瓦萊羅能源 (VLO) 2006 Q2 法說會逐字稿

Good morning.

At this time, I'd like to welcome everyone to the Valero Energy second quarter 2006 earnings release 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).

Thank you.

I'll now turn the conference over to Mr. Eric Fisher, Vice President of Investor Relations.

Sir, you may begin your conference.

Thank you.

Good morning and welcome to Valero Energy Corporation's second quarter 2006 earnings conference call.

With me today is Bill Klesse, our Chief Executive Officer;

Greg King, our President;

Mike Ciskowski, our CFO, Rich Marcogliese, Head of Refinery Operations, and other members of our senior 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 also tables attached to the earnings release which provide additional financial information on this segment.

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

Before I turn it over to Bill, I would like to direct your attention to the forward-looking statement disclaimer that is in the press release.

The summary says that statements in the press release and on this conference call that state Company's or management's expectations or predictions of the future are forward-looking statements that are intended to be covered by the Safe Harbor provisions of the federal securities laws.

There are many factors which could cause our results to differ from our expectations, including those that are described in our filings with the SEC.

With that I will turn it over to Bill.

Good morning.

Thank you for joining us today for our second quarter conference call.

As you saw in the release, our second quarter earnings of $2.98 per share were the best quarterly earnings in the Company's history.

This was despite major turnaround at the Quebec and Paulsboro refineries and unplanned outages during the quarter.

Rich Marcogliese will discuss operations a little later.

The fact that our earnings are so good despite the benefit -- showed the benefit of having a large, geographically diverse and complex refining system.

The bottom line is that this has been a terrific first half of the year for us in the outlook for the rest of the year is even better.

The current margin environment is outstanding, with extremely good margins on all of our light, clean products.

The global refining system is running at capacity to keep up with demand.

The world economy has continued to grow despite the higher commodity price.

We believe refineries will continue to operate near capacity for at least the rest of the decade.

Clearly, volatility and seasonality are very much a part of our business.

But going forward, the tight supply/demand balance will continue to demonstrate what we have been saying for years, that the highs are higher and the lows aren't as low.

Now, I will turn it over to Mike Ciskowski to walk you through the details of our second quarter financial results.

Thanks, Bill.

Obviously, this was a great quarter.

Net income was $1.9 billion or $2.98 per share.

Compared to last year's second quarter we more than doubled our net income.

In general, refined product margins were up about 60% from the second quarter last year.

Details on the average product margins for the quarter and the comparisons to last year are provided in the earnings release tables.

In reviewing those numbers, you also said that with the exception of the ANS discount, sour crude discounts remained wide, which has continued to give us a solid earnings base.

Greg will provide an update on our market outlook here in a moment.

On the cost side, second quarter cash operating costs at the refineries were up 23 million or just 2.5% from the first quarter.

However, on a per barrel basis, operating costs fell slightly from first quarter levels due to higher throughputs.

General and administrative expenses were 171 million.

The increase of 20 million from the first quarter was primarily due to funding Valero's charitable foundation and higher legal costs.

Total depreciation and amortization was 293 million, which was up 33 million from the first quarter.

This increase is primarily due to higher depreciation from our capital projects and increased turnaround in catalyst amortization.

We also finalized the appraisals on the Premcor refineries, resulting in a cumulative catch-up of depreciation primarily in the mid-continent.

Interest expense net of capitalized interest was 46 million, a decrease of 13 million from the first quarter.

That was mostly due to higher capitalized interest on our capital program and a full quarter effect of paying off about $221 million of debt in the first quarter.

Year-to-date, our effective tax rate was 33.2%, which was lower than usual due to tax law changes in Canada and Texas that occurred late in the second quarter.

Going forward, you should be using a 34.75% tax rate for modeling purposes.

With respect to our debt position, at the end of June, our total debt stood at 5.2 billion which compares to 5.4 billion at the end of '05.

We finished the quarter with a debt to cap ratio of 20.4% versus 24.8 at the end of '05.

As for our buyback program, in 2006, we have committed to buy approximately 5% of our outstanding shares under our existing repurchase programs.

Year-to-date, including July, we have purchased approximately 23 million shares of our stock.

Included within those purchases were shares under the 400 million stock repurchase plan that have been around since 2001, so we have now completed that plan.

Our existing authorizations allow us to purchase roughly another 7 million shares this year.

Once that is completed, we will look at going to the Board for additional authorization.

Looking ahead to the third quarter, turnaround activity is pretty light, which Rich will discuss in a moment.

So for modeling purposes, you should expect to see Gulf Coast refinery throughput of approximately 1.55 million to 1.6 million barrels per day, mid-continent throughputs of around 550,000 barrels a day, West Coast at 300,000 and the Northeast system around 575,000 barrels per day.

Total refinery operating expenses are expected to be lower than second quarter levels at about $4.25 per barrel.

With respect to some of the other items for the third quarter, we anticipate G&A expense to be around 160 million, depreciation and amortization around 300 million, and net interest expense should be about 45 million.

And lastly, a couple of weeks ago we completed the IPO of Valero GP Holdings LLC, which holds Valero Energy's interest in Valero LP.

The IPO resulted in a pre-tax gain of approximately $125 million or around $0.12 per share, which will be reflected in July's results.

Net proceeds from the IPO was approximately $355 million.

I will now the call over to Rich to discuss refinery operations.

Thank you, Mike.

Operationally, we had a challenging quarter with good execution of planned activities and several unplanned outages that affected our overall performance.

The key planned events in the quarter were the major turnarounds at Paulsboro and QuÃ(c)bec.

In May, we completed the successful turnaround at the cat cracker and alkylation units at Paulsboro.

This included expansion retrofits on the major vessels on the cat cracker and the addition of a new power recovery turbine.

In June, the QuÃ(c)bec refinery completed a major plant-wide turnaround, having completed successful five-year operating run.

It was well executed; it came in on-time and on budget.

We also successfully commissioned to new distillate hydrotreaters as part of our ULSD program in the second quarter, one in Quebec and the other at Lima.

We also revamped existing distillate hydrotreaters at Texas City and Wilmington, so those plants are now producing ULSD.

On the unplanned side, we had several outages that affected our income levels given the high product margins during the second quarter.

In May, we had a fire at the St. Charles refinery on the distillate hydrotreater, caused by piping corrosion in the high pressure air fin cooling circuit.

This system had an unusual piping configuration making the pipe thinning difficult to detect.

Fortunately, we had identified the need for additional fireproofing in this area of the plant during our prepurchase due diligence inspections.

Having installed the new fireproofing, we effectively limited the impact of the fire and allowed the rest of the plant to resume operations quickly.

At Aruba, we had a plant-wide power failure that significantly impacted the plant's operations in June.

Aruba is unique in our refining system, as it self-generates its entire electrical load with only limited electrical backup from the island utility, and no availability of natural gas for plant fuel.

While we have made good progress in improving the reliability of the plant power system, recently going over a year without a significant power outage, we did incur an electrical fault that cascaded into a plant-wide failure.

With the need to fully restore all plant fuel, steam, and power utilities from a cold start, it took nearly two weeks to re-establish operations.

Also in June, operations in Corpus Christi were significantly disrupted by extraordinarily heavy rainfall, over five inches in one hour, and lightning strikes that resulted in a storm water tank overflow and fire that significantly damaged stock shipping lines.

Lastly, we had unplanned downtimes at Texas City's coker and Port Arthur's (indiscernible) reformer that limited operations at those refineries.

In total, the impact of these outages was roughly $275 million or about $0.29 per share.

We are continuing to emphasize operating reliability within our refining system with special emphasis at those plants where we assumed legacy equipment issues following acquisitions.

Such issues were certainly a factor in the second quarter, as was the impact of severe weather.

We're confident that our improvement programs will yield sustainable improvement over the long-term.

A good example is our OSHA VPP program where we now have 11 out of the 12 -- out of the 21 U.S. refineries certified as Star Sites under OSHA's Voluntary Protection Program.

Meeting OSHA's rigorous requirements supports improved refinery safety, operations integrity, and reliability.

With the second quarter issues largely behind us, our system is currently running well and producing at near record rates of about 3 million barrels per day.

Looking forward, we will be bringing on a lot of new equipment as we continue with our tier 2 fuels programs and strategic project implementation.

This will include grass-roots a lot of distillate hydrotreaters at Ardmore, Memphis, and Port Arthur.

We will also include the second phase of our crude and coker expansions on Aruba, and the Port Arthur crude expansion that will be up in November.

At Port Arthur, this is a 75,000 barrel per day expansion that will take the refinery to 325,000 barrels per day of capacity by running additional medium to heavy sour crude.

As Mike mentioned, turnaround activity in the third quarter is pretty light, with the only notable activity being the crude unit and coker turnarounds at Aruba that are now under way, and the Lima cat cracker turnaround that begins in September.

Now, I will turn it over to Greg King for an overview of industry fundamentals.

Thanks, Rich.

I'll start by talking about the gasoline market, then I will cover distillate, and finally our outlook for sour crude oil discounts.

As I discussed last quarter, gasoline margins have been terrific since early March, and what's been unique about this year is that margins have remained consistently strong despite record imports.

As you know, the U.S. needs about 1 million barrels a day on average of imports to keep up with demand.

But earlier in the summer, gasoline imports reached 1.6 million barrels a day, as refiners that could send product here pulled down their inventories to capture the high margins.

Despite that wave of imports, margins remained strong.

Imports have now dropped back down to around 1 million barrels a day, yet the Gulf Coast gasoline margins remain over $20 a barrel.

We believe this is because the global gasoline market is very tight, particularly when it comes to low sulfur MTBE-free gasoline that is sold in the U.S.

Plus, European gasoline in inventories are at five-year lows right now, so there is limited spare capacity to ship to the U.S., particularly as demand in Europe has picked up for summer vacation season.

Also, because of the stringent sulfur specs and the removal of MTBE, the bulk of the imports this summer have been low octane components that still need a high octane blending component like alkylate, reformate or ethanol to be marketable as finished gasoline.

Supplies of these components have been very tight, causing prices to spike to record levels and making it more difficult to blend finished gasoline.

Couple these supply constraints with stronger than expected demand, and you can see why margins are so strong and why the outlook is for more of the same.

Looking at the futures market, Gulf Coast gasoline margins are trading at $21 a barrel for August and $17 a barrel for September.

By comparison, last year's third quarter, Gulf Coast gas crack averaged $19.38 a barrel, which was primarily driven by Hurricanes Katrina and Rita.

And based on July actuals and the forward curve for August and September, this year's third quarter should average about $1 better than last year.

The gasoline market is great, but the diesel market has never looked better.

On-road diesel days of supply is now in five-year lows, with on-road diesel demand the highest ever for this time of year.

The high demand is coming at a time when the refining system is facing supply challenges caused by the progressive transition to offer low sulfur diesel.

By October 15, low sulfur on-road diesel supplies must be at retail locations.

We think this will lead to supply constraints and certain markets, primarily caused by various logistics issues.

Given all the uncertainty around this transition, and the current tight supply situation, we've seen premiums as high as $14.75 a barrel for Gulf Coast on-road diesel versus off-road diesel.

Now going forward, we expect the premium to average $5 to $10 a barrel.

And keep in mind this is especially important to Valero, as 75% of our distillate production is sold at substantial premiums to off-road diesel or heating oil.

And the forward curve for Gulf Coast on-road diesel is showing even higher margins as the year progresses.

August and September are currently trading around $19 a barrel, and the fourth quarter is trading slightly above that.

So, as we move out of gasoline season by early September, we anticipate moving into a very strong distillate market as we head toward winter.

Turning to our outlook for sour crude oil discounts, with the exception of ANS and SJV for our two West Coast refineries, we expect all of our discounts to remain wide for the foreseeable future.

We have been saying this for quite some time, and we really don't see anything that is going to change our bullish outlook.

Globally, there's plenty of low quality crude oil on the market, but limited refining capacity to economically process these crudes.

As we have stressed repeatedly, this is great for Valero since we have the hardware to benefit from these lower-cost crudes.

Also, the strong margins in refining throughout the world have led to high utilization rates, which puts more residual fuel oil into the market.

This is because the incremental refining capacity around the world is less complex and doesn't have the hardware to upgrade the bottom of the barrel residual to light products.

This excess residual then competes with heavy sour crude as a feedstock for complex refineries, which puts additional pressure on heavy sour crude prices.

Remember, over 40% of the Maya crude price is based on residual pricing.

Currently, residual is pricing around $25 a barrel under [WTI], and the Maya discount is around $16 a barrel.

We believe this discount could widen even further as it usually does in the back half of the year.

So with that, I will turn it back over to Bill.

Thank you. 2006 is going to be another record year for Valero.

As good as the first half has been, we expect the second half of the year to be even better.

Currently, First Call estimates are expecting lower earnings in the back half of the year and we don't think that will be the case.

Even using First Call, we expect that free cash flow this year will be over 2.7 billion.

As we've said and our recent presentations, we are committed to carefully using our cash flow to enhance our long-term competitive position in the industry and create additional shareholder value.

We continue to look for acquisitions that meet our criteria.

As we have demonstrated, we like to acquire assets that have been underinvested in or underutilized.

We are also carefully managing our capital budget.

We have told you that our capital budget will be in the $3.5 billion range this year.

There are cost pressures, just like everyone in the industry had mentioned, but rather than increasing our spending, some projects are being deferred into the future.

In closing, I'd just like to reiterate that we're very bullish about the future, and that you should continue to see the tremendous earnings power of our assets in this environment of tight refining capacity, strong refined product demand, and favorable discounts for low quality feedstocks.

We strongly believe that our stock is the best value in the refining sector, especially when you consider the valuation for complex refining [assets] that have recently been announced.

Going forward, we will continue to execute the stock repurchase program that Mike previously discussed.

With that, we will open it up for Q & A.

(OPERATOR INSTRUCTIONS).

Arjun Murti, Goldman Sachs.

Thanks.

Bill, just to follow up on your recent CapEx commentary, it sounds like you want to stick to your budget, so some of the projects are being deferred.

Should we assume that in future years, you're going to lose some of the clean fuel spending that was required for this year and last year?

But will that amount it made up for by new strategic projects, so you'll be around 3.5 billion?

Or could the CapEx be either meaningfully lower or meaningfully higher than that?

The previous guidance that we had given for next year is 3 billion.

Obviously, though, as we and others have said, costs are clearly increasing.

As we look out here, we're in the middle of our strategic planning.

We're looking at all of our projects, rerunning economics in light of the higher costs that we're seeing, and at this point in time, I'd like to wait here for another month or two as we finalize all of our budgets for 2007 as they are.

Okay.

And just a follow up relative to Greg King's comments in terms of how tight some of the blending component markets are.

Can you comment on Valero's position as it relates to blending components?

I assume you are at least balanced if not slightly long, and what plans do you have to invest in more alkylation capacity or what have you to increase the supply of those blending components?

I would make a comment from octane producibility point of view, we are continuing with our program to convert idle MTBE assets to produce isooctane.

We recently completed projects at McKee and Texas City, and we have a project underway to convert our facilities in Corpus Christi in [old affects] complex, which would be sometime next year.

So we are continuing the program that we had laid out for ourselves, which does allow us to have octane we can sell into the marketplace.

Arjun, this is Joe Gorder.

You know -- obviously the alkylate prices are very strong and the premium regrades very strong, and we are slightly long alkylate.

That's really helpful.

Thanks a lot.

Doug Terreson, Morgan Stanley.

Congratulations on your record results, guys.

My question regards free cash flow and the share repurchase program which you guys touched on.

And on this topic, it appears that between cash that is likely be on the balance sheet and free cash during the second half of '06, that is in a scenario whereby spreads in the futures market are sustained in their current levels, Valero should be able to repurchase around 5% of its equity in the next two quarters, which I think Mike pointed out was the objective for the year.

And so my question regards whether or not this assessment seems valid, and maybe more importantly, whether any such free cash flow surplus would be utilized to expand the share repurchase program, and if not, what's the updated priority for those -- for any such funds?

Once we finish what we had said, which is the 5% for this year, then we said that we will go back to the Board and ask for some additional authority.

However, we also plan to build some cash on our balance sheet.

I mentioned a couple of times, next year we have almost $300 million of debt that comes through that we intend to pay off, and also we have another $175 million of debt that we can call economically which today would be our plan to do so.

So we intend to do that.

Also, relating to the capital spending question we got earlier, we're going to see where we are in our strategic plan.

But clearly, the stock repurchase program is part of our -- what I say more is our balanced approach to managing our business.

Okay, Bill.

And also, could you provide an update on the hedging program for all of the major products and the production mix for '06 and '07, that is if it exists, and any volume and pricing information that you may be able to share with us at this time?

Well, I'll tell you on forward sales in the sense of hedging, we just have minor little positions on there, and they're insignificant in the scope of things.

Doug Leggate, Citigroup.

Thank you.

Good afternoon gentleman. (multiple speakers) A couple of things for me on the dynamics of the second half of the year.

First of all, as -- (technical difficulty)

Doug, are you there?

Sounds like you lost us.

Yes, why don't you go on to next one and we can come back to Doug later.

Nikki Decker, Bear Stearns.

Good morning.

Rich, you talked about the downtime in the first quarter.

Would you just update us as to what the status of those plants is right now?

Sure.

We have two outages of significance currently.

We have a cat cracker at St. Charles down for refractory and slide valve repair.

It should be back in service by roughly August 8th.

We also have the coker down at Texas City.

It is down for failure on the wet gas compressor and it should be back by around August 8th or 9th.

And -- thank you.

So the cat cracker at St. Charles, is that related to the fire?

No, that's independent of the fire.

And what I might note, when we did the due diligence on this refinery acquisition of St. Charles, it has a cat cracking technology that's unique in the industry.

I think there are less than five of these types of cat crackers that have been built.

We have known for a long time that this particular design is not as robust as some of our other cat cracker designs, and we have anticipated making a retrofit conversion on this unit at some point going forward.

And that is under evaluation.

I think your question also refers to the issues we brought up in the second quarter, and those plants are all -- those issues have been solved and the plants are back up and operating.

I see, great.

Thank you.

And just secondly, the expansion of the cat at Paulsboro, would you to talk about how that will affect volume yields and realizations at that plant?

That was about a 5000 barrel per day expansion, taking the unit from about 50,000 barrels per day to 55,000 barrels a day.

The income numbers I don't have handy at this point.

It's not a real major impact.

It certainly helps that plant, and reliability is a key factor there, but it's not a big throughput change.

We had continuing problems with the cyclones once there with erosion.

We completed that so we should get a longer run length than we've had in the past.

It will make 3000 to 4000 barrels a day more gasoline, but the main driver there was to fix all of the issues we had around that cat cracker.

Great.

Thank you.

Paul Sankey, Deutsche Bank.

Good morning, gentlemen.

Can we dig down into the diesel market a little bit more?

Firstly, on a regional level, could you talk about any problems with transporting ultra low-sulfur diesel that you may be seeing and how that may affect regional markets?

And secondly, you mentioned that demand was very strong for diesel.

Do you think that's driven by internal demand?

Can you speak a bit more about that?

What I am thinking of here is the extent to which higher sulfur diesel is being exported, and I have a follow up.

Thanks.

Okay.

On the regional issues associated with diesel, the group has been a bit of a challenge.

And I think we've seen that because of the price spikes.

The markets have reflected the tightness of supply there, and it's all logistics related.

Refining is not having any problems producing ultra low-sulfur diesel and we'll be in good shape there, but logistically, we're challenged at getting the product moved and getting it to the destination on spec.

And so what you saw in the group was off spec product not being accepted at Magellan coming off the [Explorer] system.

And as a result, the positions needed to be filled with product that was purchased in the group, so we had a spike there ULSD over LSD.

It was $0.10 to $0.20.

If you look at the Gulf Coast, you're at $0.02.

So I think what we're seeing here is spec changes cause challenges, and in this case, they tend to be logistic challenges.

Do you guys relatively benefit from that, or does it mean a lot to you, or can you talk a little bit more about that?

Well, I think it's temporary.

So any benefit that we would have would be temporary in this case.

I suspect that these logistics issues are going to be resolved similar to the situation we had with ethanol, and they won't be lasting.

That's great.

On the diesel demand story, can you talk a little bit more about the dynamics there?

I would be interested regionally there as well.

Well, there's a couple of things I think.

The low sulfur demand is up a lot more than high sulfur.

Part of it is because high sulfur is just not available (indiscernible) anymore.

So off-road is having to use low sulfur even though they don't require it, because high sulfur is not available.

The other factor I think where you see -- we've seen demand up 4% over the last four weeks.

We're seeing some export demand for particularly the high sulfur diesel out of the U.S. and other areas of the world.

So that's also contributed to strong U.S. demand.

Right, that's great.

And finally, from me in a separate question, you counted yourselves out of the Lyondell refinery sale.

Can you talk a little bit about your -- could you update us on your acquisition philosophy?

And I am thinking there international -- whether or not you might be thinking internationally now.

Yes, we are.

Valero is still very interested in acquisitions.

They need to meet our criteria, which we have confidentiality agreements with everybody which do limit what I can say here, but as a general statement, consistently we have said that we are interested in Europe, primarily because of an Atlantic basin presence that we have at least on the western side of the basin, and so we continue to be interested.

Okay.

And what about Asia?

We haven't looked at Asia because we frankly haven't decided how the correct way Valero could enter that kind of market when we look at the players that are in that business.

So to be specific on Europe, I guess that's export-oriented products coming back into the U.S. is the kind of area you would be looking at?

Not necessarily, but that was a great question.

What we look for is a balance that lets us have the same opportunity to play the arb and to emphasize our trading capability.

But no, we would like to have backup local demand as well.

I will leave it there.

Thanks a lot.

Jeff Dietert, Simmons & Co.

Good morning.

I wanted to follow up on the question on MTBE plants and see if you could give an update of the MTBE production and how much you think that will evolve to over time, and how much alkylate or isooctane production you have now and where that evolves to.

The only MTBE production that we have today is still at Corpus Christi, and that volume is not being used in United States.

It is being exported.

We're making in the neighborhood of about 15,000 barrels a day of MTBE.

Of MTBE --?

Of MTBE.

That plant is scheduled, as Rich said, to be converted to isooctane early next year.

And the equipment and things are in process here.

And so that's the plan on that and that is what we are doing there.

When you make isooctane out of -- versus MTBE, we will make less yield.

That plant will only make about 12,000 barrels a day of isooctane and that's because obviously you don't have the methanol in the system.

So, you actually make a good octane blending component, back to the previous question, but you don't have the same volume.

The other plants that Rich mentioned are small plants off the cat crackers that take isobutylenes, and what we have done there is gone ahead and converted them.

And they make [so much] volume in the same ratio.

But it is a good blending component.

We haven't converted all of the plans we had because some have pressure issues or, in one of our plants, it's not economic.

How much volume is coming from McKee in Texas City?

McKee in Houston will be --

They're about 1000 barrels a day each.

That's fairly small.

It is small.

But they were small plants to start with.

They only made several thousand barrels of MTBE anyway.

Very good.

Thank you.

Chi Chow, Petrie Parkman.

Good morning.

I have a follow up on Paul's question from earlier.

Can you give us any comments, Bill, on the Company's potential interest in a reported new refinery in Central America?

This is the one, I guess, that you read in the press, and we attended the meeting in Houston -- I assume.

Anyhow, we were asked to attend that meeting by Mexico and we did.

We're obviously -- have excellent relationship with the Mexicans.

And so we attended the meeting.

Our interest would be at this point -- we went to the meeting, but this project has many, many hurdles to overcome.

Okay.

Are the Central Latin American regions of interest you?

As to -- no, you're asking to a grass-roots refinery, and I would tell you that grass-roots refining is difficult to see the benefits from our side.

When you have, as we said consistently, we have Aruba.

And Aruba has excellent access into Latin America as well as South America.

And we've also said, when you look at the numbers, that expansion at existing refineries is far more economic than grass-roots refineries in our part of the world.

Okay, thanks.

I have another question on your crude slate, in particular on the West Coast.

Can you give us an idea of what mix of crudes you ran in 2Q out there?

Do you have that?

I don't have it.

Well, I can tell you that we run ANS, Maya, we run some SJV.

We run [Thumbs]; that is down in L.A.

So at Wilmington we run Maya, Thumbs, probably a couple of Latin American crudes of naphtha and [Oriental].

At Benicia, we run about 65,000 barrels a day of ANS.

We have run some SJV.

And there will be some other crudes to fill out the refinery there to the 135.

Okay.

Has that mix changed, say over the last year or so?

Not so much in the last year, but we have reduced, for instance, ANS.

If you look at the differential, today it's $1.25, less than WTI.

But when Valero bought the refinery, they ran 105,000 barrels a day of ANS, and today, as I just mentioned, we're down to about 65.

And as we go through time, we will obviously continue to attempt to reduce that.

The reason we don't is crude availability on the West Coast as well as the assets we have at Benicia.

Okay great.

And one final question on Maya.

Do you have any longer-term concerns regarding the reported decline in production down there?

We had several meetings with our contracts at PMI and Pemex.

They are confident as they supplement the Maya production with -- (indiscernible) KMZ crude, that they will be able to maintain the Maya production level here for the rest of the decade.

Longer-term, sure, we look around the world here for the heavy sour crudes and we see more availability of those longer-term coming out of the Middle East for heavy sours.

Then, as (indiscernible) just a wildcard to all of us.

Okay great.

Thanks Bill.

Jennifer Rowland, J.P. Morgan.

Thanks.

I have a question on the Port Arthur expansion.

I think I heard you say that the timing of that is now November, and the last time you gave guidance it was September, so just wondering what's causing that to slip again, because I think it had originally been a midyear project.

Sure.

I do want to confirm we're looking at November.

We have seen gradual slippage in a number of large projects, and it is all representative of this post-hurricane construction markets where labor availability is at a premium, materials availability is very, very difficult, particular on alloy components, and heavy wall reactors and on machinery.

So we have seen a number of projects slip a month or two, and that is what's representative here at Port Arthur.

Okay.

And just another one from me.

On the third quarter guidance, why is it that you're forecasting mid-continent throughput to actually be lower than what you did this quarter?

Is there some planned maintenance there?

Yes.

We have the Lima cat cracker turnaround in September.

How long will that be?

That is going to be about 30 to 35 days.

Okay great.

Thank you.

Paul Cheng, Lehman Brothers.

I have a quick question.

When you're talking about third quarter earnings outlook, are you including the [trial sands] of the assets of the IPO gain that you mentioned earlier?

Well, it will be included, but I think Mike will tell you the details.

Yes, what we were referencing there, $0.12 will be in our July number, but we're excluding that when we talk about a comparison to second quarter.

I see.

Okay.

And also, Michael, when you -- I think you mentioned earlier that you had some benefit in the second quarter from the Canadian tax law change, the tax reduction.

Can you quantify for us?

Yes, the total tax benefit there was 54 million.

That includes both the Canadian change and the Texas change.

Okay.

And also, Mike, is there a minimum cash balance requirement that need to run your system efficiently that you can share with us?

Is it 300 million, 200, 400, 500 -- any number?

The minimum number that we like to have is around 300 million.

Okay.

And maybe this is for Bill.

Bill, some of your competitors have [enlarged] some (indiscernible) to go into the renewable field.

Is that a business -- wondering that -- what's your view on that?

Do you guys have any interest in -- to follow suit?

And also, if you can comment about how is your ethanol logistic supply right now that we're seeing?

Earlier in the year [that is] quite a mess.

Are you guys seeing some relief and getting much better now?

The second part of that, obviously prices have fallen significantly from those spot numbers you heard.

Remember $5 for ethanol, so the answer is supply has loosened up tremendously.

We've seen much more supply in the market.

But the other thing the has happened is the logistics have been finally ironed out in getting ethanol from the rail yard over to the terminals, which was a huge bottleneck here in Dallas, Texas and some in Houston and then back in the Philadelphia area.

So clearly, there's more ethanol supply.

The logistics have also gotten better, and thus the pricing has come down as we expected.

To your first question, clearly we think -- you're talking ethanol primarily at the moment here, and clearly, we think alternate fuels are going to be part of the mix.

We don't think they will be a significant part of the mix, but they will be part of the mix.

But to Valero specifically, I don't see us running up to Iowa and building a corn-based ethanol plant at this time.

I'm not saying that we won't look for something unique, but actually, we would want to have some technology or competitive advantage in that business.

And for us, just to build a corn-based ethanol plant in Iowa does not appear to me to be something stockholders would want us to do.

Okay.

One final question.

Bill, by early September, if we look at your output for the ultra low sulfur diesel as a percent to your total on-road diesel to date, what's that percentage maybe?

At the end of October?

By September, because I think that the [law] you said you can sell 80% of your on-road diesel as ultra low and then the other 20% is just current diesel standard.

So by September, what way are you on that?

Are you 80%, 85%, or 70%?

We're going to get you a number here, but remember, it is 80/20, but you have 13 months average, okay?

Sure.

That's why I asked that, to see where you --

Yes, it's 40% by the end of October.

He is asking September.

Do we have September?

Well --

Because I mean you have to start shipping, if you assume that the ultra low diesel to the pipe by September, right?

In the 35 to 40% range, but remember, we have the end of September period, but we have the 80/20 is a 13 month out.

Right.

So that means that you expect sometime that by maybe early next year, you get close to 100%?

Well, just remember that we have Houston, we call it a mild hydrocracker, but it's a big project in Houston will come on the first quarter.

And in the second quarter, we have our St. Charles mild hydrocracker coming on.

But end of the year, we have the Corpus Christi -- by the end of '07, the Corpus Christi hydrotreater coming on.

And we have another one, Rich.

Well, we have two distillate hydrotreaters that we are yet to bring on this year, one at Port Arthur which will be up in September, and one at Memphis which will be up in October.

So actually this 13 month compliance period fits our system as we're bringing assets on-line.

Just to be clear, Paul, we do not make 100% because at Delaware -- and we make some today, but at Delaware and Paulsboro, we haven't started our project there.

I see.

Very good, thank you.

And there we have the heating oil [mark].

(OPERATOR INSTRUCTIONS).

Philippe Lanier, Banc of America Securities.

Good morning.

The first question I have for you is regarding the [Amulary] refinery in Venezuela.

Could you guys give us some insight as to what you see happening there, what it might do to gasoline imports to the U.S., and more importantly, I think for my question, what kind of quantity of heavy crude it might release to the market and where you think it might be going?

Well, I think all we can really tell you at this point is that they said it's going to take them to months to repair, and I've seen numbers that are longer.

So I've seen numbers that said six months and I saw a revised announcement that said two months.

I think beyond that, it's very difficult for us to comment on their business.

Is the -- I don't know if you know this, but is the crude they run there, is that a type of crude that you could run through Port Arthur or one of your other facilities?

Do you guys know?

I don't know what their crude is.

No, I don't think we know, but I would tell you we're not having any trouble buying crude.

So there is not an issue here, and the discounts for heavy sour excellent, as we say, anyway.

Right.

I think it might even improve that if those are out for six months.

That is a fair assessment.

Right.

Another question I had was just on the comments you made earlier in the call in terms of the spread between premium and conventional gasoline and RBOB clearly has been widening quite a lot.

Could you comment on what you might see in terms of the volume side of things?

Could that also have been correlated with a falloff in volumes, the premium and some RBOB given the tightness in the octane requirement?

And have any of your volumes fallen off a little bit in that regard?

Let me let Gary Arthur just tell you a little bit about our own retail operation, which will be the best thing (inaudible).

Thanks, Bill.

In our own retail, we've seen a very slow decline in premiums as prices have risen and people I think have been fuel switching.

We run about 11% total premium in our mix if you include the midgrade portion of premium that is blended into that.

That is down about -- just under 1% from last year, so we have seen some small decline, and it was down about 1% from the prior [period].

Thank you.

And just one last question as it relates to the hurricanes that could be forming in the next two months period, if it's anything like last year, could you comment on anything that you might have learned or experienced in last year's season that might help you in preparing for an unfortunate eventuality this time around?

I would say the primary thing that we learned is the availability of emergency materials, portable generators, trailers for housing people can be very, very difficult to get.

We were very successful last year because we were very assertive in our efforts to acquire materials.

As it relates to this hurricane season, we were advised months ago by our suppliers that it would be helpful for us to put equipment on reserve anticipating a lot of industry demand.

And we have had expenditures of about $5 million to put a lot of emergency materials on reserve for Valero use, so I would say that was a key learning.

Great.

I think I heard from another caller -- just want to confirm.

Most of your refineries, if not all of them, in the Gulf Coast are somewhat protected against storm surge.

Is that the case, or are there any that are potentially at risk?

Well, we don't have the vulnerability that some of the refineries experienced that were closer to the coastline.

Great.

Thank you very much.

Many places we would have some levees, but it depends on the magnitude of the storm surge as to how much you can do.

And remember we did lose Port Arthur last year for about three weeks before we actually got started up, and that was because of power pole damage and things like cooling tower and along those lines.

It just takes time.

We learned some of our vulnerabilities, and we're attacking those, but they take time.

Fair enough.

Thank you very much.

Sunil Jagwani, Citadel.

Sunil Jagwani from Citadel.

My question was developed your views on ethanol and what you guys expect in terms of capacity that's coming on.

And also, do you guys think that there is a chance that with continued build out of ethanol capacity, that we might have enough addition to the gasoline pool that hurts margins, perhaps four or five years out?

Well, current ethanol capacity it's just over 300,000 barrels a day.

That's up from 150,000 barrels a day just a couple of years ago, so it's really come up pretty strong.

We see renewable mandates are going to require about 500,000 barrels a day by 2012.

And it looks from our standpoint right now that there will be -- that capacity will be available probably prior to 2012, maybe as early as 2010.

There is enough to meet the current renewable mandate.

And how would you characterize the risk of there being an overbuild?

Overbuild?

Yes.

Well, I think that what you're seeing with all the activity in it right now, there probably will be some overbuilding, but it will find its home into conventional gasoline.

What drove the price up earlier this year was the demand going into reformulated gasoline.

If reformulated gasoline is around 3 million barrels a day, 10% ethanol, you need about 300,000 barrels a day just to meet the RFG demand.

So almost by definition, any additional capacity is going to have to go into conventional gasoline and compete into that market.

And then one follow-up regarding M&A in Europe.

When you said that Europe is something you would consider, does that include Central and Eastern Europe as well?

We're interested in acquisitions, but we're not looking at anything there.

Thank you.

Mark Gilman, Benchmark Company.

Good morning.

A couple of things.

You referred to some projects, Bill or Mike, that are being deferred to '07.

I wonder if you could be specific.

We've had a generalized deferral of projects.

I don't think we would say that we have a major strategic project that's been moved out.

We are evaluating the timing of investments in Aruba, for example, because we have a number of large projects under consideration.

I think we just had a very generalized movement of small refinery projects from third quarter/fourth quarter into first quarter next year.

And as a general statement, Mark, also, just our own projects that we have had major emphasis on, Houston and St. Charles, for instance, have both slipped as we said earlier.

So it's a combination of our own projects slipping and then managing our capital and a few things that we look at, we're now re-looking at the economics in light of higher costs, and we pushed them out into next year.

But nothing of major strategic.

Okay.

I wonder if I could just clarify the Port Arthur expansion numbers.

I note that the inputs, I believe, in the second quarter, were 302,000.

Yet the expansion, I think Rich said would take it to 325 with a 75,000 expansion.

The numbers don't quite add.

How should I look at that?

My numbers are purely quoted on a crude basis as opposed to total throughput.

So we run in the neighborhood of this 250 to 260 of crude oil at Port Arthur.

It's a 75,000 barrel a day expansion.

And then from that expansion, we're going to make somewhere in the 30 to 40,000 barrels a day of more diesel fuel, and then the rest will be [gas alls] in that business because we're not expanding those other units.

And we'll use those gas alls in our other facility.

I got it, thanks.

Bill, any specific interest in either (indiscernible) or Chevron's interest in the Europort plant that they indicated is now available for sale?

We're -- we are interested in Europe as I said, and we have confidentiality agreements where we're interested.

And I got in trouble because I commented on another refinery we were looking at here a few months ago, so I'm not going to go any further.

Just one more.

Let me check a reporting thing.

I want to be sure that the gasoline volume you're reporting as refinery yield system-wide now, that includes or excludes an ethanol component where applicable?

Can one of you guys answer that?

Excludes it.

Excludes.

Excludes.

So when we look at comparisons versus the prior period, we're looking at essentially an RBOB versus an RFG that included MTBE.

Is that accurate?

(indiscernible)

Yes.

Yes.

Thanks very much.

Good talking to you, Mark.

Roger Read, Natexis Bleichroeder.

Thanks.

My questions have been answered.

[Gary Wilhelm], [NEV Consultants].

Good morning, gentlemen.

I have two questions.

The first is on the Maya discount.

About six months ago, you predicted that for all of 2006, it would average between $16 and $20, in the first half is slightly under $16.

And then from -- from late June, it kind of peaked at $18 and now it's down.

I'm wondering if you still think it's going to be -- it's going to average $16 to $20, maybe a little bit of an explanation for why it would have dropped from late June.

Yes, I think our view would still be the $16 range throughout the year.

It's going to fluctuate month-to-month.

One of the key components we mentioned earlier was residual pricing.

That has an impact.

As residual prices move, it also moves it as well.

Gene, do you have any other comments?

Pemex has tightened their K factor, which is their discount to the formula.

It's their -- it'll last a couple months.

Otherwise, just looking at residual prices alone, they probably would be $18, $20 right now, but they tightened up on the K factor.

Okay.

Great.

My second question is going back to something Bill said earlier.

And I want to agree wholeheartedly with what he said, because as a long-term shareholder, I agree that Valero is by far the best value in the refining sector, particularly given that it should be plain to see that you're going to do $10 of earnings this year given that you've done $4.29, $3 plus in the third quarter and so forth.

And given that the Company on average trades at a multiple of slightly under $10, the only question is kind of when you get to $90 or $100.

So given that, and given that you could have completed your entire 5% share repurchase at under $60 this quarter, my question is when your shares are being dumped at giveaway prices like they were in this quarter, why can't you be more aggressive and less balanced in your share repurchases for the benefit of long-term Valero shareholders?

It's a fair comment and I can tell you we've been out of the market for the last two weeks because legally they said we had to be out.

If you go back, your hindsight is right, so I am just going to say you're right.

But as we have done this, we said it was a program for the year, and that's how we've been managing it.

Keep in mind we bought over 20 million shares in the first half of the year, so of the total we've levered a lot of it toward the front of the year. (multiple speakers) your comment in mind.

Mike gave the number, but we have purchased 23 million through basically July 15.

Yes, I'm just observing that -- look, under $60 is a complete giveaway given your earnings.

Even if you had to borrow another $600 million this quarter to buy shares under 60, you're saving yourself between 50 and 100 million if you have to buy those shares over 65, which I'm sure is going to happen.

I guess the only other thing I can say is we are returning the money to the shareholder universe.

So --

If you have any follow, Gary, you can give me a call off-line.

Okay thanks.

Doug Leggate, Citigroup.

Can you hear me now?

I'm sorry about the other problems.

My question goes back to the blending issues.

I really just wanted to get a sense as to whether or not you see the alkylate octane RVP issues being repeatable say over the next year or two.

So as we move into summer next year, do you see the same kind of difficulties?

If you could relate the same issues to what the changeover to ultra low sulfur diesel means for hydrotreating capacity, or more correctly, the utilization of the hydrotreating capacity?

Well alkylate, the reason it's valued so high is it really is needed to make the lower base pressure RBOB and CaRBOB, and without MTBE, it's really the elixir to fix almost anything with the high-grade gasoline.

So that really isn't going to change much next year.

In fact, if anything, the early sulfur credit expires in this year.

We are going to have to go to (indiscernible) credits, and basically what that means is I think the whole pool is going to be pushed closer to the 30 [PPL].

This year, you could really blend up to an 80 PPM and buy some -- a lot of early credits that were generated.

The vintage credits next year are much tighter.

They are going to be less volume available to do that.

So bringing in some of the 120, 150 PPM imports and blending them down to 80 and buying credits is going to be much more difficult next year, or to do so, you're going to need more and more alkylate.

So I think directionally, I'd say that issue is going to be even tighter next year.

Okay.

I guess as we move into winter and we move back to higher RVP gasoline, do you see an exaggerated decline in the gas cracks or the gasoline cracks, or do you think other factors are going to keep [it fairly tight]?

Well, the issue we were talking about was alkylate.

That is mainly a summertime issue that it's this tight.

Making RBOB in the wintertime is going to be easier.

You put butane in to help to lose some of the sulfur and trying to make a five-pound gasoline to go into RBOB is not the issue there, so clearly the winter is not going to be as tight as the summertime.

But today's supply is at 22 days, which is very low for this time of year.

I think just overall the refining fundamentals, supply and demand are tight on that -- on an annual basis, but seasonally, yes, we probably (indiscernible) see a little bit of falloff from $22 crack that we have today for sure.

And the forward curve indicates that falloff if you actually look at the numbers, but everything else that would -- that you mentioned is known in the industry.

The fourth quarter gasoline crack is obviously down from today.

Okay. (indiscernible) gentlemen.

Once again, apologies for the earlier problems.

Thanks.

[Don Perry], [Don Herald Inc].

Good morning.

Lyondell recently pulled this refinery -- that it has to sell, didn't seem to be for lack of an adequate price.

And without revealing anything specific, is it something that you took a look at?

I'm just wondering what comments you have on that.

Since I already got in trouble with them --

Oh, is that the one?

Then don't comment.

I announced in our European roadshow that Valero was not pursuing that any further.

And that roadshow was back in early June.

I missed that then.

Okay.

So we were not in the mix here at the end.

Thank you.

Mark Gilman, Benchmark Company.

Mike, just a follow-up or two.

You mentioned a 54 million tax benefit associated with the Canadian reduction and the Texas franchise tax.

Is there a onetime tax-deferred piece of that?

That's all that is.

That's the tax affected -- or that's the --

Recovery to prior --

The recovery -- the deferred tax reduction rolled through the tax provision.

So the entire 54 million is a onetime benefit?

Yes.

And obviously those deferred tax were accrued in prior periods at the higher tax rate, and so when the tax laws were decreased, we were allowed to reduce our deferred tax liability.

Okay.

And with respect your DD&A in a number and the 300 million, is that a good quarterly run rate going forward?

I think you said when you were talking about the second quarter that there was some catch up associated with the Premcor plants, particularly in the mid-continent.

If the second quarter was a catch up, I don't know understand why 300 is what we are looking for going forward.

Well, as Rich mentioned, we do have several projects coming on-line this quarter and next, so we did have about 10 million of catch up (technical difficulty).

But with the additional projects coming on-line in the third quarter, we think the 300 number is pretty good for the third quarter.

We have a large capital budget, obviously, (technical difficulty) $3.5 billion more.

And these things are getting completed as we outlined -- the big jobs.

We also have lots of little jobs we're getting done all the time.

Okay Mike.

Thank you.

At this time, there are no further questions.

Mr. Fischer, are there any closing remarks?

I'd just like to thank everybody for being on the call.

If you have any questions, feel free to give me a call afterwards.

Thanks.

This concludes today's conference call.

You may now disconnect.