as well.

Is that despite -- I mean, you seem to be saying that demand is strong.

Can you just address that one a little bit?

I guess some of the DoE data is looking a bit weak.

Well, the DoE data is all over the place.

But it's easy -- if we go back and look at the monthly data, gasoline is up year to date.

However, we would not argue that the recent gasoline data is probably pretty darn flat with last year.

It's hard to articulate whether it's just prices or whether it's housing, confidence in the economy, or whatever, but we would say it's -- gasoline right now is pretty flat with last year.

So your assessment is correct.

However, when we look into next year, lots of changes, refining is still tight, our product is still economic.

I mean, compared to where it was obviously not.

But it's still a very viable economic product.

And the dollar weakness is also impacting all of this.

But we are still very optimistic that the refining, supply and demand balance remains tight.

But I think -- I think I've had my fair share.

Thanks for that.

Sure.

Your next question will come from the line of Paul Cheng with Lehman Brothers.

Hi.

Good morning, guys.

Good morning.

My -- I think this is for Mike or maybe for Bill.

I think previously that we are talking about 2008 capital spending, $4.7 billion to $5 billion, and at the time it seemed the time line for Port Arthur and Quebec, operating project was 2010.

With those two projects are delayed, are we looking differently on that CapEx range?

For 2008, we're still looking at right around $5 billion or a little bit under.

So we are still at $5 billion?

Yes, Paul.

And that might -- for 2007, I think the original here is 3.5, and then later on that trims you to 3.2.

And now I think if I did not mistake, you are talking about $3 billion.

Is there any point of being delayed or that you guys just do it far more effectively?

There is only really one project that we consciously delayed.

And that was the crude oil expansion at the Quebec refinery which we rolled from year-end 2007 to mid-2008.

Beyond that specific hurdle, the capital expenditures are just following the normal progression of our capital project development.

And in some cases, things are moving along just a little bit slower than we anticipated.

But you heard the numbers correctly, Paul.

We would expect to be around this $3 billion or slightly less for 2007.

All right.

And I think this is for Rich.

That in the third quarter we have a little bit of the operating upside in I think Port Arthur this year, maybe in some of the facility.

Can you quantify that?

I mean, how much is the actual and opportunity cost associated with those?

What we've associated with the third quarter was about a $300 million impact which is favorable to the second quarter.

But is a big number nonetheless.

The issues we had just to give you a sense, we had CAT cracker outage in Ardmore in July.

We've had issues with Port Arthur crude units also in July, which was separate from the hurricane impact that Mike Ciskowski mentioned.

We also had difficulty with the coke handling system at our Port Arthur refinery.

We had crude throughput issues in our Aruba plant which were related to piping and metallurgical issues.

So we had a number of things going on across the system.

Additionally we also had a catalyst change on the Texas City gas haul hydrotreater.

We don't generally define that as a major unit turnaround.

But that also had its impact in the third quarter.

Rich, since I got you, is there a preliminary first-quarter turnaround schedule you can share?

Well, I'll just mention a couple of things for first quarter '08.

In February of next year, we plan to take the St.

Charles millisecond CAT cracker down for about a 21-day turnaround.

And then also the -- in Quebec we're going to take one of the crude units down.

This is the crude unit that's going to be revamped for the expansion project.

That will come down in the March/April timeframe for about 42 days.

Those are the most significant.

Okay.

And Mike, for Aruba, I believe the tax holiday is coming up for expansion or exploration.

Is it 2010 or 2011?

It's 2010.

The end of 2010.

End of 2010.

So that whatever is the selling price -- if we decide to sell that probably we will need to take into consideration if you sell?

Well, I think so.

Yes.

You got it.

Okay.

Okay.

Excellent.

Thank you.

Thanks, Paul.

Your next question will come from the line of Chi Chow with Tristone Capital.

Thanks.

I was wondering if you could provide us with an update on McKey and what the status is there?

Sure.

I can do that.

Currently we're in the same configuration in McKey, which is the total plant is up ex the propane deasphalting unit.

Construction continues on the revamp and rebuild of that unit.

We expect mechanical completion sometime late November, early December with start-up of the PDA either just before the end of the year or in early January.

Today the plant is running at a throughput of about 140,000 barrels a day with PDA out of service.

And are you running more sweet crude then as a result now?

We have -- we have adjusted the crude mix at McKey to try to minimize the bottoms production.

That is the constraint on the refinery operation because we're shipping fuel all oil out by rail.

So very recently, we've made some attempts to lighten the crude slate a little.

Okay.

How big of an impact do you think McKey and also BP's Whiting plant, down time at both those plants is having on cushing inventories and as those plants get back up, do you see the backwardation easing at all, and do you see sour crude discounts narrowing going forward?

Well, Chi, you know it had a significant impact back in the second and probably the early part of the third quarter.

I think we saw the dislocation of TI to the other sweet crudes as a result of that where it was significantly discounted.

And I think that largely that's behind us.

It -- as far as the effect going forward and the heavy sour discounts coming in, with these high prices like we're experiencing today I think we're going to continue to see strong discounts.

We got Maya discounts today that are over $16.

We've got other heavy sours that are in the market that are trading at $20-plus discount.

So I -- I would say that if we were to look at it we would expect the heavy sour discounts to maintain.

I think the other piece you asked in there was what our outlook would be on the backwardation.

I would tell you if inventories continue to keep drawing, the backwardation is going to continue, okay.

So if you're asking how we plan our business here, we're looking at these overall inventories and trying to assess where we really think they're going to go and if they keep coming down the front's going to stay a little tight relative to the out months.

We're going to see the backwardation continue.

It's very difficult for us to comment as Joe has, skipped around there that we can't comment on BP.

At McKey, though, we're running pretty close to our crude charge.

BP's situation in Whiting, we wouldn't know about.

What type of crude do you think is sitting at Cushing right now in storage?

Is it primarily sour grades?

I -- I don't know for certain.

But we know that there is a lot of Canadian crude in Cushing today.

I guess we'll give you one other piece info.

We also know asphalt markets are very weak.

When you know asphalt markets are very weak you don't want to run the WTS.

So you tend to see your idea or approach here may be right, Chi, but we don't have any per se data.

Okay.

Okay, then one more question on Aruba.

Have you seen the reliability, in particular the power supply improve over the years since you have had that plant?

Let me comment.

Let me say that we have put a lot into it.

And we even have more investments planned.

But we did have a total power disruption on Aruba about a month ago which was related to a transformer and breaker failure which we had anticipated replacing within the next year or so.

So the odds that we put quite a bit of effort and investment into the upgrading.

But the difficulty is we still have a lot of 1930's and 1940's vintage infrastructure that's in the process of being upgraded.

And we're not complete with the program.

Okay, thanks, Rich.

Appreciate that.

(OPERATOR INSTRUCTIONS) Your next question will come from the line of Mark Gilman with the Benchmark Company.

Had a couple of things.

I wanted to go back to this Mid-continent effect.

Bill I think you said a $58 million impact in the third quarter.

My guess is that it was probably something closer to multiples of that.

Just going from the average contango in the second to the average backwardation in the third.

Also if you could clarify, it's my understanding that this is in effect really only during the time when you switch from contango to backwardation and not if the market structure remains the same going forward.

Well, Mark, I can only tell you the numbers that people give me and the number I gave you is the number they give me, okay.

And as far as to your question as to -- I guess what you're asking is when it changes, it's the impact, well, it was contango in the second and the contango reduced.

So I was giving you the impact of the drop in, or the reduction of the contango.

The roll.

So as it's continued to roll and comes down to the question that we were asked earlier, if you compare fourth quarter to second quarter, it's going to have two times or something the number I gave you for the third to the second.

If you're comparing the fourth to the third, it's gotten worse.

So it's going to be to that magnitude.

But you know this roll like I know the roll and you know the backwardation.

I'm giving you a number that we calculate.

Okay.

I think we're on the same page.

Let me try something else if I could.

It -- it just appears to me that as it relates to your Texas and Gulf Coast plants in particular that a pretty good fraction of the reliability and unplanned downtime issues relate to power.

And I was wondering whether in response to this if you share my conclusion.

Whether cogen-type investments on a broader scale would make a lot of sense.

I might take a crack at that.

I -- I would not characterize our Gulf Coast system as having kind of a generalized power issue.

If you went back a few years, there were issues of that nature in Texas City that we've since corrected.

Where we're having most of our reliability issues are in the Port Arthur refinery.

But that is primarily related to the operation of the delayed coker.

Now I would also say, just from a cogen infrastructure point of view, Port Arthur is one of the most highly integrated plants in terms of internal power generation, and a good example of that, there was this recent pipeline fire in the Port Arthur area.

It took out both 230,000 volt feeders to the refinery.

We were able to islandize the plant and run off power generated from our relationship with air products to produce hydrogen.

So just to summarize again, I would not say that we have a power reliability issue in the Gulf Coast.

Where we are seeing reliability issues are associated with the process units.

In Aruba we've made a lot of improvements but we generate a lot of our power there, it basically starts with fuel oil.

And to steam to the power.

And so the improvements we have made have helped.

But power in Aruba is a challenge.

Thanks, guys.

Let me try one more if I could regarding Aruba specifically.

Aruba has a number of the characteristics that you would otherwise look at I think as being desirable in terms of both size, as well as coastal location, ability to receive BLCC-type cargos.

Is there a message that perhaps you're sending the government regarding the expiration of the tax holiday with this announcement and, therefore, might this strategic alternative assessment potentially wind up in no action at all?

Well, I guess potentially I would say, yes.

But we are sincere in looking at our strategic alternatives.

I think that you are very familiar with the refinery.

In a high crude cost environment when you have a coking refinery that doesn't do any upgrading, it is a different competitive plant than a, for instance for us our St.

Charles refinery that does coking and upgrades.

Another thing, remember, Aruba does not make any gasoline.

It makes very limited ULSD.

So as we do our assessment of the future, it requires us to invest heavily in this refinery to be competitive.

And so you as a person who recommends our stock and as the people that own our stock would expect us to do, we would -- we're looking at our alternatives.

So that's what we're doing, Mark.

Hey, listen, on your contango question and backward question, when the market is contango in the Mid-continent, we capture the roll.

So.

I understand that.

It's the loss of that and going to backwardation where there is a significant loss, if you will, that produces a number that in the third quarter looks to me like it's more like $200 million.

Well, we didn't calculate it that high.

But if you went back to the second quarter and went all the way to the fourth quarter where you have $1 backward versus over $1 of contango, it's a big number.

I agree.

Okay.

Thanks, guys.

Your next question will come from the line of Daniel Vetter with JPMorgan.

Yes, can you comment on your progress to date towards meeting your $1 billion operating improvement target?

Sure.

And just to define that, we've got a $1 billion competitive GAAP closure objective defined over a five-year period.

We have a rigorous reporting and stewardship process toward those objectives.

What I would say generally first is the progress on that kind of buy design is more heavily weighted to the back end because there are some large capital projects that we need to implement to create some of this GAAP closure.

Examples I would use, I'd describe problems with the coker in Port Arthur.

We've got a premature drum cracking issue there.

We're going to replace all six coke drums in 2009.

We're also going to do likewise at our St.

Charles plant, and replace all four coke drums there.

So certain of the refinery reliability boosts and improvement that we are anticipating isn't really captured until 2009.

We do have a number of noncapital improvement initiatives, maintenance efficiency, energy conservation, that are underway, but we're really early in the program at this point.

So I would say our program is on track, but it is lightly loaded on the front end, and heavily loaded mid-to the back end.

Okay.

And one more if I may.

I noticed that the estimated cost of the St.

Charles project or I guess it's actually a handful of projects is up a bit from your prior estimate.

Can you comment on the -- or update us on the expected EBITDA contribution of that project.

Or the expected return of that handful of projects?

Thank you.

The capital is up from when I was in New York in September.

As we -- as we finalize the project, the scope for our Board.

So that was the number we came up with.

We're looking here to find the EBITDA number.

But the project has a return that's in the slightly higher than the mid-teens.

And we expect it to -- at this order of magnitude project using our forecast in the future, it adds significant -- and that's an IRR return, adds significant shareholder value.

If we can't find the EBITDA, you need to call Ashley Smith here.

Yes, it was on the slide I think I used in New York.

Okay.

We haven't -- well, I'll get you an updated number for that slightly higher cost estimate now.

Okay.

In the mid-teens return, assumed.

So what kind of a margin environment?

It's our strategic planned forecasting.

And we do our own forecast on this.

And so I mean that's what it is.

Okay.

All right.

Thank you.

Your next question will come from the line of [Ari Ravitz] with Banc of America.

Hi, just a quick follow-up on the ethanol.

You had said 25,000 to 30,000 a day of blending.

Just wondering how much of that is discretionary versus state mandated?

Let's see.

I don't think we're going to have a good answer for you on that.

Well, yes.

If I look at the numbers, I would tell you it looks like probably 12,000 or probably half of it is mandatory.

The other half is discretionary.

Okay, great.

Thank you.

(OPERATOR INSTRUCTIONS) Your next question will come from the line of Paul Cheng with Lehman Brothers.

Guys, just two quick follow-ups.

Mike, for 2008, your CapEx is $5 billion given the three major upgrades in Port Arthur to Quebec and St.

Charles.

Should we assume that it's roughly about in the $5 billion from the 2009 to 2011 also?

Or that the number would be lower?

The 2008, we're not going to spend a lot of money on Port Arthur or Quebec just because of timing.

So in all our numbers, we've said -- it just really doesn't have that big an impact.

But yes, to your question, you can look at this range of capital here for '08 and '09, and then '010 really depends on how much was spent on these jobs in '09 quite frankly.

'09 is a large turnaround year for us also.

So if I add that, it could be slightly higher than in '08.

Okay.

And--?

If you look at our turnaround schedule extended, '09 is -- as Rich said, we have Port Arthur, we have the St.

Charles, both cokers, we had the millisecond CAT complete revamp at the end of '09.

Big projects for us.

Right.

So that means '09 may be over 5 and then '010 and '011 may be somewhat below 5?

I think that's a fair assessment for right now.

All right.

And if I look at the presentation you have before Bill back in September, quickly calculate the sustainable capital is about in the 2.6 billion to $2.7 billion for 2008.

Is that also a reasonable proxy going forward based on your current configuration?

Assuming if we don't do anything with Aruba?

I would say it's in the $2 billionish, so $2.2 billion to $2.3 billion I think is fair.

Okay.

A final question.

Mike, for 2008, is there a number you can share for antidilution, how much stock you have to buy back in 2008?

Is it 10 million shares, 5 million shares, what kind of number we should assume?

The number that -- I mean, a lot of that depends on the exercise of stock options and the like.

But I would guesstimate about 10 million to 12 million shares.

Okay.

Perfect.

Thank you.

And at this time this does conclude the Q&A session.

Please continue with any closing comments.

Okay.

At this point, I just want to thank everyone for listening to our call today.

And if you need more information, please contact our Investor Relations department.

Thank you.

Ladies and gentlemen, this does conclude the Valero Energy third-quarter 2007 earnings conference call.

You may now disconnect.