瓦萊羅能源 (VLO) 2009 Q2 法說會逐字稿

Good morning.

I'll be your conference operator today.

At this time I would like to welcome everyone to the Valero Energy Corp.

second quarter 2009 earnings conference call.

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

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

(Operator Instructions) Thank you.

Mr.

Smith, you may begin your conference.

Thank you, good morning and welcome to Valero Energy Corporation second quarter 2009 earnings conference call.

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

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

Also attached to the earnings release are tables that provide additional financial information on our business segment.

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

Before we get started I would like to direct your attention to the forward-looking statement disclaimer contained in the press release.

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

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

Now I'll turn the call over to Mike.

Thanks and thank you for joining us today.

As noted in the release we reported a second quarter 2009 net loss of $254 million or $0.48 per share which compares to $734 million of net income or $1.37 per share in the second quarter of 2008.

The second quarter 2009 operating loss was $317 million versus $1.2 billion of operating income in the second quarter of 2008.

The decrease in operating income was mainly due to much lower refining margins on diesel and jet fuel and significantly lower sour crude oil discounts versus the same quarter last year.

For example, benchmark, Gulf Coast, diesel margins versus WTI decreased 79% from $28.85 per barrel in the second quarter of 2008 to $6.16 per barrel in the second quarter of 2009.

Regarding crude oil discounts, the Maya, heavy sour crude oil discount versus WTI decreased 78% from $21 in the second quarter of 2008 to $4.57 per barrel in the second quarter of 2009.

Also the discount to WTI on the Mars medium sour crude oil decreased 69% to $2.19 per barrel over the same time frame.

Our second quarter refinery throughput volume averaged 2.5 million barrels per day which was in the range of our guidance but 257,000 barrels per day below the second quarter of 2008.

This decrease in volume was mainly due to lower utilization rates, unscheduled down time at McKee and Delaware City and a reduction in capacity from the sale of the Krotz Springs refinery in 2008.

Refinery cash operating expenses were $4.30 per barrel or $0.10 per barrel below our guidance and $0.23 per barrel below the second quarter 2008 due mainly to lower energy cost which was partially offset by write-offs on our canceled projects.

General and administration expenses excluding corporate depreciation were $124 million in the second quarter.

The decrease of $21 million versus the first quarter and $16 million versus our guidance were primarily due to lower expenses for incentive compensation and legal reserves.

For the second quarter, total depreciation and amortization expense was $389 million which was in line with our guidance but higher than the first quarter of 2009 due mostly to the addition of of the ethanol plant.

Interest expense net of capitalized interest was $82 million, which was lower than our guidance mainly due to the reversal of accrued interest on a sales tax audit that settled in our favor.

The effective tax rate was 40%.

Considering the loss for the quarter this rate was favorable to the guidance rate of 31% due to the use of the federal tax credits and state tax benefits.

Regarding cash flows for the second quarter, capital spending was $698 million which includes $82 million of turnaround and catalyst expenditures.

We are still on track to come in around $2.5 billion for total capital and turnaround cost this year.

Also in the quarter we paid $78 million in dividends on our common stock and we paid off $209 million of debt that matured in April and we also acquired the ethanol plants for $556 million which included working capital.

With respect to our balance sheet at the end of June, total debt was $7.4 billion.

We ended the quarter with a cash balance of $1.6 billion which includes the $799 million of net proceeds from the equity offering in early June, and we had over $4.6 billion of additional liquidity available.

At the end of the quarter, our debt-to-cap ratio net of cash was 25.9%.

As to the refining outlook, low product margins and narrow sour crude discounts were the key drivers of our second quarter operating loss.

Although product cracks have rebounded recently we expect refining margins and sour crude discounts for the third quarter to be similar to what we experienced in the second quarter which means we could have another loss.

And the fourth could be just as challenging.

What is needed is a sustained recovery in the economy to drive growth in demand for refined products and to also pull lower quality crude oils on to the market.

This leads into Valero's strategy, which is to maintain our financial health by cutting costs, optimizing our assets and preserving cash.

Our major growth projects the two hydro crackers on the Gulf Coast have been placed on hold until we have better visibility on the need for that capacity.

We have a comfortable cash balance partly because of the equity offering in June which was conducted to ensure we have a strong balance sheet to weather a low margin environment and to complete the acquisition of the interest in the TRN refinery which we believe was a high quality asset at a good price.

Although we didn't move forward on that transaction, we are not in a hurry to do any acquisitions.

For now, we will continue to focus on what is in our control, our cost structure and our refinery operations.

Now I'll turn it over to Ashley to cover the earnings model assumptions.

Thanks, Mike.

For modeling our third quarter operations you should expect the following refinery throughput volume.

Gulf Coast should average 1.2 million to 1.25 million barrels per day.

Mid Continent should average between 360,000 and 370,000 barrels per day.

West Coast should average between 270,000 and 280,000 barrels per day and the Northeast should average between 500,000 and 510,000 barrels per day.

Refinery cash operating expenses are expected to be about $4.50 per barrel.

Regarding our ethanol operations in the third quarter we expect total throughput volumes of $2.2 million gallons per day and operating expenses should average approximately $0.30 per gallon including $0.03 per gallon for non-cash costs such as appreciation and amortization.

With respect to some of the other items for the third quarter, we expect G&A including depreciation to be around $135 million.

Net interest expense should be around $110 million.

Total depreciation and amortization expense should be around $385 million, and we estimate a 30% effective tax rate.

We will now open the call for questions.

If you will go ahead and queue up the questions, we'll wait for those.

(Operator Instructions) Your first question comes from the line of Jeff Dietert with Simmons.

In your press release you talked about considering monitoring refineries for potential run cuts and shutdowns of units or other plants in addition to Aruba, can you talk about the process that you go through in that evaluation?

Jeff, this is Rich Marcogliese.

We obviously are watching the gross margin contribution of all of our refineries and that has a strong relationship to the kind of heavy sour crude discounts we have been looking at.

We are reviewing our refining system in addition to Aruba.

On Aruba we've placed the refinery in what I would call on a hot mothball status where we are conducting maintenance on the refinery.

We have retained all of our employees, but we have made an initial reduction in kind of the daily contractors that would support an active plant operation.

Should a plant move into a cold shutdown status, that would involve additional steps that would potentially impact employees and additional contractor reductions.

There are some required notifications in that process that would take place of a regulatory nature and then of course there's the Warrant Act which requires 60-day notice of any potential employee lay off impacts.

Do I understand correctly you review that again in September with potential bringing it back up in the economy and demand recover?

We are going to make a reassessment of where we are in Aruba in a couple of months and take a look at the margin contribution going forward to see if we should change it back into an active run status.

And am I thinking about things correctly in that you are buying crude 30 to 60 days in advance, so July and August runs are pretty well already established absent any unplanned down time?

Jeff, this is Joe and that is a fair assessment.

We have been buying crude to run at minimum run rates.

We've really changed the nature of our purchasing activity.

Historically we've been probably 60% contract and 40% spot.

Now goes the reverse and we are running much higher volumes at spot barrels which gives us more flexibility.

Would you avoid building crude inventories in this environment or is that a possibility as well?

Well, it's something that we are taking a look at.

I mean clearly with the market structure the way it is, the economics would support storage plays and we are seeing a lot of that out there.

So we are considering the opportunity to do that.

Thank you for your comments.

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

Hi guys.

Just an immediate follow up to that.

Does that mean you are not building inventories right now is that how I read that?

Or can you describe how you are handling inventory at this particular stage?

Thanks.

Well, clearly it doesn't pay us to gasoline right now.

So we have been keeping our gasoline inventories at absolute minimums.

We have been looking at storage plays on the distillate side and we have done some of those and on the crude side we are looking at the economics to do that today.

The issue is how you go about doing it, what would be the mechanics, and a lot of people are storing oil offshore on ships and that is one of the options we are considering.

We also have tankage available and will look at the options to do that also.

I understand and is it fair to say that regionally within the US it's more likely to happen Gulf to offshore than for example our suspicion is that Mid Con tanks are pretty much full up now?

You are right.

Great.

Back to a high level question, my original question was really regarding the cost savings that you talked about and perhaps some more on expenses.

You said here that you've saved $250 million since '07.

If I recall rightly, it was a target to get to $1 billion within five years of I think '06 back end loaded.

Can you just update us on how this cost might be saved in the context of that original target?

Thanks.

Well, let me speak first to the $250 million.

What we are doing there is that's more of a corporate initiative that is around the Company and also dealt with contractors at the refinery.

So for instance we outsourced medical claims.

We used to do our own medical claims in the Company.

To give you an example that's been a $12 million savings.

By the cost that we incurred with our own employees doing that and then also because of the provider was able to do this, give us discounts on the medical.

So that was just one example.

It also included a big reorganization in our retail group where they've saved 15 million to $25 million on the things that we've done over there.

So it's all throughout our Company.

I mean, I joke about it, but this is a pennies business.

The parking garage lights now get turned off at night, and that's worth $60,000 a month for us.

But this is our business.

This is what this business is made up of.

So we have many, many examples of that.

Now, this is a little different initiative.

There is a little bit of overlap to the $1 billion program, and the $1 billion program envisions reliability, energy, and then other expenses, and there we are only a little over 100 million when you actually attack the $1 billion, and that program is -- we've had a lot of trouble with reliability and of course as energy prices have fallen, the prize is not as big because we primarily use natural gas.

The prize is not as big as it was before.

So we have -- we still are working on that program, but our goal for this year, at the end of the year is -- was it 200 -- we will be a little over 200 by the end of the year, but we've lagged on that program.

Okay.

I understand, Bill.

If you can just go into expenses, in the case of a total shutdown at Aruba or anywhere else, is there a sense of how much the cost of that would be?

There is a sense.

We would have severance.

Of course, that's negotiable to a point in Aruba.

There are certain laws.

We do have contracts.

There will be other costs incurred.

We have a number, but I'd prefer to keep that to ourselves.

Then does the refinery get dismantled?

What we would do at this point in time is mothball the plant if that's what happens.

That plant is still on the market.

There are still people that are interested that have a different strategy.

There are several opportunities with adjacent countries that you could put a transaction together.

I'll remind you the cokers there are very good.

There's a lot of hydrogen generating, we've desulphurized.

There's a lot of assets there, but you have to have a integrated play here, and thus some of the people that we are still talking to that are interested in that refinery have an integrated approach.

Sure.

I understand.

But from an industry wide point of view what would we would expect some plants to be mothballed and then continue to have a minor OpEx associated with them on a go-forward basis until demand recovers?

I think that's very fair.

I had one last one.

I'm sorry to ask so many questions.

But, Mike, just to clarify did you say that the current market conditions for Q3 would mean another loss?

And possible a similar situation in Q4?

I was just wondering because obviously margins have rallied very strongly over the past couple of weeks.

Are you talking about Q3 to date or current margins or?

Okay.

We are just -- what I'm talking about is there's a potential for a loss in the third quarter.

If you look at the month to date prices and then our third quarter projection, the product cracks don't look that bad but the sour crude discounts are still under a lot of pressure.

So there's the potential for another loss in the third quarter.

If you actually look at our numbers, as Mike just said, the gasoline crack is frankly, excellent.

On the distillate crack it's not that bad but the Maya discount yesterday was less than $4 compared to the number we had for the second quarter last year just to give you an idea it was 21.

You can't look at it straight up like that.

It really needs to deal in a percentage but the percentage is very low from our end.

If you look at Mars, that is also very low, so the issue that heavy complex refiners such as Valero are having is with all the medium sour, heavy sour discount.

It is a huge change, and that was of course the reason for our earnings guidance in the second quarter and that is what Mike is saying, Unless we see some improvement primarily in heavy sour discounts and medium sour discounts, that would be our anticipation for the third quarter and the forward quarter would be just as challenged.

I don't want to go too much into the available time, so thanks a lot you guys.

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

Thank you.

A follow-up to all these questions.

Valero historically longer term has had a pretty constructive view of sour spread and light heavy spreads.

Has your long term view changed as a result of whether it's mix in declines and so forth and as you consider potentially shutting down or selling some refineries might it be some of those more complex facilities where in the past we would have probably thought it was in more of your light sweet facilities.

Thank you.

Our view certainly has changed on heavy sour, medium sours, and for the rest of this year what has to happen is we have to get oil production increasing in the world.

We need more 1%, 3% fuel back into the world which would come from the Middle East crudes being produced at a higher rate running through the hydro skimmers.

If you actually look at the number 6 fuel oil percentage of WTI price, you'll see that that percentage is very high or the discount is very low.

So fuel oil tends to be tight.

And fuel oil is influencing all of the -- certainly influences the heavy sour but it also influences the medium sours.

So we need to have the economic growth get back into the business.

So we get into 2010 then where oil production is now forecast to increase instead of decreasing like it is this year somewhere in the range of 1.7 million to 2 million barrels a day and that is on top of it decreasing in 2008.

So 2010 we get the increase somewhere between 1.5 million and 2 million barrels a day.

So that would help those.

Now, on the other side of this, it's much easier to have these cokers in the refineries and they basically have paid out so they are there.

Now, we are doing projects to produce more fuel oil in our system, but the coker is there, and we have this opportunity that no one else has.

It's much easier for us to go back riding all out on the coker operation than it would be for somebody else to go out and build a coker today.

So our view hasn't changed in the long run but it certainly has changed in the short run.

We still expect Canadian crude to come to the US Gulf Coast.

We still think there's a competitive advantage to have that hardware that can bust this stuff up and make quality products.

But short run, you are absolutely right.

That's very helpful, Bill.

If I can paraphrase it to make sure I understand it correctly.

In the short-term, or however long these narrow spreads last, those particularly complex facilities you have where the investments are paid out as you mentioned you might have meaningfully lower run rates but you are probably not looking to permanently mothball or sell those types of assets and you'll keep them for the days when OPEC production reincrease and the economy comes back.

So it's really more the fourth quartile light sweet refiners and what have you, that would be more on the block so to speak for investment or real closure.

Yes.

But it also has a reliability component.

There's also the capital investment component.

Typically a refinery, because you can adjust operating rate, so typically you can get a refinery where maybe it's breaking even by -- and I'm talking now on a cash basis by operations, but then if you are required to put in a lot of capital spending, that can put you over the hump to say the future doesn't look as good.

So the fourth quartile, third quartile type refineries that need a lot of capital that are just breaking even can be sweet or sour.

Aruba is a sour refinery, heavy sour but it doesn't have any upgrading capability there.

So your liquid volume yield loss through that refinery is very large when you consider it's just a coking plant.

So there is a little more to this than just saying a light sweet refineries.

Frankly today light sweet refineries are making money for us.

That is really helpful and I appreciate your answers.

Thank you.

Your next question comes from the line of Paul Cheng with Barclays Capital.

Bill, I think maybe two years ago that you have looking at your portfolio and identified this about 10 to 11, the coal holding.

Is that lease being changed or it is still pretty much the same mix if you are looking at it today?

The mix today it would be changed but it's academic because there's really not a market for some of these refineries anyway, at least the price we would want.

But the point is we did not anticipate such a dramatic fall in the medium and heavy sour discounts, and we did not see that coming, this kind of fall.

We never thought they would stay at $21 and $18, but we didn't see the Maya discount being just a little over 3, and we didn't see the Mars discount here that's less than $1.

Right.

So we did not see that coming.

Now, we have a couple plants that are sweet, that are very well run operations.

When I looking at the second quarter, I think it looked quite clear that Aruba and Delaware City probably lost money.

Other than those two is there any other refinery in your portfolio really is a big money losing operation?

Well, your assessment would be correct on those two.

We also have a couple of other plants that are not generating income.

And will you be willing to share what those?

I would prefer not to.

Okay.

And in the second quarter, is there any meaningful hedging or trading gain or loss?

Yes.

Mike?

In the second quarter we had, from our hedging, we had a $99 million loss.

And Mike, where is that, is it in the Gulf Coast or is it spread across?

That's pretty much allocated across our refining segment based on throughput.

Okay.

And, Mike, since I got you here, can I get a number of balance sheet item, what is your inventory market in excess of the boat, working capital, and the long-term debt component of the total debt?

Okay.

I'll give you the market in excess of book is $3 billion at the end of June.

Our balance sheet items total current assets are $11.2 billion.

Cash is 1.6.

So current assets less cash is $9.6 billion.

Current liabilities total 7.3.

Current maturities are just $137 million.

So our current liabilities less maturities is 7.2.

Net working capital is $2.4 billion.

And then total long term debt and capital leasing is $7.4 billion.

Thank you.

And is there a number you guys can share about the capital spending for 2010 yet?

Yes.

We are targeting around $2 billion, but it will most likely be between 2 billion and $2.5 billion, and part of that is driven because of our 114 where at Benicia we are building a scrubber and there's a tax advantage for us to finish that scrubber by December 2010, and that's a large project when you consider the heater scrubber, $650 million, and we also have the same (inaudible) which is the benzene where we lower the benzine and gasoline and for our whole system they get down to the 0.62 or less, we are spending $550 million.

Right.

It comes into effect January 1, of '11.

And so those projects we need to finish.

So the spending will be in the 2 to 2.5 range.

Right.

Should we assume that our (inaudible) the sustainable capital is about in the 1.5 to 1.7?

Yes.

We use 1.8 -- 1.8 until we finish the 1.14, and that finishes over the next couple of years and that will drop down to the 1.5.

Perfect.

And, BIll, in the, I understand the sensitivity on Aruba, can you tell us what is the current book advantage sitting on your book and also that mark, the annual labor cost for Aruba?

We'll tell you the book value.

The book value is about $1 billion dollars on Aruba.

And the annual label cost?

$200 million in cash operating cost.

We have about 650 employees on Aruba.

So you have to make some assumptions on what the average-.

We are trying to get you an answer here.

Cash operating cost around $200 million.

We have 650 employees in Aruba.

We don't have the number.

Maybe Paul you could call Ashley, and we'd be glad to give it to you.

That would be good.

And, Bill, can you help us understand a little bit why there was (inaudible) in the second quarter as bad?

I understand they have operating upset, but it seems like there's a huge loss that they suffered and the margin was so bad.

Paul, let me just make a couple of comments on the quality of the operations.

It's been very difficult for the whole first half of the year.

A lot of this originated with a major utility upset that we had on February 16 at which time we concluded that we needed to take the entire plant down for maintenance particularly in the utility area, and the plant remained down through about late April, early May.

In the attempted restart of the refinery in early May, we had an additional upset on the fluid coker which required a second outage.

So just to give you a sense for where we were, we've had 110 days of accumulated lost coker runs in the first half of this year, 67 days in the second quarter, and when you have the coker down at Delaware City, you also were unable to run the coke gasing fire.

So this was about as difficult the first half and second quarter as you can imagine and had a significant impact on the gross margin on that refinery.

I see.

Rich, I think when you guys announced the second quarter earnings a couple of months ago, you had indicated that what's the total trend, down time, your opportunity cost set to the Company, and at that time you were talking about $200 million.

Is that number being changed to be much higher now that we have the actual, and can you break it down into your four different operating region for us if you have a new number?

I think we have the -- we have the numbers in aggregate, for the first half it's about $245 million and for the second quarter it was about $140 million unscheduled downtime impact.

Okay.

Final one.

In ethanol, I presume that the operating cost in the second quarter, $0.32, that is not including the transportation cost and transportation cost is net of the operating margin that you guys indicated, a $0.47?

I think the transportation is included in that number.

In the $0.32?

That seems--?

On a net basis to the plant so--.

The way it's reported Paul it's in OPEC.

Transportation is not in OPEC.

Transportation is not in OPEC, it's net of the margin the way that you report.

In our refinery.

Perfect.

Thank you.

Your next question comes from the line of Neil McMahon with Sanford Bernstein.

Hi.

Just a few questions.

Other than Mayan crude, what other sources of heavy or sour oil have you seen missing from the market?

Is it mainly some of the (inaudible) volume and also Venezuela?

I'm just trying to think in terms of as we go forward we expect OPEC volumes to have to increase towards the end of the year and into next year.

I am just wondering when new heavy or sour sources of barrels will come onto the market.

Well, clearly the production of Maya crude is down, and we are not seeing as much in the marketplace.

The OPEC run cut pulled heavier sour barrels out of the marketplace also.

Venezuela on the other hand has been a much increased source of supply for us.

In fact I would tell you that we have really backfilled the reduction of Mayan barrels with Venezuela crudes because of economics but also because of availability and then we replaced the Saudi barrels in our system with US Gulf Coast medium sour barrels, which trade at better prices than the Saudi barrels right now.

Longer term as Bill mentioned earlier I think it's going to take economic recovery which will increase demand, increase refinery run and then OPEC will increase production and then we should see the sour discounts return.

So if we take the Maya situation, it's basically Saudi volumes that have come off the market that has been a major impact for you?

That's correct.

Second question.

Maybe a bit of a strange one.

Given your valuation, have you had any M&A interest on yourselves?

There are certainly a few companies out there that have acquired in the last 6 to 12 months, some refineries, national oil companies, potentially some would like a position in the US based on their own strategies.

Have you had any people knocking on your door?

I don't think I can comment on something like that.

Okay.

Just a final question.

Some investors have been asking me given the fact that you are not doing acquisitions in Europe, have you considered giving the cash back to investors or are we simply in a situation that given your near term outlook on the refining environment, it's just prudent having the cash on hand?

That's a fine question, and we have gotten that question from other people.

Technically, we are still on the hook for the TRN refinery.

The way the contract is written, if their deal were to fall apart with Totale and Luke Oil then Dow could come back to us.

Rest assured there would be some discussions, but we are still technically on the hook.

The other point is we have given you all some earnings guidance here, and certainly are telling you our issues on these medium and heavy sour discounts.

So when I still look around at the market and we see this whole cash and availability of cash, right now we are going to keep a very strong balance sheet as we said in our press release, and we are going to hang on to the cash.

Okay.

Thank you.

Your next question comes from from the line of Faisel Khan with Citigroup.

Good morning.

Good morning.

I was wondering if you could reconcile something for me.

I think previously you talked about a $99 million hedging loss.

Could you reconcile that with the $440 million decline that you guys talked about in derivative instruments in your second quarter '09 interim update?

Yes.

When we did the interim update it was about $440 million and then what happened since then was the loss on the paper actually decreased about $50 million from that interim guideline.

So 140, the number you said, it was 140ish when we did our preliminary announcement.

It ended the month because everything is mark-to-market, and so at the end of the month it was 100.

Now, in the first quarter we told you we had almost $300 million of gain.

Okay.

Understood.

And then on the ethanol, the ethanol segment for a second, the guidance you are giving of 2.2 million gallons per day is about 30, 35% higher than--?

2 million gallons.

2.2 million gallons per day is higher, 30% higher than what you guys did in the second quarter.

Is it fair to assume that if corn prices stay where they are, that there's a linear relationship to the earnings generated in the second quarter going into the third quarter?

The biggest reason second quarter was through the plants who weren't fully operational when we bought the plant only four of them were running, and we had start ups of the three different plants during various stages of the quarter.

That's a lot of the reason why we weren't at the higher rate.

Everything is running right now.

We have got good margins on every plant we are running.

Okay.

And there were also like costs incurred in the second quarter to get those up.

So you wouldn't want to make those linear just because the run rate is up.

It's a different environment.

Got you.

Going back to a previous question on inventory, what would you guys say right now your inventory level is at at the percentage of being full both for product included?

I have no idea what our total tank capacity might be, but our inventory levels are about 108 million barrels.

The reason that's hard to answer is there's so much product and crude oil that is in trend that we either own but it's not in our tanks and somewhere coming to us one way or another, but if it is important to you, we'd be glad to figure out what our tankage capacity is.

Okay.

But Joe gave you the number of our total inventory, 108 million barrels.

Got you.

Thank you.

I appreciate the time.

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

Thank you.

Bill, I have got a question on carbon legislation which you made some comments on again in the press release.

What's the basis for the million job loss comment?

And also the $0.70 -- $0.77 per gallon tax to consumers that you've outlined on the website?

Right.

There is a study that we have a source on the million.

There's a study for the million jobs and the heritage-- and the congressional budget office is the $0.77 number.

And there are others too.

Yes.

There are plenty of studies but I'll put it in perspective for you because this is huge negative for the consumer, for the country.

Our footprint is about 36 million metric tons, in the US, it's about 30 million metric tons.

If you say this legislation that we have to pass through or get charged for the CO2 omissions from burning the fuels that we generate, our estimate would be making 10 times, so that's 300 million metric tons, and then if you put 20, if you say these carbon credits are going to be $20 a metric ton now, then that becomes $6 billion, and that $6 billion we'll have to pass through to the consumer because they only gave the refiners free credit of 2% of the whole allotment.

If you look at it, the industry, if you add it all up, would be over 30% of the CO2 omissions.

So these are huge numbers that have to get passed through.

Do you have the source?

Yes.

The source is--?

Well, it's a study conducted by Charles Woodward Associates for the National Association of Manufacturers.

That is on the job estimate, job loss estimate and the other one is the congressional budget office, the increase in price of gasoline.

Bill, what is that 10 times multiplier that you talked about?

Well, the legislation is, our footprint that I say 30 million metric tons is the CO2 omissions from the refinery to take the crude to the products.

Then the way the legislation works, we would be liable for the CO2 omissions for the burning of the fuels that we have produced, the products.

So we are just using an estimate of 10 times because of all the fuel, like all the gasoline that gets burned.

And so our footprint then for the CO2 admitted at the refinery to make, we'll just use gasoline, and then the burning of the gasoline in the automobile would be 300 million metric tons.

So and then you have to pass all that through.

Got it.

We are the ones responsible for that, the way they drafted this.

The deal on foreign refiners, is they would only be responsible in this legislation out of the house for the CO2 omission as the consumer burned the fuel.

They wouldn't be liable then for the emissions at the refinery to make those fuels.

So there's an inherent bias to push you through imports.

This is legislation that I'm sure every house member read.

How do you think this is going to play out in the senate, and what is your desired outcome on carbon--?

Well, this is ludicrous legislation.

And we believe that the senate and also during this interim here, more data is coming out that is rush, rush to get things passed.

There is more data coming out on the impact of this proposed legislation.

So we think there's -- the people still are rational, and when it gets into the senate, that this bill eventually gets defeated.

How it turns out at the end of the day and if there's any CO2 legislation, I think remains to be seen.

India has already said they are not going to participate.

China most likely will say they are not.

If they do, they won't enforce it.

The trouble here in the United States is whatever gets passed will be enforced.

So the playing field is skewed tremendously.

But we, Valero, are going to be very active in trying to get grass roots through participation here on how much this means to the consumer, to this industry, actually to the American economy.

Every single good that is produced that has any energy component will go up in price.

It is a huge hidden task.

It doesn't seem like we are going to fail to get -- come away with no legislation at all.

Is there a lower level that you are aiming for at this point rather than cap and trade?

Well, I think we need to defeat this legislation.

If the government wants to tax carbon and if this is the will of the people and the government obviously, federal government needs cash, a carbon tax is certainly more visible and that would be Valero's position that if that's what's going to happen, let's have a visible tax.

It is a tax on carbon and then the consumer at least knows what he is being charged for.

Great.

Thanks for your thoughts.

I appreciate it.

(Operator instructions) Your ur next question comes from the line of Mark Gilman with Benchmark Company.

I had a couple of specific questions.

Rich can you say whether Del City is now fully back to its normal operating status?

Other than the coke gasifier, we have a couple of reliability issues that are holding the gasifier down for about a week to ten days.

But other than that, the rest of the refinery is operating normally.

Has that been the case since the beginning of this month?

We did have a power interruption over the weekend which was not our issue.

It was in the Delmarva power grid.

It did cause a disruption over the weekend which took down our cat cracker but it was put back on line yesterday.

Okay.

With respect, guys, to the Aruba decision, Bill, in the release you referred to the arbitration vis-a-vis the tax holiday, and I guess I'm wondering is it, the turnover tax.

I guess I'm wondering whether the tax holiday which I believe has a 2010, 2011 expiration on it, isn't that also going to be part of your thinking here as to what you do?

Absolutely.

The tax holiday ends at the end of '10.

Effective January 1, 2011, and it is an uncertain world in Aruba as to what goes on at the end of '10.

And then this BBO or turnover tax, we are expecting the answer to this arbitration.

And it's -- I'll remind you it's a 1% tax which in our business is a lot.

Bill, just a strategic question if you don't mind, and I got to tell you just don't understand.

In response to prior questions you suggested that the focus was to preserve cash, and I guess I just don't understand how the TRN acquisition had it gone ahead, was at all consistent with the implementation of that strategy?

Well, that's a fair question Mark.

It's not some -- without the TRN acquisition clearly we want to maintain cash.

We want to maintain a very strong balance sheet.

We have our projects that we are finishing here even though we have cut our capital spending down.

But we also want to grow our Company, but we want to grow wisely, and we want to grow in the interest of the shareholder, and we ship diesel fuel to Europe.

In July here we are going to ship, we'll average [165,000] of barrels a day of diesel that have gone to Europe.

We've said in all our previous calls that since about June or so of last year we've been shipping somewhere between 150,000 and 200,000 barrels a day of diesel.

We also have opportunities in Canada where diesel goes to Europe and frankly gasoline can come back into our Canadian operations.

So as we look at the Atlantic basin, Europe continues to be short diesel, long gasoline.

The US here at the moment is long diesel and we are still short gasoline because our country still imports gasoline.

So we look at Europe as a good trading, good arbitrage, good opportunity for us to work more aggressively in the Atlantic Basin.

And the refineries we have looked at, because things are coming on the market in Europe and they've been doing that for quite a while, you'll remember and I disclosed we had bid on Corrington in England.

We've looked at a couple of others, but TRN looked to us to be an excellent opportunity and also had the potential, at least from a management's perspective for a high success entry.

The cat cracker even though it was a partial interest and the complexity looks low to the investment community, the cat cracker -- the 68,000 barrel -- hydro cracker at 68,000 barrel a day unit.

We know what they're costing here in the States.

We are shipping the diesel to Europe anyway.

The netback is better obviously.

We think that's going to continue because the (inaudible) is crude, obviously why Luke Oil is interested and so it was the best operation and Totale runs a good plant, they are either first or second quartile in the European settlement survey.

So we are a refinery.

You buy Valero, you buy a refining Company and we think our business is eventually going to grow again.

It is not growing this year but eventually it will get going again, and we think we can add value with that.

But it's opportunistic.

People have asked us, well, now that this cash burning a whole in your pocket and the answer is absolutely not.

We thought that was the best thing we've seen.

Bill, wondering if I could just try from a slightly different angle and that is your comment previously that you have not given up on the longer term belief regarding the merits of high conversion refining and therefore wider discounts on the medium and heavy sours.

If that is indeed true, rather than investing when those discounts are optimal doesn't it make sense to be aggressively investing to the extent that your financial position allows in a period such as this and therefore not show some of the high complexity projects at the expense of either ethanol plant acquisitions or TRN or its future equivalent?

I think we are trying to balance everything Mark, and we still believe that the Canadian heavy sours will get to the US Gulf Coast but that is 2012 maybe '13 on the big projects.

So the Mexican production continues to fall somewhere between 150,000 and 200,000 barrels a day on a net basis on the heavy sour.

Venezuela, although Joe said it's stable, we don't see it growing per se.

So I think we are in this window here on the heavy sours where we, the timing may not just -- may not be right, and that is one reason we went ahead and wrote off, this coking project that we were working on at Port Arthur here, which is in our numbers.

But the hydro crackers we really just suspended.

They are still there, and we really are just waiting until we see the world's economy get going.

We'll see how reliance as the supply diesel moves to Europe and gasoline moves all over the world, we'll see how those all rebalance.

But I think long term, long-term our business just adds tremendous value, and everybody is trying to figure out how to make it not economic.

Okay.

Bill, thanks very much.

I appreciate your thoughts.

You're welcome.

Your next question comes from the line of Blake Fernandez with Howard Weil.

Good morning.

My question is I guess more of a strategic one.

There's been a lot of commentary on your thoughts as far as evaluating the portfolio for potential reductions or even permanent closures, and this may seem a bit counterintuitive but given your balance sheet and the geographic breadth of your capacity I'm wondering if there's not opportunities to actually increase utilization in certain areas and potentially drive some of the less efficient capacity offline?

I'm sure there's that potential but that is not the course we are taking.

Okay.

The other question I guess kind of dovetails in with Mark's question surrounding Europe, I'm wondering, a lot of the global capacity coming online is clearly in the emerging economies.

My sense is that it's difficult for Valero to kind of compete in that environment, but I want to see if you can provide any color.

Is that purely going to be dominated by the host countries and the integrateds?

I'd say yes to a point.

It depends on their growth rate and there's always the opportunity for us to export.

We haven't done it this year, but last year we were actually exporting diesel fuel to Australia.

So there is the ability as all the space is balanced to put products into the trade, but clearly China wants to be self-sufficient.

India is obviously an exporter.

Korea is an exporter.

So Japan is extremely long refining.

So your point I would have to agree with except that there's always trading opportunities.

Okay.

Then the final one I had for you, I hate to beat a horse here on the differentials, but as some of the new global capacity comes online presumably it will be a lot more efficient and more complex and it seems like that will kind of create more demand for the heavier sour barrels right at the time when maybe the OPEC production quotas are being increased and I'm just curious if there's any thoughts on that potentially creating yet another headwind for the differentials down the road?

Well, I think there is a headwind reliance and refinery is a sophisticated refinery and runs lots of heavy and sour crude oil.

Just to take that as an example.

That's not true of all the plants but that would be true of that plant.

So what our strategy is, if Canadian crude oil needs to get to the Gulf Coast or in fact the heavy sour crudes, these discounts will be smaller than what we would like to see.

So your point is well taken.

Some of this stuff is as you say.

Okay.

Great.

Thanks a lot.

I appreciate your time.

Your next question comes from the line of Jason Gammel with Macquarie

One more on the light/heavy differential environment.

Would you be able to actually just run the Gulf Coast as if it were a simpler system and take water feedstock slate through the system and shutting coking capacity rather than shutting in distillation capacity or are there logistical constraints that prevent you from doing that?

And finally, does it make economic sense to run cokers even in the current environment?

All the comments you made are somewhat yes, somewhat no.

Let's go to the one where would we lighten up our crude slate.

The answer is, yes.

We have lightened up our crude slate where we can, but the issue you have is in the heavy sour plant.

If you lighten up on the front end, you either need to have some preflash or you have to do something because we immediately flood or bottleneck the crude tower, the upper part of the crude tower.

Because it's not built to handle all those vapors coming up the tower.

So your ability to lighten up with the existing hardware we have is not -- you just don't have a wider range as you would like.

Now if you can go ahead and preflash the crude so you take those vapors off before you get in to the crude tower, you get more capability, but then you are going to overload your gas plant in the refinery.

What I am really telling you is your range or your ability to go very far is limited.

Now, on the tail end to the coker question, you don't have to operate the coker, and we have several of our cokers cut back.

We have our St.

Charles coker that is coming up.

We had a fire over there, it's coming up.

We're only going to bring it up 50%, we're only going to bring up one of the modules.

And then what we would do is make more fuel oil, but we run the economics around the cokers.

So we have economics at Delaware City.

We have economics at Texas City, we have economics at certain cokers but we don't have very attractive economics.

In Aruba where it stands alone as really just an upgrader, coking upgrader.

We didn't have economics at all.

The other location where we shut the coker down is at Corpus Christi.

Our Reese plant is 100,000 barrels a day crude unit with an associated 20,000 barrel a day coker and we shut down the coker down there completely.

As Bill mentioned at St.

Carols it's a four drum coker.

We are going to bring it up on two drums.

Also at our Paulsboro refinery it's a four drum coker, it's in a two drum operation presently.

And at at Texas city we are running all four coke drums but we are operating the coker at a reduced capacity as we lighten the crudes today.

That's very helpful and I think you just answered my second question.

Should we expect to a resid as a percentage feedstock decline?

Resid as a percentage of feedstock?

Yes.

You were running residuals, you were running 248 during the second quarter of '09.

Right.

Yes, you would.

Okay.

Thanks guys.

Your next question comes from the line of Cory with Raymond James.

A lot of my questions have been panned through at this point.

Would you update me as to what your liquidity position is right now?

At the end of the quarter we had 4.6, I believe, of available capacity in addition to cash.

Right.

Okay.

And also just kind of a higher level question.

Would you guys mind commenting on what you are seeing in terms of international and diesel and distillate demand playing out for the remainder of the year?

Well, obviously prompt, the exports to Europe are much tighter than they have been, but we are still seeing significant demand at the levels we've experienced in the past right now.

I think if you are also asking domestically, diesel demand is down tremendously.

I don't think I've ever seen anything like this where we have demand down 15% in the transportation sector.

So if you just say this is a 4 million-barrel a day business, it's down 600,000 barrels a day, and this is why to all these questions that we need the economy to get back going again because Valero has been exporting, as Joe said, because we still see demand coming out of Europe, but the domestic market, diesel consumption is very, 3.2 million, 3.3 million barrels a day, and that's after a very cold winter.

So we need -- and trucking is on highway diesel is 60% of the diesel business, and we need, on highway diesel to get going.

This is tied directly to the economy.

Gasoline tends to be the consumer product, disposable income or employment, but diesel is starting to really be and that's where -- so we see very weak demand, and the only thing that is going to take these inventories off the market is the economic recovery, a cold winter or the refiners are going to have to cut back hare on diesel production ultimately as things are getting full.

Gasoline demand and then in Europe stuff is pretty full.

On gasoline, it sits down to 1 to 2%.

They always revise these numbers but we'll say it's down somewhere in this 1.5 to 2% range.

It was down that much last year.

That's somewhere in the range of 150,000 barrels a day each year to 200,000 barrels a day, and to us you saw housing start to weaken.

We saw then consumers disposable income.

We have unemployment rising, and this ties a little bit to our outlook here even though we have very good gasoline margins or cracks today, we still see unemployment continuing to increase here for the next several months for sure, and that's a consumer product.

So that's why, as we said earlier, we are running our refineries in this 80 to 85% range, and where the industry is.

But demand has been very weak.

No doubt about that.

I appreciate the additional color.

Thanks.

There are no further questions at this time.

Thanks.

And just want to thank our investors for listening to the call.

If you have any further questions, feel free to call me, Ashley Smith, at Valero.

Thank you very much.

Thank you.

This does conclude today's conference call.

You may now disconnect.