瓦萊羅能源 (VLO) 2007 Q2 法說會逐字稿

Good morning.

My name is Julie Ann, and I will be your conference operator today.

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

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

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

(OPERATOR INSTRUCTIONS) Thank you.

Mr.

Ashley Smith, you may begin your conference.

Thank you Julie Ann.

Good morning and welcome to Valero Energy Corporation's second quarter 2007 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 you would like a copy, you can find one on our Website at Valero .com.

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

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

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

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

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

Now I will turn the call over to Mike.

Thanks, Ashley, and thank you for joining us today.

As noted in the release our second-quarter earnings came in at $3.89 per share, which is the highest we have ever achieved in any quarter.

These earnings are a 31% improvement over the $2.98 per share we earned in the second quarter of 2006, which was our previous record.

You should note that these results include the operations of the recently divested Lima, Ohio refinery, which are classified as discontinued operations in the financial tables that accompany the earnings release.

Given the strong margin environment in the second quarter, Valero's throughput margin for continuing operations was $18.14 per barrel, or 16% higher than the $15.59 per barrel earned in the second quarter of 2006.

Regarding operations mid-continent throughput levels increased over the first quarter, due to the return of our McKee refinery to limited operations in mid-April at around 80,000 barrels a day.

As more units were brought on-line, rates increased to approximately 150,000 barrels per day by the end of the quarter.

We plan to run at this level until the propane de-asphalting unit is repaired, which we expect to occur late in the fourth quarter.

Going through some of the key numbers for the second quarter, cash operating costs at the refineries were $3.87 per barrel.

The $0.09 per barrel increase over the first quarter, was primarily due to higher energy and reliability expenses, which were partially offset by an increase in throughput volume.

General and administrative expenses excluding corporate depreciation were $177 million.

The $32 million increase from the first quarter was mainly due to an increase in charitable contributions, and charges related to the cancellation of a services agreement with New Star Energy.

Total depreciation and amortization expense was $337 million, and interest expense net of capitalized interest was $83 million.

The $25 million increase in net interest expense from the first quarter was primarily due to the financing associated with the accelerated share repurchase program, or the ASR.

Our effective tax rate on continuing operations was 33.8% in the second quarter, which was in line with our guidance on the last earnings call.

Capital spending during the second quarter was $592 million, which includes $101 million of turnaround expenditures.

As to our stock repurchase program, as you recall in April we entered into an ASR with an affiliate of JPMorgan.

That allowed us to immediately purchase 42.1 million shares of common stock for an up-front payment of $3 billion.

As mentioned on the last earnings call the final price for the shares purchased would be determined based on a discount to the volume weighted-average trading price, during the period it took JPMorgan to fulfill their requirements under the ASR.

JPMorgan recently completed their requirements which resulted in Valero settling the contract with a cash payment to JPMorgan of $94.5 million.

So at the end of the day the 42.1 million shares we purchased in April cost us $3.1 billion instead of the $3 billion.

Included in the ASR we have utilized nearly $4 billion of the $6 billion authorization so far this year.

Over the remainder of this year, we intend to purchase an additional $2 billion of our shares in the open market.

With respect to our debt position, at the end of June our total debt stood at $6.9 billion, which compares to $4.9 billion at the end of March.

We paid down $230 million of maturing debt in April, and we borrowed $3 billion on a bridge loan to fund the ASR program.

Later in the second quarter, we repaid the bridge loan with $750 million of cash on hand, and the $2.25 billion of notes.

We ended the quarter with a cash balance of just over $2.3 billion.

Subsequent to the quarter end, we closed the sale of the Lima refinery.

Proceeds after taxes and other related expenses are expected to be approximately $1.8 billion.

As to our third-quarter operations, turnaround activity is relatively light, so for modeling purposes you should expect to see Gulf Coast refinery throughputs of approximately 1.55 million to 1.6 million barrels per day.

Mid-continent throughput should be around 450,000 barrels per day, which is lower than the usual guidance for this region due to the Lima sale.

West Coast throughput should average between 280,000 and 290,000 barrels per day, and our Northeast system should average in the range of 550,000 to 570,000 barrels per day.

Refinery cash operating expenses are expected to be slightly lower than the second quarter levels at about $3.65 per barrel, mainly due to higher expected throughput volumes and lower expected energy costs.

With respect to some of the other items in the third quarter, we anticipate G&A expense to be around $160 million, which is $17 million lower than the second quarter due, to the nonrecording charges in the second quarter that I mentioned earlier.

Net interest expense should be around $93 million, which is expected to increase from the second quarter, due to a full quarter effect of the ASR financing.

Total depreciation and amortization expense should be around $345 million, and then finally for the third quarter, you should be using a 33% tax rate for your remodeling purposes.

Now I will turn the call over to Bill.

Thank you, Mike, and good morning.

As Mike said, we had a terrific first half of the year, as strong demand continues to supply issues throughout the refining industry, tighten gasoline and diesel balances, and kept refining margins high.

We have seen DOE data report record gasoline demand this driving season, despite retail prices being around $3.00 per gallon.

As a percentage of disposable income, gasoline purchases are still low, about 50% of the late '70s and early 1980s level.

As to Valero's strategy, you can see that we are doing exactly what we had said we would do.

With respect to our refining system, we said we would consider optimizing our refining portfolio.

The Lima refinery was sold because it was not core to our overall strategy.

Going forward, we will continue to look at our portfolio of assets.

Even though we have certainly had our share of operating issues and unplanned downtime, we have been investing in our plants to make them safer, more reliable, and more efficient.

This year our Capital Expenditures budget remains $3.5 billion.

Over the next few years, we have several sizeable projects planned for our large Gulf Coast refineries, which will make those refineries more competitive and more profitable on a long-term basis.

Also, as Mike said, we intend to purchase an additional $2 billion of our shares this year to complete the Board-approved program.

We are in a great refining environment of strong product demand, favorable discounts for low quality feedstocks, and tight refining capacity worldwide.

We see many of the underlying supply and demand factors in place for many more years, which makes us bullish about our future.

Throughout our industry, projects are costing much more, are taking much longer to complete than originally envisioned.

Some are being cancelled, many are being delayed.

Of course, our business will continue to be seasonal with plenty of volatility, as we have seen lately.

However, please note even with the recent margin fall on any long-term historical basis we still have excellent cracks.

For Valero, our stock remains the best value in the refining sector, when you look at the valuations for other complex refining assets.

This management team is committed to improving our performance, and increasing our shareholder value for the long run.

With that, we will go ahead and open it to Q&A.

Thank you.

(OPERATOR INSTRUCTIONS) Your first question is from the line of Mark Flannery with Credit Suisse.

Hi.

I have a question about the large amount of ethanol capacity coming on stream in the second half of 2007.

Are you making any specific plans to try and accommodate that?

Are you building out any infrastructure to convert over markets to allow you more discretionary blending?

What do you think will be the impact of the new ethanol between now and the end of the year?

Mark, this is Joe.

Our forecast is that by year end, capacity will be about 560,000 barrels per day.

And really to answer the question, I mean from an infrastructure perspective, we are really not doing anything to accommodate it.

We are blending 20,000 to 22,000 barrels per day right now on average of ethanol.

And frankly the infrastructure isn't in place in many of the markets we are marketing it into to accommodate it today.

It just, we will do it economically where it make sense and where we can do it, but otherwise we are not pushing it.

Right.

I will add to that, Mark.

If you actually look at some of the numbers, even though ethanol prices have fallen significantly, if you take the vapor pressure hit we are getting here at least in the summertime, relative to some of the other blending components and their values, some of the discretionary blending is still not economic as people think it is, because they see the price of ethanol.

But when you look at our full cocktail, it is not necessarily so.

So just adding to Joe's comments for you.

That applies more in the summer then?

I am sorry.

That applies more to the summer than the winter?

That is absolutely right.

Just remember then the trade-off in the winter is in fact the vapor pressure versus butane, and I am sure you have looked and seen the butane prices.

All I am saying is, these trade-offs, you have to look at the whole cocktail.

When you look at the price, it looks like it should work but it's much -- it is a much tighter blend than you think.

That is very helpful.

Thank you.

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

Hi, I have a few questions.

Really the first one is given the deal of the day, so to speak, what is your overall strategy for potentially refining Canadian crude?

It looks like with the Lima divestment, it is very much focused around the Gulf Coast, and sort of by passing the whole of the Mid-Continent.

Maybe you could go into that in a bit of detail, and I have got a few follow-ups as well.

Thank you.

Well, Lima refinery where it was located for us, didn't really have that great a fit for the Canadian crude.

The pipeline had to be built over there.

You really needed an integrated strategy, and that's why Husky -- it is just a much better fit for them, from the womb to the tomb.

For Valero though, we are very interested in running Canadian crude.

Some Canadian crude does come to the Beaumont area today through the Exxon pipeline, and we have actually run some at the Port Arthur refinery.

Our strategy though is to see Canadian crude get to the U.S.

Gulf Coast; and we are talking with all these proposed pipeline projects that are trying to make that happen, and we will encourage those projects, by our participation through throughput commitments and others.

So that is our strategy is to do that.

We want to see the Canadian crude in the Gulf Coast.

Is there any particular reason why you have taken that approach?

It is very much aligned with what you have seen Exxon Mobil do, and to be honest what I think Shell are proposing as well.

Is there any reason why you felt that that is the best move for you?

I presume it reflects where your asset base is, but also is it because of the greater flexibility with seaborne access?

Neil, it would absolutely be greater flexibility.

Also when we look at building things, and as you have said, you properly said, our hardware where we have Corpus Cristi, Texas City, Port Arthur, St.

Charles, all having coking capacity for us to do work around those refineries, is at a much lower cost.

And quite frankly on the U.S.

Gulf Coast, it is much more efficient.

Maybe just a follow-up question.

After your initial disposal, are we to presume that portfolio rationalization could continue?

But looking have you sort of, take for example a sort of strategy of disposing below 100,000 barrels per day refineries, and potentially the ones that don't look as strategic, maybe Ardmore might be the next one that you might think about disposal?

Or are we done for the time being?

We are continuing to evaluate the portfolio as I have said.

You cannot put the criteria that you tried to put on it.

We are looking at all of these assets.

And quite frankly with the margins we have had, boiling oil anywhere makes money.

And so we are just trying to be certain that we are hanging on to the assets that long term will be the strategic fit for us.

But we have not said anything below 100,000 doesn't fit.

Just one quick last one from me.

You made a great comment there in terms of the way you look at your own valuations within the marketplace.

I don't know if you guys have had a look at some of the European refiners and their valuations, which do seem above yours and some of your competitors in the U.S.

Any sort of ideas for why that might be the case, or are you as confused as some of us are with that?

Gene is going to answer that because he has looked at it.

He runs our development function.

We've looked a lot at the European assets.

You are exactly right, they trade at much higher multiples to earnings or EBITDA or any other measure than our portfolio or most U.S.

assets do.

That is the reason we have always said we would be interested in acquiring in Europe, but we just quite frankly couldn't make the valuations work.

So we kind of have that strategy on hold until the relative valuations change.

Great.

Thanks a lot.

Your next question is from the line of Doug Terreson with Morgan Stanley.

Good morning, guys.

The industry operating and capital cost indexes and refining have continued to move higher this year, as you suggested in your comments.

On this point I wanted to see whether your expectations for full year CapEx have changed, and if so how?

And, second, I wanted to see how the Company performed in relation to plan on the billion dollar income improvement plan during the first half of the year, if you have any information in that area, too?

Doug, I will make some comments about that.

On the capital program for this year, our budget is $3.5 billion, and we expect to be within that budget.

We feel fairly confident about that.

And as to the second part of the question--

Let me go ahead and start, and then Rich will add in.

On the billion dollars what we have done is we are getting our tracking system in place, so that we can be right on top of that.

A lot of those projects require capital, and so it is skewed to the latter part of the five-year program, as I said.

So in the first couple of years you will see some efficiency things, some little benefits that we get from just general improvement in our reliability.

Once we get these new coke drums in, you are going to see reliability improve significantly at St.

Charles and at Port Arthur.

And then in the latter part you will see some stuff that comes in from fire recovery on a couple of our cats, and those type of projects.

But we are getting the tracking system in place, so that we can do it.

But one thing I would tell you that we have done is we are looking at how we do business in all of our refineries.

And between our Controller, Clay Killinger, and Rich, they have gone ahead and changed our business model on our yield accounting and procurement effort and we are going to bring that in.

It is little when you look at the scheme of things.

We will save $10 million a year by bringing this into corporate.

But what we are going to also get is a much greater focus on procurement.

As you can imagine, our spend is tremendous.

We will get that.

And the other thing is we are trying to get these refinery and the refinery operations to focus on the operation of the refinery, not worry about some of these ancillary things around our business.

So all of that is happening.

You want to add anything, Rich?

No, I just want to emphasize the point on the billion dollar program, that it is not a ratable 20% per year over the next five years.

It is probably going to be more back-end loaded, because there is a capital component on some of it, as Bill mentioned.

Sure.

Just quickly on St.

Charles and Corpus Cristi, the expansions there.

Are those projects tracking the investment level that you expected in timing as well in '07?

Yes, and Doug, those are, the expansions are envisioned for St.

Charles and Port Arthur.

Just to recap very quickly, we are evaluating large gas/oil hydrocracker investments for both plants.

We are actually using a unified design, where we would build the exact same units at Port Arthur and St.

Charles.

The projects will be in excess of $1 billion each.

At this point, we only have advanced approval from our Board to put certain long lead equipment on order, and we will be reviewing this project with our Board prior to the end of the year for consideration of full funding.

The timing on these projects, these would be commissioned in the early 2010 timeframe.

Okay.

Thanks a lot.

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

Jeff Dietert with Simmons.

You mentioned that your maintenance activity was going to be lighter in the back half of the year relative to the first half of the year.

And I was going to see if you could provide a little bit more detail there and ask if you have any visibility into labor parts and equipment, how if you are continuing to see cost inflation there?

Sure.

Jeff, I will make a few comments on that.

First of all on the second quarter, turnaround activity was pretty light, really what we worked on we had a small crude unit turnaround at Paulsboro, hydrocracker in Benicia, and the resid finer in Corpus Cristi.

There really isn't any major maintenance in the third quarter to speak of.

We will close out the year with some modest activity in the fourth quarter.

We have 100,000 barrels per day crude unit at Paulsboro that will be down in October.

Benicia's fluid coker, which is a 30,000 barrel per day unit will be down in October.

And we will have two cat unit outages, one at Texas City and then one at Wilmington, down for turnaround, in October and November respectively.

As far as labor resources for turnarounds, what I would say is I think the cost inflation has plateaued.

There aren't any indications of it abating, however.

So I think we have just established both a higher plateau of cost.

Likewise, we do not see any real changes in productivity.

Productivity is lower by historical standards, and we don't see that situation changing.

Our discussions with the major contractors still emphasize the need that we need to commit early, to lock up contractor availability in advance, and it just represents a continuing tight market for those type of maintenance and construction services.

Two other things.

It appears OSHA has tightened up its efforts in monitoring operations and procedures, and that you are also dealing with forced reductions in emissions.

Can you address those two topics?

Yes, I can make comments on the OSHA piece.

OSHA is out with a National Emphasis Program on refining for a more rigorous examination of process safety management compliance.

We have been tracking these developments with OSHA, and I am glad to say that in line with that, we had our first OSHA Star Program recertification just completed in our Houston refinery in July, and our refinery was recommended for recertification against OSHA's National Emphasis Program template.

So we are prepared for what OSHA is looking for, and in our first opportunity to be evaluated we were successful.

Thanks, Rich.

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

Thank you.

Rich, when you talk about the fourth quarter turnaround, can you give us the number of days on those units that is going to be on the turnaround?

Sure, in general and these are rounded for simplicity.

The Paulsboro crude unit, it is a 100,000 barrel a day unit, is going to be a nominal 30-day turnaround.

The Benicia fluid coker is also going to be a 30-day turnaround.

Texas City's cat unit and Alky, it is about 80,000 barrels a day of cat capacity.

That will be about a 40-day turnaround.

In Wilmington's case, this is a 55,000 barrel a day cat cracker, it is going to be a 45-day turnaround.

In this particular case, the duration is longer because we are going to go through a large retrofit on the associated Appalachian unit.

Thanks a lot.

Rich, talking about first quarter 2008, any kind of insight as to how that may look?

I don't have the specifics on that at this point, but I don't anticipate it is going to be any step-out quarter from a maintenance point of view at this point.

So it will be normal to maybe light?

Let me say, I would say that is a good characterization.

Looking forward we will have a significant increase in turnaround activity in 2009 and 2010, with a couple of large refinery turnarounds.

Maybe this is either for Rich or for Mike.

Any kind of rough estimate what is the loss in opportunity [cost] in the second quarter, related to the planned downtime and also the unplanned downtime?

Okay.

Let me give you some general figures.

If we look at all of our unbudgeted downtime in the second quarter, including things such as project schedules slipping on new capital projects, with the wide margins we have experienced, the impact is about 590 million in the second quarter.

For the first half that number is about 850 million.

And, Rich, those are after tax, right?

No, those are pretax.

Pretax.

And the other thing he said there is it includes where we have had projects slip.

So our big hydrocracker, model hydrocracker is on the Gulf Coast.

Where they have slipped are included in this number.

They [multiple speakers] our earnings power that we have.

Any asset sales gain or loss related to the Lima in the reported?

Nothing in the second quarter.

So that's zero.

No.

All we have done is shown on the earning tables there, we have separated between continuing and discontinued operations.

The 187, in other words, that is the actual earnings in the quarter by Lima.

That is correct, net of taxes, that is correct.

Okay.

A final one, just a quick one, can you share with us what is the throughput number for Lima in the second quarter, in realized margins?

I can.

I think throughput was roughly 158,000 barrels a day.

And their operating income was $300 million in the second quarter.

Perfect.

Thank you.

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

Thank you.

Two questions.

First, do you have a fully diluted share count at the end of the quarter, or whatever recent period you might have?

Yes, we do.

Fully diluted, for the second quarter on a fully diluted basis weighted-average for the quarter is 578, and then at the quarter end it is roughly 566.

Thank you very much.

You allude to in your press release widening light, heavy, and sweet, sour spreads.

Obviously they were narrower in the second quarter.

I think Mexican production is well documented to be in decline.

Is the outlook for light, heavy, and sweet, sour, or really light heavy spreads in particular, should we assume that is dependant on OPEC actually raising their production here over the remainder of this year?

And it is noteworthy that WTI has shot up here to $78 a barrel, and while the spreads are a little wider, maybe not as wide as they were in past periods when WTI was this high.

Okay, Arjun.

I think we have had a very strange situation in the second quarter with TI.

Right?

Everybody looks at Maya discounts relative to TI, and heavy sour discounts relative to TI, and we know that TI was just dislocated from all of the other sweet crudes.

Because if you look at [spread] and LLS, you had a significant divergence from TI.

When we looked at the heavy sour discounts, and we say, "Okay, we averaged 960 Maya discount during the second quarter," what we really would do is look at that number, and adjust it to the other sweets.

And so if you had discounts that were probably much more normal than we would guess, $14, $15 heavy sour discounts and Maya itself has been a little bit more expensive relative to some of the other heavy sours, also.

When we are delivering Maya in at $11 off, we can get other heavy sours at $14 plus off.

So the light heavy spread even though it looked off, I think that it was really more related to [G]I than anything.

That is helpful color in Q2.

As you look forward for the rest of this year, do you think the widening is dependent on OPEC raising productions?

Yes, that is a good question.

I think as they do raise production, a lot of it is going to be Saudi Arabia, which is going to be some of the heavier crudes, which directionally puts more pressure on the heavy crude discount.

Remember the Saudi crudes are basically medium sours.

Even though they call it Saudi heavy, it is a medium sour crude, and you have seen Mars start to move out a little bit.

Those are great points.

Thank you very much.

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

Thank you.

Good morning, guys.

A couple of industry questions, really.

You mentioned on the press release some of the issues that had arguably inflated margins during the quarter, unplanned downtime being one of them.

But production at least according to the EIA for gasoline is still up year-over-year.

Can you give us some color as to why you think that might be?

And I have a follow-up.

I think a lot of the proaction being up year-over-year is just imported [blunt] stock.

You get a lot of [Arbad] that is imported and really it is shows just that gasoline production when at the terminal, you blend it with ethanol, and that's the way the DOE reports it, when you blend it with the ethanol it shows up as gasoline production.

I think you just look at U.S.

refineries alone, it's fairly flat.

But with 5% lower utilization?

I can tell you everybody is running conversion units.

Where you have had some issues on crude, you have been running your cats, your reformers, because you have had such an attractive gasoline margin.

So when you look at that utilization number where they are talking about crude, it can affect a conversation on distillate production, but when you look at the gasoline the conversion units are running.

Unless somebody had a problem, like in the Chicago area which lifted the entire margins in the upper Midwest.

I guess a related question is -- wasn't quite my follow-up -- but you mentioned imports there.

Imports are down quite markedly YTD.

Obviously they picked up last week, but do you see any dynamics particularly that could see imports going in one particular direction over the next couple of months, or are you pretty isolated from that?

I think there were heavy turnarounds in Asia and Europe earlier in the year, which reduce the buy obviously, and the other factor is Mexican demand is up on imports quite substantially versus last year, so the latest numbers are around 300,000 barrels per day, and also imports into Nigeria where all the refinery capacity is down, and imports in places like Iran and Singapore.

Other areas that have just become bigger ex importers of gasoline, than they had been in the past.

It just take barrels off of the market to pick up into the United States.

Which then causes the prices to have to get higher to attract the imports.

I guess where I am going with is I am trying to get an idea of your thoughts longer term.

If 2007 was a little more transitory because of these import issues, which arguably is why inventories are so low, is that something that you think is repeatable or sustainable, or do you think it goes back to normal?

One of the things I mentioned are because of the world economic growth, gasoline demand increasing faster than supply, which leaves fewer barrels left to come to the United States.

Okay.

My follow-up is related to the summer/winter issue.

I mean clearly there is a little bit of a blend premium associated with summer blend nowadays.

But when do you guys start transitioning back to winter grade?

When would you fully expect to be fully producing winter grade gasoline again across your system?

In or around mid-September.

And it varies.

Southern, northern California is --

I think it's September, October.

L.A.

is probably first.

Southern California is a month later, and then in our other markets, it starts in mid-September, as Gene said, and then we go through a couple of steps.

So I think by the end of October, we are making winter gasoline in the mid-Continent.

If you need to know that exactly, Ashley can give you exact dates on that.

I will follow up then.

Thanks very much.

Your next question is from the line of Mark Gilman with Benchmark.

Guys, good morning.

Can you, I guess I am following up on a point that either Bill or Rich made.

Neither of the mild hydrocrackers at St.

Charles or Houston came on in the second quarter?

No, Mark.

Where we are on those, the Houston unit came up towards the back part of May.

So it is in service and running well.

The St.

Charles unit is actually in start-up as we speak, and it should be fully commissioned by next week.

Okay.

Thanks.

Can you give me a rough or a precise idea how much physical WTI/WTS you actually ran in the second quarter, in both the Mid-Continent and Gulf Coast regions?

We wouldn't have run any in the Gulf Coast, Mark, WTI or WTS, and we will try to see if we can get you a number here.

The regional data, I don't have the regional data.

We don't have it broken out, Mark.

We don't have it broken out by crude at this level.

Ashley can follow up and dig that number out of the system for you.

But it is zero in the Gulf Coast TI/TS?

We can't really get it there today.

People are looking at a lot of things to try to move it, but today you can't get it down.

I am assuming that there is a pretty large working capital liquidation number in the quarter from a cash flow standpoint, Mike.

Is that accurate?

No, well, when you look at the items that have been disclosed in our earnings materials they pretty much come to the change in cash flow.

I mean, change in cash of $640 million.

So we don't have a huge working capital requirement in second quarter.

Okay.

And just one final one.

Any derivative effects of any kind impacting the second quarter results?

You are talking there about our hedging?

Well, Bill, broadly derivative inclusive of hedging and anything else.

Well, we feel, when we buy crude oil and stuff we still put paper against it because that is how the business is run.

But I think you are talking about--

Yes, outside of that.

Outside of that, and it is just a minor little number, and it's insignificant.

Okay.

Guys.

Thanks a lot.

(OPERATOR INSTRUCTIONS) Paul Sankey with Deutsche Bank.

Hi, I think we have just about hit all my questions actually, but one that is outstanding is the way that curves have shifted.

Is there any meaningful impact for you, from the moves that we've seen to backwardation in crude markets?

As a follow-up to that are there any observations that you could make the fact that crude inventories are ostensibly quite high in the U.S.

but we've seen obviously very high prices.

At the same time gasoline inventory is not super loose by any means, but a cratering of the price there, so any observations you can make on those would be great.

Thanks.

Well, I will speak to gasoline.

Gasoline inventories are very low.

I mean they are very low on a historical basis.

So the decline that we have seen in the margins there isn't necessarily fundamentally driven.

We are entering the season where we will start blending butanes back in, and so we know that will have an effect on the inventories.

But nonetheless, we go into that period with inventories at very attractive levels, relative to previous years.

On the crude, the change in the market structure just means that we are not paid to carry it, right?

So what we will do is what we always do -- and just aggressively manage the inventory to the market structure as we have done on the product side.

I would expect to see inventories continuing to fall, but maybe the price nevertheless staying high?

Yes, I think there is no incentive to hold the inventory, so your observation is correct.

I would say because Mark Gilman usually asks the question, on contango versus backwardation, at least for the Mid-Continent refineries it does increase our, in effect, our effective crude costs, into those two plants.

There has been talk of destocking of gasoline as well.

Would you say, I mean, I guess the curve [hasn't] changed everything like the crude curve has, but would you say that's been part of the impact that we are seeing on gasoline prices?

I don't know if just the destocking is an issue, but we certainly have said to our plants we are not holding gasoline at the refineries, right?

It is the end of July and into August here.

So we tend to keep the product moving to the market, and I would assume other companies look at it the same way.

Great.

That's great.

Thanks.

Just a final one for me.

Utilization was very poor in the first half.

It was kind of lumpy between companies.

But would you argue perhaps that there has been a secular shift towards a lower availability capacity in the U.S.

or you think it was just a uniquely rough first half?

I will try to answer you, and I will ask Rich for some help here.

But clearly we are looking at crude.

You look at the whole system, you have to treat your products.

Between the distillates which, basically we are taking all the sulphur out of distillates, if you take a 7 PPM or 8 PPM at the refineries; if you think crude or gasoline we are doing the same.

So any time you have a hydrotreated problem in your refinery, you can't make spec products.

So it does cause you -- if your inventories are full or you have component inventories -- you have to cut back.

There is no other option.

But it is a more complex refining environment now with all this severe hydrotreating.

You want to add anything, Rich?

I would.

I think there is an impact in the market associated with the productivity and the maintenance workforce.

The quality of the work, if revamps are being done to existing units, we find that even the quality of engineering is not what it was; and I think turnaround durations directionally are becoming longer, and I think that is a factor as well.

As a rule of thumb what would you say is the impact on the percentage utilization?

It is kind of hard to quote an exact number.

But associated with those factors, we know that they are qualitative factors.

Paul, I don't think we would be able to give you any better number than your own, but the things that we mentioned to you are the real world that we work in.

Thanks, guys.

Nicki Decker with Bear Stearns.

Good morning.

Most of my questions have been answered as well.

Just one on the ARB situation as you see it.

Maybe you could give us an update as to what you see as attractive, to where you see as attractive to send product?

Well, I mean, the ARBs into the U.S.

have been largely closed here recently.

Out primarily our exports are related to distillates, and those typically go south.

Okay.

Have you seen any change in the numbers after the Exxon refinery outage in Europe?

I haven't seen any changes in the numbers.

In talking to the guys on the trading floor, though, they are seeing less barrels being loaded to come this direction.

Okay?

So they try to keep a close eye and stay in tune with the market, and look for what might be moving, and there hasn't been length in Europe really to speak of this summer, and it is certainly not changing now.

If I could just ask one other on the results.

Just looking at the operating costs on the West coast, that was really a stand out in terms of the higher than expectations, and it doesn't look like it's particularly related to volumes.

Maybe you could talk about what's driving up those costs?

I am sorry, I was going to say there's two factors associated with that.

There is an energy consumption factor, which just related to lower internal planned fueling, and more natural gas purchase.

This is primarily associated with Benicia.

And then there was also a litigation reserve that was established for a labor issue out on the West Coast that impacted the results.

It sounds like part of that we should carry out into future quarters?

Well, it's -- the litigation of course is a one-time issue, and as far as the energy costs go, we make internal market calls based upon the value of propane and butanes, whether they are better served as internal plant fuel, or whether we should sell them as products.

And we just track the market, and do the most economic thing.

Okay.

Thank you.

Your next question is from the line of Ann Kohler with Caris.

Good morning, gentlemen.

Kind of a question on sort of your growth and acquisition strategy.

You kind of highlighted before that currently the valuations in Europe are a bit high.

It is my understanding, and correct me if I am wrong, but that you expressed interest in a South American refinery, and if you could just clarify if that is true and if so what your thought process is behind that?

I guess it would be some new refinery in Central America?

We are participating with Pemex, PMI looking at this refinery in Panama that is being proposed.

So we are taking a look at it, and that is the extent of our thought is, it is an opportunity, we are looking, we will see what we think as we get into it.

Is there any sort of timing I guess on sort of the process for the facility?

They have a schedule but it is a meeting in September, and then it drags out.

But there is going -- if you are worried, we are not about to jump into a grassroots refinery that doesn't have more assurance as to margin going forward.

But it's an opportunity in Latin America.

We already told you, we know that Mexico is importing 300,000 barrels a day of gasoline now.

We looked at Central America, South America, so there is opportunities here.

So this is an opportunity to participate in the growth in that particular market versus using the opportunity to basically import product into the U.S.?

Right.

We wouldn't view that as a place to import products from into the U.S.

That is correct.

Okay.

Thank you very much.

Next a follow-up from the line of Mark Gilman from Benchmark.

Bill, it looks to me as if some of the ULSD premiums are beginning to tighten up and shrink a little bit.

Perhaps in response to the industry having overdone it a little bit in terms of supply capability.

Do you think there is any chance as we go toward the winter that we may see ULSD being downgraded from a value standpoint, and maybe sold into the heating oil pool?

My answer to that would be yes.

But it has to do with logistics, and where product is available.

But people will tend to sell it into, if you look at our whole system, and by the end of this year -- just to give you an example -- we will be able to make ULSD in every single refinery or carve diesel in every refinery except the Northeast.

And I think the industry is doing that.

You want to add something, Gene?

I think you are right.

The East Coast is really the only place we are really able to make high sulfur diesel in any great degree.

So we are agreeing with your observations.

Thanks, Bill.

There are no further questions at this time.

Mr.

Smith, are there any closing remarks?

No, that is it.

We will just conclude the call.

Thank you very much for listening to our call.

Thank you for participating in today's conference call.

You may now disconnect.