瓦萊羅能源 (VLO) 2006 Q1 法說會逐字稿

Good morning.

My name is Kimberly and I will be your conference operator today.

At this time I would like to welcome everyone to the Valero Energy first 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 would now like to turn the call over to Eric Fisher, Vice President of Investor Relations.

Please go ahead, sir.

Thank you, Kimberly.

Good morning and welcome to Valero Energy Corporation's first 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 our Refinery Operations; and other members of our senior management team.

If you have not received the earnings release and would like a copy it's available on our website at www.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 Joe, Kim or myself after the call.

Before I turn it over to Bill I would like to direct your attention to the forward-looking statement disclaimer that's 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 managements expectations or predictions of the future are forward-looking statements intended to be covered by the Safe Harbor provisions under Federal Securities laws.

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

And with that, I will turn it over to Bill.

Thank you, Eric.

Good morning, and thank you for joining us today for our first quarter conference call. 2006 is off to a great start with the first quarter being the best in Company history.

Even though margins were volatile during the quarter it demonstrates what we have been saying for a long time: The highs are higher and the lows aren't as low and won't last as long.

Early February was a good example of this when gasoline margins weakened considerably, but within three weeks had refounded to around $8 per barrel on the Gulf Coast and by March were up in the high teens.

What is also impressive about our first quarter results is that we had nine refineries with units in turnaround, mostly in the month of March when margins were at their highest levels for the quarter.

The fact that our earnings were as good as they were with that many turnarounds demonstrates the benefit of having a large geographically diverse and complex refining system.

And based on what we see in the market today we expect that we will also be talking about record earnings on the second quarter conference call.

Mike will run through the first quarter results with you in a moment, but I first want to make a few remarks about what we are focused on right now.

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

In the first quarter our total capital expenditures were 975 million, 200 million of which was for turnarounds.

As part of the turnaround work we made several investments to improve efficiency and to get ready for ultra low-sulphur diesel production.

We also continued our strategic investment program that focuses on reducing operating costs, improving reliability, lowering feedstock costs, and improving [crane] product yields.

Rich Marcogliese will highlight some of these projects in his remarks.

For the full year we are focused on keeping our capital expenditures at around 3.5 billion.

The slight increase in our expected capital expenditure budget for this year from 3.4 billion is primarily due through the purchase of industrial gas supply-related equipment at our Port Arthur refinery, which was being financed by a third-party for Premcor.

This added around $70 million to our $3.4 billion budget.

As for acquisitions, they will continue to play a role in our future growth.

We will continue to seek out assets that we can upgrade and that compliment our system while offering us a good growth platform.

However, we will not over pay.

Financially, we delivered on our commitment to return cash to the shareholders.

In addition to paying off 221 million of long-term debt we purchased 10.7 million shares of our common stock.

For the year in total we expect to buy-in approximately 5% of our outstanding shares under our existing repurchase program.

Upon completing these purchases we will consider going to the Board for additional repurchase authority.

We also intend to continue to evaluate modest dividend increases.

Recently we filed an S-1 Registration Statement with the SEC in order to IPO a portion of our partnership interest in Valero LP.

We intend to eventually sell all of our interest in the LP and the proceeds will be used for general corporate purposes which will include funding acquisitions, stock buybacks, and debt reductions.

Now, I will turn it over to Mike Ciskowski to walk you through our financial results.

Thanks, Bill.

As the earnings release points out our earnings were the highest first quarter results in Company history with net income of 849 million or $1.32 per share.

On average for the quarter, refined product margins were very good but as Bill alluded to February margins were weak.

Fortunately, margins in January and March more than offset that.

The average product margins for the quarter are provided in the earnings release tables and in reviewing those numbers you will also note that sour crude discounts remained wide, which gave us a solid earnings space even when gasoline margins were under pressure in February.

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

Now on the cost side, first quarter operating cost at the refineries were down 45 million from the fourth quarter, this was primarily due to lower natural gas costs.

However, on a per barrel basis operating costs were up slightly from the fourth quarter levels and that was due to reduced throughputs from our turnaround activity.

General and administrative expenses were 151 million.

And as you may recall from the last earnings call I mentioned that starting this year information services costs would no longer be allocated to the business segments but instead go into the G&A line.

So on an apples-to-apples basis, G&A costs were down 32 million from the fourth quarter primarily because overhead costs related to Premcor came in much lower than what we had budgeted.

Depreciation and amortization was 260 million, which is essentially flat with the fourth quarter.

Interest expense net of capitalized interest was 59 million, a decrease of 16 million from the fourth quarter.

That was mostly due to the full quarter effect of paying off the term loan used to purchase Premcor and also to increase capitalized interest.

With respect to our debt position at the end of March our total debt stood at 5.1 billion, which compares to 5.4 billion at the end of '05.

We finished the quarter with our debt to cap ratio at 23.5% versus 24.8 at the end of last year.

Now looking ahead to the second quarter for your modeling purposes you should expect to see Gulf Coast refinery throughputs of approximately 1.6 million bpd, Mid-Continent throughputs of around 550,000 bpd, West Coast are at 300,000, and the Northeast system around 525,000 bpd.

The Northeast system volumes are lower than normal due to turnarounds at the Quebec and Paulsboro refineries.

Total refinery operating expenses are expected to be lower than first quarter levels at about $4.10 per barrel.

The decrease of $0.35 is primarily attributable to the higher throughput.

With respect to some of the other items for the second quarter we anticipate G&A expense to be around 160 million, depreciation and amortization should be around 270, net interest expense should decrease to 50 million, and you should be using a 34% tax rate.

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

Okay, thank you, Mike.

Operationally, this was an important quarter given the unusually high level of plant turnaround activity in our system.

We were particularly pleased with the execution at the Corpus Christi East refinery where we made major reliability upgrades to the coker and completed the turnaround on time and on budget.

Krotz Springs also did a very good job with the work they did on the crude and cat cracker turnarounds.

At Aruba, in addition to completing a turnaround and expansion project on the No.

II Coker, we commissioned the Visbreaker along with a new sulphur plant.

The Visbreaker allows us to process an additional 30,000 bpd of heavy sour crude and improves the overall conversion capability of the refinery.

Adding the sulphur plant eliminated ongoing acid gas flaring, which was unexceptably high.

Since taking over the Aruba refinery we have reduced sulphur emissions by nearly 90%.

The most expensive turnaround was at Memphis where we conducted a plant-wide turnaround that began in February.

Unfortunately, that turnaround lasted longer than planned primarily due to shortages of skilled trades.

The plant was competing with other Gulf Coast refineries for labor, which as I'm sure you've heard from other energy companies is an extremely tight market right now.

Next, let me give you a quick update on Del City.

Many of you are familiar with the historical problems associated with the coke gasification unit.

Due in large part to the operational and technical expertise we have brought to that facility we were able to operate the unit in the first quarter at 1,000 tpd of coke destruction with 96% mechanical availability versus 7 to 800 tpd historically.

Currently, we are running at nearly 1300 tpd.

This is a big improvement and we plan to continue moving that processing rate toward our goal of 1800 tpd within two years.

Keep in mind that for every increase of 100 tpd we achieve that translates into an incremental $5 million in annual operating income.

As expected, cash operating costs in the Northeast dropped significantly to about $4 per barrel in the first quarter, which should be a good run rate going forward and hopefully trending lower over time.

The Port Arthur refinery turned in an outstanding operating performance and had the distinction of being our most profitable refinery in the first quarter.

Not only does the Port Arthur refinery have an outstanding set of processing hardware but it also has an exceptionally talented workforce and a very capable leadership team.

Turnaround activity in the second quarter drops down significantly with Quebec undertaking a crude unit, cat cracker, and CCR reformer turnaround.

Paulsboro also has a cat cracker turnaround and expansion project underway and at Aruba in June their other coker will come down for a turnaround and a planned expansion project along with the crude unit.

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

Thanks, Rich.

Let me walk you through where margins are currently and where we see them headed.

Refined product margins in April have been extremely good.

Gulf Coast gasoline margins have averaged $24 a barrel and low-sulphur diesel margins have averaged nearly $18 a barrel.

For comparison, last year in April the Gulf Coast gasoline margin averaged $12 a barrel, while the low-sulphur diesel margin was around $11 a barrel.

The factors that we outlined last quarter, heavy turnarounds, the transition to summer grade gasoline under the lower sulphur standards, ethanol replacing MTBE in reformulated gasoline, and solid demand, all have contributed to the tight market we've seen in April.

These challenges are likely to persist as we head into summer.

And moving into May the industry will need to see gasoline inventories build, as they typically do each year, in order to have enough supply to meet peak summer demand in July and August.

Given all the challenges we are facing this year in making on-spec U.S. gasoline, we believe margins will need to remain high in order to attract sufficient imports.

Another way to look at the gasoline market is on a days-of-supply basis.

In the U.S. gasoline days-of-supply stands at 22.2 days, which is very low for this time of year.

Gasoline demand is up about 1% YTD.

And by most accounts, the economy is strong and consumers are continuing their normal driving despite the higher pump prices.

Globally, gasoline demand is also up YTD driven not only by growing economies, but also by rapidly accelerating car sales in China and India.

Now looking at the future's market it also confirms our expectations of continued strength.

Gulf Coast gasoline margins are trading at around $19 a barrel for May and at around $17 a barrel for June.

Now when you include April, the second quarter Gulf Coast gasoline margin would average around $20 a barrel.

It's also worth noting that the third quarter Gulf Coast gas crack is trading at just over $14 a barrel, which would be the best third quarter ever if you exclude the hurricane impact from last year's third quarter.

Even though we had a very warm winter distillate margins are also outstanding.

The Gulf Coast high-sulphur diesel margin for April has averaged $13 a barrel, but it's also important to watch the low-sulphur to high-sulphur diesel spread.

Right now that premium for low-sulphur diesel is about $6 a barrel, so effectively the low-sulphur diesel margin is currently at around $19 a barrel.

And since 75% of our distillate production prices like low-sulphur diesel, this is a meaningful distinction.

And the forward curve for low-sulphur diesel is showing higher margins as the summer progresses.

May and June are currently trading around $16.50 a barrel and the third quarter is slightly above that.

Turning to our outlook for sour crude discounts, we expect all of our discounts on sour crudes to remain wide this summer, primarily due to continued strong demand for sweet crudes and ample supplies of sour grades.

Sweet crude prices are at record levels today not only due to geopolitical concerns, but also due to increased demand for sweet crudes as refiners globally try to produce lower sulphur products.

We've even seen some of this in our own system like in Houston where we are processing more sweet crude in order to meet the new low-sulphur specs.

Also, when light product margins are high sweet crude demand goes up because sweet crudes have a higher yield of light products.

With respect to heavy sour crude discounts, more residual fuel oil is in the market now that winter is over and refiners are returning from turnaround.

Those increased supplies put pressure on heavy sour crude prices since refiners can substitute between residual fuel oil and heavy sour crude.

Currently the MIA discount is $15 a barrel and should trend higher as the year progresses.

Mars, which is a medium sour crude, is currently trading at a discount of about $6 a barrel.

In general, we are seeing more deepwater Gulf of Mexico crudes finally returning to the market following last summer's hurricanes, which should support wider discounts going forward.

The bottom line is that we expect this to be another record-setting summer for earnings.

Keep in mind that we've got the additional 800,000 bpd of throughput from the Premcor refineries that we didn't have last summer.

So refining margins don't even need to be better than they were last summer for us to achieve higher earnings.

And with that I will turn it back over to Bill.

In closing, I would just like to reiterate that we are very bullish about the future and that you will see in the coming quarters the tremendous earnings power of our Company.

Even with all the rhetoric that's going on today there is very little that can be done in the short-term to increase supply.

But rather than talking more about how great our business is and how well Valero is positioned we will go ahead and open it up to your questions.

[OPERATOR INSTRUCTIONS].

Your first question comes from Paul Sankey of Deutsche Bank.

Hi, good afternoon, gentleman.

You just referenced the rates that we are hearing today, could you talk a little bit to the -- what President Bush -- and I understand if you haven't seen exactly what he said -- but can you talk a little bit today about today's comments that he's made, particularly regarding changes to EPA standards that are potentially there?

Thanks.

Sure.

I will speak on that.

I don't know if I heard all of it, but clearly we have said forever that we do not think that we should be filling the SPR.

So that is a good move when they stop filling that.

High gasoline prices are not good for Valero nor the consumer nor the industry.

So we are very supportive of seeing the prices come down at the retail pump.

So not filling the SPR is good, having some temporary relief, if it actually does increase supplies is good.

So we would be supportive of all of those actions.

And I would point out that most of those would be temporary measures anyway.

Sure.

And you've referenced imports.

Could you talk a little bit more about your outlook for imports, which I guess are the big threat to margins in the U.S. staying higher this year?

Well, imports have been high throughout the year and I think it's just the fact that U.S. demand is exceeding our internally capability to supply the market, so imports are really pulled in to really -- about supply and demands.

And we see that continuing because I think demand is going to outsize the U.S. supply this year, particularly with -- as MTBE comes out of the pool and we are going to rely on more imports to solve the supply and demand balance.

But it's going to attract -- take a certain margin to attract the cleaner barrels that we require here.

Okay, so you think that it's a margin issue regarding more imports of product rather than -- if you like a constraint from imports coming in based on the fact that they don't meet spec?

Well, supply has to equal demand, so eventually the specification is going to have to be met but it's going to be met at a higher cost because lower sulphur and meeting gasoline without MTBEs is more costly produced than gasoline was last year.

So I think it just takes a higher margin to attract those imports.

Great.

And finally from me, you said that we are running at about 1% growth.

I guess that's partly based on what you are seeing through your stores.

Could you just talk a bit about the very recent trends that you've seen in demand as a result of the price ramping up in the way it has and if we are weakening?

And also what you are forecasting for demand to do this summer?

You've talked about it being high but if you could give us a few more specific numbers that would be great.

Well, YTD we are up 0.8% on demand according to DOE stats.

I think the latest three weeks were up more like 0.25%, so it's soft a little bit with the higher prices, but it's still net positive for the latest four-week average.

Does that tie in with your experience as a company?

Our Company retail stores, just in the month of April are up 1.5% on a same-store basis versus the same month last year.

But we are still seeing good demand from the industry.

Do you think that's a function of your location in the South or primarily -- or what do you think is driving that?

Well, I guess I would just say that we are seeing it across our entire network and we are in 10 states with 1,000 stores, so we don't see one region being substantially different from the other.

It seems to be fairly consist across our entire chain, company stores.

Right.

And your outlook is for a continuation of that, despite prices?

Well, I think the high prices -- and there have been some outages in certain markets have dampened demand.

We saw this last year with the hurricanes when we had very high or a price spike and we also had outages.

As soon as supply was back in the market and the prices came down some we saw demand recover immediately.

So as we look out here over the summer we have a very strong economy, we think people will drive.

Some of these actions may bring prices down a little bit at the pump and we think that's all good.

Great.

I will leave it there.

Thank you, gentlemen.

Your next question comes from Doug Leggate of Citigroup.

Thank you.

Good morning, gentlemen.

I also have a couple of questions, if I may.

First of all you mentioned -- you alluded to the way things spread with low-sulphur diesel and regular diesel, I guess.

Could you maybe try and help us with dates going forward because clearly there isn't a ultra low-sulphur diesel contract right now, so if you were to try to identify the fiscal margins that you guys are realizing right now versus what the indicators are telling us, could you maybe just walk us through that a little bit us we look forward through the second and third quarters?

Yes, well, like you said there really is no forward market there, so I think what we are seeing today is kind of an indicator.

We haven't even hit the ULSD requirement yet for the refineries at June 1, and a little bit later in wholesale and retail.

But I think they are going to stay more or less in the same range that we are at right now.

If there's any disruptions you could have some temporary price spikes, but I think it's going to be relatively wide and similar of today just, again, because a lot of the imports that need to come in don't really meet the 15 PPM spec.

Europe put 50 PPM and very few places in the world can meet our specification.

I think it's going to have to stay wide just for supply and demand to balance.

If I could just add, we have seen historically the prices, the premiums being about $0.029 to $0.03 a gallon and right now we're at $0.15 and it's $0.10 going forward.

So we do think it's going to be wider.

Doug, this is Eric.

But to help you -- help the analyst try to get some color on that, I mean we do put on the website each week kind of what the prior weeks average was.

And one of the items that I've been including is this what we call the "low to high spread."

That's the low-sulphur diesel minus the high-sulphur diesel, to help give you guys some clarity.

I know it's historical but it should give you a little sense of where we are on each quarter on that.

And you said 75% of your distillate product is pricing like that.

What would -- could you give us similar kind of comparisons for gasoline in terms of the RBOB and conventional gasoline split?

Well, RBOB -- the RFG components is what, about 30% of our total gasoline production.

Okay, and all of that is going to move through RBOB?

They include California, so the rest is going to be conventional.

Right, okay.

Great stuff.

My second question is sulphur from polls really, there hasn't been a lot of detail regarding the potential -- the call for potential EPA waivers, but just conceptually do you consider that a possibility would be pushing back the implementation date for ultra low-sulphur diesel, perhaps easing the phase-out of RFG oil -- the reinstating liability protection after May 5th?

Are those actions that you think could be conceivable in light of what's going on right now or are those -- do you think those are kind of off the page?

Okay, so this is going to be my opinion and so our opinion then is that the EPA is not going to push back the implementation date for ULSD for refiners.

It's still June 1st.

Now at retail they delayed it 45 days or something like that.

Now, they have made it where it's an averaging 13-month period.

They are aware that some projects are slightly behind and I will add that the EPA or the Administration will want a smooth -- as smooth a roll-out as they can get for ultra low-sulphur diesel.

So if there are disruptions that start to occur with diesel later in the year then I think you can assume that they would take some form of action.

Okay, I guess my final question then is you alluded to acquisitions and they are -- or at least you mentioned acquisitions in your rhetoric, Bill, in terms of -- that it's something you would still look at but you would not be prepared to over pay.

Clearly the CITGO Line -- [Laughter].

The CITGO Line/Del asset clearly has come in the market.

What would you -- when you say you wouldn't over pay are you talking about various replacement costs and, if so, could you just give us an idea of what you see -- where you see replacement costs stand in the industry, maybe on a stream-day basis?

Well, I will take the first part of that and say we will look at the line, Del/CITGO asset.

It's an asset that fits our criteria, over 100,000 run sour crude located on the water, and frankly, our Houston refinery is less than three miles away, so we know we would have a lot of synergies.

So like others we will look at it.

Now, when I say we do not intend to overpay, in our business we make a price call just like you.

We look out here and actually have a 20-year price call and we will go ahead and run different scenarios and we'll evaluate it, and we will run this as -- and to determine our price based on the economics that ultimately or is based on our price call.

Now, that's how we do it.

We will not do it looking at replacement calls.

That's very clear.

Gentlemen, thanks very much.

Your next question comes from Jeff Dietert of Simmons & Company.

Good morning, guys.

Hi, Gene was going to push a little bit more on the import situation.

I think the marginal gasoline -- gallon of gasoline in the U.S. is imported and the Atlantic arbitrage is wide similar to the way it was after the hurricanes.

And I would acknowledge that imports were very strong early in the year, but last week; for example, they were down 18% year-on-year and the tanker rates are just modestly responding to this wide arbitrage.

Could you talk about that a little bit more and what you think will be necessary to increase imports?

Well, I think part of the reason imports went down last week, there was some operating problems with St. Croix refinery and also Venezuela had some operating problems from the European refineries have been in turnaround.

So you had a little bit of disruption in imports just because of that.

Obviously, trying to meet the new specifications, 30 PPM gasoline and doing it without MTBE I think is also compounding the problem for places, that traditionally don't make U.S. grade gasoline like Eastern Europe and places like that that can't necessarily come in.

But I think as the price gets high enough what people do is segregate their cleanest components and do a grade that they can ship over here, even if it's blend stock that we can use to enhance our blending.

But you have to do it without MTBE and you have to meet the sulphur spec, is the bottom line.

Do you think -- do you sense there are a big shipment of imports on the way now or do you think process and margins have to go higher from where they are now?

I think the arbitrage is open, so I think that any barrels of it that can be made and shipped over here are coming here, but it's not just an unlimited supply, though.

Thanks for your comments.

Your next question comes from Doug Terreson of Morgan Stanley.

Congratulations, guys, on your record results.

With regards to capital spending it appears that a variety of entities in the petroleum sector are beginning to experience meaningful cost and timing issues related to some of the things that Rich talked about, that is, manpower, materials, et cetera as it relates to energy infrastructure and that includes refinery expansions, obviously.

And so my question regards your specific situation and whether you are experiencing similar issues and maybe you can expand on what Rich talked about, how you're handling them and also whether there is risk that you may not be able to fully spend your capital budget in 2006 because of some of these issues or whether or not it's manageable?

Well, I will take part of this and I'll let Rich add.

We expect to spend our capital budget this year.

We've taken steps to keep our projects moving.

But on the other hand we do intend to make this $3.5 billion of capital expenditures.

So we will not be under, Doug.

Okay.

And the only reason it's creeped up this 100 million is because of this Port Arthur situation, which is not the way Valero does business --.

Right.

-- and we cleaned that up.

So on that part of it, now, on the specific costs I think Rich can talk to you and give you some detail.

Yes, because it's not only an issue of timing, this scarcity of labor is also showing up as inflated labor rates and material costs, particularly in the Gulf Coast.

I mean we are seeing labor rate increases on the order of 20 to 25%.

In addition to higher hourly rates we've had to include per diem payments to hold on to people because there is some bidding for labor services going on in the Gulf Coast where workers are build -- or bid from one refinery to another.

So it supports the notion we're going to still spend our capital budget even though we're seeing extending timing, we're also seeing inflationary pressure on the cost of construction.

Sure.

Final question on the same -- on this same topic, an update on the Port Arthur expansion, any timing of that you guys may have?

Well, it was originally considered to be a mid-year project.

It's going to be more in the fall at this point, about a three-month delay, so we will say it's September.

Okay.

Good enough.

Congratulations again.

Thank you, Doug.

Your next question comes from Mark Flannery of Credit Suisse.

Hi, I don't want to get too micro on the MTBE issue, but could you give an idea of how much that the change over has already happened ahead of early May?

In other words, have we flushed a lot of this out of the existing system or do we go all the way to let's say May the 1st before flushing it out?

This is Joe Gorder.

I would tell you that in some markets we've seen it already flush through, Dallas/Fort Worth, for example.

Houston is in the process of converting today and we are going through some transitions up in the East Coast.

Now, as a percentage I don't know what that amounts to in total, but we are in process right now and I think a lot of the issues you are seeing at the retail level is associated with the transition of these terminals from RFG to RBOB in ethanol blending.

Right.

And are you getting reports in that people are having trouble making that transition or?

Well, the problem isn't with the supply of ethanol so far, the problem is getting the ethanol to the right place at the right time.

And; for example, in Dallas/Fort Worth we've had some outages and it's been related more to getting the ethanol from the rail yard into the product terminals for blending than it has been in availability of supply.

And then from the product terminals to the retail outlet because of this trucking has been very tight and part of that is because it's hauling ethanol from rail to the terminal, and the terminals have been doing their work to connect ethanol and shut down certain racks which makes their queue a lot longer, which then comes up with the driving limits that -- the driving time that drivers are allowed to stay on the road which causes that truck then to go off.

But what we've found it's been a transportation issue in the Dallas area with drivers running out of allowable time and that as opposed to anything to do with ethanol actually coming into the market.

So just to be clear ethanol is coming into the market roughly as expected, but it's the distribution of ethanol with the tripping of the allowable hours, et cetera, that is causing some trouble?

Yes, that's right.

Yes, and at the loading racks because several terminals only have one or two bays operating because they are making their revisions on the other bays, the driver sits there, he loses time and then he has to -- he can't drive.

Great.

Okay.

Okay, thank you.

That's very interesting.

Your next question comes from Roger Read of Natexis Bleichroeder.

Hey, good morning, gentlemen.

Can you give me an idea, you made a comment about switching over, using a little more sweet crude along the Gulf Coast.

Exactly how much would increase as is and is that something you will have to sustain going forward or is part of the investment in your ability to improve your yield or the use of sour crude, something that will change that in the future?

All right, we will try to get you a little better number here but, yes, we have switched over at Houston.

For instance, we have a much -- we've gotten a better operation, but the problem is in your residuals, when you are producing and selling those residuals the net backs are very low.

They work on the other side for us in the sense that we do by heavy [inaudible].

But because of our timing on our gasoline to sulphurization units we have found it advantages to run some sweeter crude oils just to make sure that we can make the gasoline sulphur spec product here, which you know changed January 1st.

These units are coming on for us and the Keys' units started up in March?

Just a couple of weeks ago.

And in Houston our units are coming up?

In October.

In October of this year on the gasoline side.

So we are doing these things and making it all balance, so that we have a spec product.

Now, the actual percentage.

Well, Houston is running about 75% sweet.

And that's been primarily the place.

We have run some sweet accrues at Ardmore and at McKee and that's because of the reason I just gave, either asphalt pricing at Ardmore and at Mckee it was to make specification gasoline.

Okay, thanks.

And then could you give us a little more I guess clarification or color on the expansion at Port Arthur and the timing on that?

Rich?

Sure, Port Arthur's capacity today is about 250,000 bpd.

The expansion project is going to take it up to 325,000 bpd.

It was originally envisioned for June implementation.

Because of this situation with the tight labor market and equipment delivery we've had to push that back to September.

Okay.

Thank you.

Your next question comes from Paul Cheng of Lehman Brothers.

Hey, Paul, are you there?

His question has been withdrawn.

Your next question comes from Chi Chow of Petrie Parkman.

Thanks.

With the Exxon reversal of their crude line from Patoka are you guys running any Canadian crews at Port Arthur at this time?

Yes, in the first quarter I said that we were receiving that the call -- the conference call back in January, and the fact was it was still in the pipe, but we have now received the Cold Lake crude?

May 4th.

May 4th we will actually receive it from Exxon, from that pipeline and we will run it at Port Arthur.

What sort of volumes are you talking about?

Volumes in the first batch was five a day and then we have got similar type of volumes coming in later May, early June.

5,000 bpd.

Are you able to run any Canadian at Ardmore or heed Cushing at this point?

We do not -- can't run it at Ardmore because we do not have the connections.

Cushings Northeast of Ardmore we don't have the connection.

I want to drill a little bit more on the op costs in the Northeast.

I recall fourth quarter you had a pretty good big turnaround.

Hey, Chi, can you either move closer to the phone please.

Yes, sorry, can you hear me?

There you are. [Laughter].

Sorry.

Yes, I wanted to drill a little bit more on the op costs in the Northeast.

It seems like in fourth quarter if I recall you had a pretty big turnaround in Delaware City that drove up costs there and in this quarter it came down but really not that much and it seems like you had better operations on the gas fire unit.

Is there something going on there that's keeping op costs on?

Well, what you have to keep in mind, we did have very large turnarounds in the fourth quarter, we had both the coker and hydrocracker down at Delaware City.

But in the first quarter we also had the CAT unit down for nearly the whole month of January.

We had an unplanned repair that we had to make on the CAT riser.

We had a large hotspot, so in a sense we did not get full volume metric recovery in the refinery in the first quarter.

That was all at Del City?

That was at Del City.

Yes, we had the CAT cracker, and spent 80,000 bpd unit, it was down essentially the whole month of January.

But you have no -- let's see, so you've got turnaround plans back in Paulsboro; is that correct?

That's right in the second quarter where we stand, the Paulsboro CAT cracker is down currently.

It came down earlier in the month of April.

It will be down for about five weeks.

We are going to install an expansion project at the same time.

The Quebec refinery will come down for a plant wide turnaround.

It will be implemented in two phases.

We will take the large crude unit offline right at the end of this week and we will take the CAT cracker down in about two weeks later.

All will be said and done by sometime around mid-June.

Okay, and then you expect kind of a $4 per barrel range going forward?

Yes, that's right on the cash operating cost basis.

Hopefully it will - it may turndown a little bit towards, keep in mind with the Quebec turnaround going on in the second quarter, Chi, that that will affect the per barrel buy, the back half of the year that we should be turning lower.

Okay.

All right thanks a lot.

Your next question comes from Mark Gilman of Benchmark Company.

Hi, guys, good morning.

I had a couple of specific things if I could, please.

How much ULSD will you be making on a system-wide basis starting June 1st?

10% of our total production.

Didn't hear that.

Wait a minute we're going to get you the right number.

We'll get you the specific number here.

It's currently about 10%.

We are producing ULSD at Three Rivers and we'll begin production in May at Delaware City, Texas City, and Port Arthur.

Hang on we're looking for a specific number.

That's 10% of your distillate order or 10% of total production?

10% of the distillate tools.

Okay.

Mark, you have got to remember too that using the 13-month averaging most of the LSD we were making will continued to be sold into the on-road market during that period as well.

So we really --.

I understand, I'm just trying to get a handle on the manufacturing side.

Oh, we are going to tell you if it's 10% it's about 100,000 bpd.

And that's what it will be as of June 1st.

In June.

At the end of the transition in 2007 we will be at 500,000 bpd of ULSD, which matches our current on-road diesel productions.

Okay.

Have you shutdown the corporate MTBE plants?

No, we have not.

We are not blending any MTBE for the domestic market, but we are exporting MTBC.

So it's running at normal rates?

It's running at a reduced rate but it's running.

And that's the on-purpose play you are talking about when we take normal butylene.

Right?

Right.

Okay.

Because we did shutdown the small plants inside the refinery to take the butylenes of the CATs.

Okay.

Did -- Bill, did I hear you say that the amount of RBOB production you anticipate is going to match what you had been producing in RFG?

No, I didn't say that.

No, I don't think Bill said that.

It won't.

It's more difficult to make RBOB and with -- we are expecting a 20 to 30,000 bpd reduction when you compare it directly to RFG.

And that is in what we are calling the next year.

We have said many times that we believe that the industry will have 145,000 bpd less gasoline production with the elimination of MTBE and the replacement with ethanol.

For us it's a law, it's 20 to 30,000 bpd, but that phases out over time because we are converting some plants to iso-octene and others are doing things along those lines.

Okay, Bill, that 20 to 30 reduction that's versus RFG with a 10% MTBE contents?

Yes.

Okay, I've just got one final one and that relates to octanes.

What kind of change do you expect in pool octanes as you look toward this summer and what modifications might you be making as a result thereof in the amount of premium versus mid and regular they should be producing?

Not exactly.

But obviously taking the amount of MTBE as pool, even the U.S. taking a 140,000 of MTBE at a pool at 108 octane is a lot of octane barrels if the industry is going to be short.

Hey, guess what we don't mind answering that for you.

We will have to put something together and tell you.

We will get Eric to give you a call.

Okay, guys.

Thanks very much.

Your next question comes from Gary [Wilhelm] of MVP Consulting.

Good morning, gentlemen.

I was wondering if you can tell me what the total opportunity cost in foregone operating income or EPS was from your nine or so turnarounds in this quarter?

It begins in May, right?

It was a grand total.

It was about $300 million.

It's a big number.

Okay, great.

And that was because our timing was -- we were down in March when we had very good cracks.

How much of that 300 -- would most of the 300 be in March?

Yes, I mean that was when the margins were the best.

The biggest impacts were on the Texas City crude unit turnarounds and then also the Memphis plant [LIFO] turnaround.

Those were the biggest contributors.

Well, let me ask you this, if you add in the 300 plus pro forma of your operating income for the first quarter and add in the 300, roughly how much of your operating income would have been earned in March because March was your best quarter in terms of spreads and April was even better than March?

Well, I don't think we really want to parse the quarter out like that Gary.

If you want to follow-up with me after the call then we can chat, but that's not really the way we look at it.

I mean obviously March was the best month of the quarter.

Okay, that's fine.

My --.

Because we really don't want to get into a month-by-month retake.

Okay, my final question is of your -- is your estimate of the Premcor synergies now is it higher or lower than your original 350 million?

It's actually higher.

We actually achieved 30 million last year for the four months we owned them.

We expect to have over 200 million this year and then as we begin to do the projects at the refineries we expect it to exceed the 350 million that we announced when we bought the company.

And roughly what quarter do you expect to be at that 350 million annual run rate?

Right now the plan is for the first quarter of next year, first quarter '07.

Okay.

Thank you so much.

Your next question comes from Fadel Gheit of Oppenheimer.

Fadel, are you there?

Fadel, your line is open.

His question has been withdrawn.

And the next question comes from Philippe Lanier of Banc of America Securities.

Good morning.

Thank you for your time.

I just had a quick question about your inventory management, I mean inventory from the U.S. and the crude side are definitely quiet high, and I imagine you guys are as well.

The question I have relates to the decision profits in that to what extent is it based off of how many days demand cover you want and to what extent is it based off of financial incentive?

And then secondarily, are you planning on building any new inventory?

If you are talking specifically about crude.

Yes.

We are sure that we have our refineries supplied, so it's always a supply question first and we look at it that way.

But the market is in [inaudible] or carry and because it's in carry, we carry -- we Valero are or have much higher crude inventories than we normally would have and it's because it's paying us to carry the inventory also.

First it's supply and it's always supply, but because we look at the markets we are holding [inaudible].

And has there been any discussions to increase inventory capability?

Well, you would have to build more tankage and because that's not something we are doing here at the moment the answer would be no.

Okay.

Thank you very much.

[OPERATOR INSTRUCTIONS].

Your next question comes from Wayne Cooperman of Cobalt Capital.

Hey, guys.

Do you all -- we know that talking about the CITGO refinery and people are throwing out big numbers and it seems like the new build cost keeps going up and up, and obviously you guys trade way below what it would cost to build a new build plus your -- I would imagine that your refineries are in locations that are better.

Do you guys look at it that way and do you compare your asset value on a cost basis versus an acquisition or is that not really how you look at it?

Well, we do calculate the numbers but we don't look at it that way.

Right.

We actually do, as I said earlier, we have a price projection and we will run our economics and determine it based on a rate of return or a hurdle rate that we want to achieve on an acquisition.

Do you do the same thing on your share repurchase?

No, we do not.

We just know that we are selling seven times.

But I guess we could always -- it seems like if you are buying at seven times at a much less than an acquisition that the hurdle rate on a share repurchase is probably even better than an acquisition?

Well, I think if you were here the first quarter we talked a lot about having a balanced approach to our entire business, between the rating agencies because we do want to get an increase in our investment grade ratings, and we intend to be responsive to them.

I would just suggest to use the same financial discipline no matter when -- whatever you spend money on whether it's CapEx, acquisition or repurchase.

Okay.

Well, I appreciate that.

Thanks.

Your next question comes from Daniel Burke of Johnson Rice.

Yes, good morning.

Just a relatively macro question on the ULSD market, how relevant will the credit system be here, particularly over the first 13 months?

And then secondly related, if you are to export diesel can you effectively remove it from your [Ardmore] pool and selling it at a higher international price then you might realize in the U.S. off-road market?

Yes, as far as the credit trading, the 13 months really -- the numbers Bill gave you a while ago we're only making 100,000 bpd day one, and 500,000 by the end of the period.

What the 13-month averaging really allows us to do to continue to sell about the same amount of on-road diesel that we are selling today, even though it's part of LSD.

So we will be fairly in the same balance we have been in the past.

As far as exporting, though, I guess if someone had barrels they couldn't get through credit into the on-road market and the off-road market price was not good enough in the U.S. you could see some exports.

We've seen Latin America importing diesel already because of their growing demand for distillates and I would expect that to continue.

Okay, thank you.

Your next question comes from Mark Gilman of Benchmark Company.

Guys, it looks to me as if there was a substantial working capital liquidation in the first quarter.

Mike, can you possibly confirm that and quantify it if I'm right?

I don't think there was a working capital liquidation.

We've been building inventory so our working capital would have gone up.

You think it's higher at March 31st than it was December 31?

Yes.

Inventory --.

Inventory.

How about overall working capital?

Yes, I mean I think the prices were up, too, so I would think the receivables would be up from the December levels, yes.

Okay, I'm having trouble making the funds flow fit in the absence of working capital liquidation.

Let me try one other one if I could, please.

I don't know whether this is a typographical error or not, but the footnote in the press release referring to the contribution of the Premcor refinery indicates or suggests that Port Arthur was running at 295 in the first quarter; is that accurate?

Port Arthur ran at, yes, 295.

You said the capacity was 250 and with the expansion it goes to three and a quarter?

Yes, that's 250 on crude.

The 295 represents total input including feedstocks above crude.

Which is how we consistently disclose our throughputs for refineries on a total basis.

Okay, guys.

Thanks.

Your next question comes from Fritz Vongart of Sage Asset Management.

My question has been asked.

Thank you.

[OPERATOR INSTRUCTIONS].

Your next question comes from Eric Johnson of Barclays.

Hi, guys.

Any plans to refinance the higher coupon Premcor paper?

Not at this present time, some of that is callable within the next year or two and it would make more sense to do it at that time.

Thanks.

Next year we have $289 million of bonds that come due.

Our intent would be to pay that off and then some of that other paper we think it will be callable in economics that are favorable to Valero.

175 is callable next year.

At this time there are no further questions.

Please proceed with any closing remarks.

Thank you, Operator.

If anyone has any follow-up questions, again, as I said feel free to call Joe, Kim or myself.

Thank you.

Ladies and gentlemen, this concludes today's conference.

You may now disconnect.