瓦萊羅能源 (VLO) 2011 Q1 法說會逐字稿

Welcome to the Valero Energy Corporation first-quarter 2011 earnings release conference call.

My name is John, and I will be your operator for today's call.

At this time, all participants are in a listen-only mode.

Later we will conduct a question-and-answer session.

Please note that this conference is being recorded.

I will now turn the call over to Mr.

Ashley Smith, Vice President, Investor Relations.

Mr.

Smith, you may begin.

Okay, thank you, John, and good morning and welcome to Valero Energy Corporation's first-quarter 2011 earnings conference call.

With me today are Bill Klesse, our Chairman and CEO; Mike Ciskowski, our CFO; Gene Edwards, our Chief Development Officer; Joe Gorder, our Chief Commercial Officer; Kim Bowers, our Executive Vice President and General Counsel; and Jean Bernier, our Executive Vice President for Corporate Communications, Information Services and Supply Chain Management.

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

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

If you have any questions after reviewing these tables, please 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's or management 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've 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, we reported first-quarter 2011 income from continuing operations of $104 million, or $0.18 per share.

This number includes an after-tax loss of $352 million or $0.61 per share on derivative contracts related to forward sales of refined products.

These contracts were closed and realized in the first quarter of 2011.

Excluding that item, our first-quarter earnings would have been $0.79 per share.

I should note that the loss from discontinued operations shown in the financial tables relates to the Delaware City refinery site and the Paulsboro refinery, which were sold in 2010.

As reported, first-quarter 2011 operating income was $244 million.

Excluding the $542 million pretax loss related to the forward sales, first-quarter 2011 operating income was $786 million versus operating income of $4 million in the first quarter of 2010.

Since the loss on the forward sales was reported in cost of sales, our throughput margins were reduced by $2.86 per barrel across our system.

Excluding this item, first-quarter throughput margins were $9.91 per barrel, which is an increase of $3.93 per barrel over the first-quarter 2010 margins, and the highest first-quarter margins since 2007.

The increase in throughput margins was due to higher diesel and jet fuel margins, plus wider discounts for heavy sour crudes on the Gulf Coast and light-sweet crude in the Mid-Continent.

I want to highlight that on page 5 of the earnings release tables, we are showing market prices in terms of Louisiana light-sweet crude oils or LLS.

We think LLS is a better indicator of prices for light-sweet crude oils that are waterborne and can move efficiently to key refining markets, especially on the US Gulf Coast.

This became important in the first quarter when WTI began to trade significantly below other light-sweet crude oils such as LLS and Brent due to significant growth in production and also inventories of crude oils at Cushing.

One of the key drivers of our year-over-year gain in throughput margins was in diesel margins.

For example, Gulf Coast ULSD margin per barrel versus LLS increased $6.76 or 99% from $6.83 in the first quarter of 2010 to $13.59 in the first quarter of 2011.

Looking at the Gold Coast gasoline versus LLS, margins per barrel fell from $6.46 in the first quarter of '10 to $3.82 in the first quarter of '11.

However, in the second quarter, gasoline margins have rebounded to an April average of around $8 per barrel or $4 higher than the first quarter.

The other key driver for our margin gain over last year was crude oil discounts.

The Maya heavy sour crude oil discounts versus LLS increased $6.11 from $9.57 in the first quarter of '10 to $15.68 per barrel in the first quarter of '11.

The Maya discount has continued to widen in the second quarter with the April average up $1.58 to $17.26 per barrel.

These discounts are important in our Gulf Coast region where we have significant capacity to process heavy sour crude oils.

Another benefit for Valero came from WTI pricing at a discount to LLS.

This discount increased over $10 per barrel from $0.67 in the first quarter 2010 to $11.08 in the first quarter of 2011.

The WTI discount helped our McKee and Ardmore refineries in the Mid-Continent region where the crude oil price is priced at or below WTI.

In the second quarter, the WTI discount to LLS has continued to widen from the first quarter with the April average up around $5 to nearly $16 per barrel.

We also benefited from crude oil discounts at our Three Rivers refinery, which is in our Gulf Coast region.

This refinery recently began to process light sweet crude oil from the Eagle Ford shale formation in South Texas.

In the first quarter, we processed an average 25,000 barrels per day of Eagle Ford crude at prices similar to WTI, which replaced expensive waterborne sweet crudes, saving around $11 per barrel in the first quarter.

We are rapidly working to use more of this discounted crude oil.

We're now processing 30,000 barrels per day and expect to be at nearly 40,000 barrels per day in June.

And by the end of this year, our Three Rivers refinery should have the ability to process almost 60,000 barrels per day of Eagle Ford crude.

Now continuing with other items, our first-quarter 2011 refinery throughput volume averaged 2.1 million barrels per day.

Refinery cash operating expenses in the first quarter were $3.93 per barrel.

Cash operating expenses were in line with guidance, but higher than the fourth quarter of 2010 due to the decline in throughput volume mainly caused by turnarounds.

Our retail segment reported a good quarter with $66 million of operating income.

US retail had $19 million of operating income in the first quarter, which was even with the fourth quarter of 2010, but down from the first quarter of 2010 on lower fuel margins.

Canada retail had $47 million of operating income in the first quarter, which was up $5 million from the fourth quarter of 2010 and up $9 million from the first quarter of '10, mainly on stronger retail fuel margins.

Our ethanol segment earned a $44 million of operating income in the first quarter.

This was down $26 million from the fourth quarter of '10 and down $13 million from the first quarter of 2010 on lower gross margins.

However, we did achieve our highest quarterly production rate at 3.3 million gallons per day in the first quarter, which was also in line with guidance.

In the first quarter, general and administrative expenses excluding corporate appreciation were $130 million.

Depreciation and amortization expense was $365 million, and net interest expense was $117 million.

The effective tax rate on continuing operations in the first quarter was 28%, which was lower than the fourth quarter and guidance due to favorable settlements of some tax audits.

Excluding those settlements, our effective tax rate on continuing operations for Q1 was 35%.

Regarding cash flows in the first quarter, capital spending was $737 million, which includes $299 million of turnaround in catalyst expenditures, and we paid $28 million in dividends.

Also in the first quarter, we repaid $210 million in maturing debt, and we purchased the $300 million of tax exempt bonds related to the St.

Charles refinery, which we issued in the fourth quarter of 2010.

By purchasing these bonds, we avoid unnecessary interest expense, and we preserve the right to reissue these low-cost bonds if needed.

With respect to our balance sheet at the end of March, total debt was $7.8 billion, cash was $4.1 billion, and our debt-to-cap ratio net of cash was 19.5%.

At the end of the first quarter, we also had approximately $4 billion of additional liquidity available.

We remain focused on our strategic priorities, including our 2011 target of $100 million in pretax cost savings, improving the performance of our assets and maintaining our investment-grade credit rating.

We will continue to look for earnings accretive acquisition opportunity, but we will only acquire quality assets at an attractive price like our pending Pembroke acquisition.

In conclusion, Valero is in great financial shape, and we have significant potential for earnings growth given the strong industry conditions; the recent completion of heavy turnarounds and profit-enhancing projects at our refineries; the Pembroke acquisition that we expect to close in the third quarter; and finally, our economic growth projects, including the hydrocrackers and the hydrogen plants that are on schedule for completion in 2012.

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

Okay, thanks, Mike.

For modeling our second-quarter operations, you should expect the refinery throughput volumes to fall within the following ranges -- Gulf Coast at 1.42 million to 1.47 million barrels per day; Mid-Continent at 385,000 to 395,000 barrels per day; the Northeast at 190,000 to 200,000 barrels per day; and the West Coast at 265,000 to 275,000 barrels per day.

Refinery cash operating expenses are expected to be around $3.70 per barrel in the second quarter.

Regarding our ethanol operations in the second quarter, we expect total throughput volumes of 3.3 million gallons per day and operating expenses should average approximately $0.36 per gallon, including $0.03 per gallon for non-cash costs such as depreciation and amortization.

With respect to some of the other items for the second quarter, we expect G&A expense excluding depreciation to be around $140 million.

Net interest expense should be around $110 million.

Total depreciation and amortization expense should be around $370 million, and our effective tax rate should be approximately 35%.

We will now open the call to questions, John.

(Operator Instructions).

Ed Westlake, Credit Suisse.

Yes, good morning, everyone.

And making all the adjustments, some solid results in Q1.

I guess just to understand Q1, my first question is, what's the total net income loss that you had from turnarounds in Q1?

You mentioned the $0.20 for March.

And can you confirm that all the refineries are now back up and running?

The total turnaround, just turnaround impact, was estimated around $470 million for the first quarter.

And all the refineries are now back up?

Yes, we have Port Arthur and Benicia are back up out of turnaround, and we still have turnaround -- we're still in progress at Ardmore and they're actually starting up as we speak, and then St.

Charles will be starting up in mid-May.

That is sort of the status.

After mid-May we will essentially be done with our heavy turnaround mode.

And Ed, hey, this is Ashley again.

That number, the $470 million, that's a pretax number.

I just want to clarify.

You had asked about net income, but that's a pretax number.

It's kind of like a margin number.

Okay.

And then I guess the second question is more strategic.

You've got good cash on the balance sheet.

You've got good margins going into Q2.

Obviously you just mentioned acquisitions and we know all the refineries that are up for sale.

But can you just give us your latest thoughts on the benefits of growth through acquisition as opposed to returning more cash back to shareholders, either by a buyback or perhaps increasing the dividend?

At this point -- this is Klesse.

At this point in time, we intend to hold the cash on our balance sheet.

We do think we're going to have a very good second quarter and rest of the year.

Right now, where consensus is around $3 a share, we think we will even beat consensus for the year.

But, well, we have good projects.

We need to finish our hydrocrackers on the hydrogen plant.

Our capital spending will be somewhere this year between $3 million and $3.2 million; we'll see as -- it's all about timing.

And then as we get into next year, as we finish those projects, our capital spending load could be just as high as we finish the hydrocrackers.

So, right today, we're going to keep our resources.

We think at the end of the day, we will add much more shareholder value by completing all of these projects.

And Ed, you also mentioned acquisitions.

Certainly today, the majors are putting some quality refining assets on the market.

And we will continue to look, but as Mike said in his notes to you, that we are only looking for quality stuff that can provide real shareholder value.

But today, there is opportunity.

As I've said before, this management team demonstrated in the past that when we didn't see those opportunities, we bought our shares.

Thanks very much, Bill.

Doug Terreson, ISI.

Good morning, everybody.

On the refinery turnaround maintenance delays, which I think was part of Ed's question, is there any geographic segmentation of note, Ashley?

Or would you call that kind of a system-wide situation in the first quarter?

Yes, the number in the first quarter -- most of it was in the Gulf Coast, because that's where most of our turnarounds were.

Okay.

Sure.

And Bill, I wanted to see if you could provide us an updated view on the likely outcome and timing of the ethanol debate in Washington, if you have an updated view.

And specifically, how the tax regime, the blending mandates and the import restrictions may change.

And if you think that there are meaningful changes ahead, I would be interested in your view of the most likely implications for the market at this time.

Well Doug, (inaudible) to let Gene answer that.

You know, the blenders credit is probably the one that gets the most attention, whether that's going to be maintained or reduced, and it's $0.45 a gallon today.

In today's market, the ethanol producers are not really capturing it, because ethanol is selling $0.50 a gallon under gasoline right now, even before the subsidy.

So the blenders are really getting it, so they are actually getting ethanol $0.50 under, catching $0.45 blenders credit; so they're actually capturing about $0.95 a gallon.

We do capture that at our retail locations, but it's a very small volume compared to the ethanol production we have.

So I guess the way I would look at it, even if we didn't have the subsidy today, it really wouldn't change the economics because you still have the mandate and you have to produce some ethanol.

Our plants are more competitive than most because they are a corn advantage and the economies of scale that we have and our operating costs and such.

So, to be honest it's really not much of a factor.

The Brazilian import duty, again, is kind of a non-factor.

Brazilian prices are higher than the East Coast.

Things of a similar message I had told you at the last meeting.

So, with high gasoline prices there, they're not in a position to be exporting.

Sure.

So, right now there's not a whole lot on policy that really would change our current economics.

Okay.

Thanks a lot, Gene.

However, I would just say, we're in this business and the excise tax credit is part of the business.

And, we look to continue to grow this business in the right opportunity (multiple speakers).

So, it will be phased out over time, we're quite comfortable.

Okay.

Thanks, Bill.

Doug Leggate, Bank of America Merrill Lynch.

Thank you.

Good morning, everybody.

I'm going to try a couple if I may.

The first one is on crude charge.

Obviously, there's a lot of moving parts out there in terms of where the best benefit is, but excuse me.

Would you please give us an update on, across the system, how you are changing your emphasis on heavy discounted crudes versus the WTI advantage or the domestic advantage, if you like?

And I appreciate the color on if you could Three Rivers, but if you could widen that discussion across the whole system that would be helpful.

Well, good morning, Doug.

This is Joe.

I will tell you, it honestly hasn't changed that much if you think about it.

I mean the Gulf Coast, we got very strong heavy-sour discounts and improving medium sour discounts, and so it's to our advantage to go ahead and run those crudes to the extent we can.

Obviously our runs of heavy sours were down in the first quarter, and that was largely attributable to the turnaround activity in most specifically Port Arthur.

But we haven't changed our view and our desire to go ahead and run heavy crudes where we can.

As we had mentioned before, we run as much WTI price crude as we can in the Mid-Continent and in South Texas.

And because we had the Ardmore turnaround, those volumes were down a little bit in the first quarter also to about 245,000 barrels a day, but our May refinery operating plant has those increasing to get up to that 300,000 a barrel range.

And then the other place that I had mentioned is the West Coast.

And on the West Coast, we've got of course the issue with AB 32, the low-carbon fuel standards and the associated high carbon intensity crude issues.

And what we've done there is adjusted the slate a little bit to avoid some of the absolute high carbon intensity crudes, and we are running crudes from different sources.

So, overall, I would say those are the changes in the slate, but nothing material.

Joe, could I -- I'll just ask you to elaborate a little bit.

We've all focused obviously on the WTI discount to LLS or Brent or whatever benchmark you choose to use, but could you maybe just walk us through the mechanics as to how we end up with a Maya discount?

Currently on our numbers anyway, it's about $18 below LLS.

How is that price set, and how sustainable do you think that is, even if WTI maybe narrows at some point?

Okay, well the price is a formula based pricing, as you know.

And 40% of it is high sulfur fuel oil, 3% fuel oil.

And it's right now being very well supplied out of Europe.

And in fact, high sulfur fuel oil in Europe is at a $23 discount to Brent.

So you've got a major component of the Maya formula that's weak.

You have WTS is a major component of the Maya formula.

It is also very weak because it is pricing off of WTI.

Then you got two sweet crude components which make up I think maybe 20% of that formula.

So, if you look at the way it's priced today, the components themselves are what are driving those discounts to the higher levels.

So it's not just PI, basically?

No, it's not.

But it also relates to the supply that's in the market, because the suppliers of Maya or other heavy crudes are obviously looking at the supply/demand balance.

So we are seeing more crude oil come out of Columbia.

The Mexican Maya production has stabilized for the moment.

We're seeing more heavy oil out of Venezuela, and we're seeing heavy, although it's sweet, crude coming out of Brazil.

So, the balance, as you look at it, is there's ample heavy crude on the US Gulf Coast, which then contributes because the formula has a K factor that can be adjusted by discretion.

So, it is a supply/demand situation on the Gulf Coast.

Got it.

Let me just try one final one.

I'm not too optimistic on this one, but I'll give it a go anyway.

So Pembroke, the Chevron refinery, there's obviously some other assets nearby that could be a pretty terrific bolt-on.

Any thoughts as to how you might want to proceed on -- because I think originally you had said more than one refinery in the UK would have interest to you.

And I'll leave it there.

Thanks.

Well, I'm very open about the fact that, yes, we want to increase our geographic diversification here.

We think we, with Chevron, have made a deal that works for both companies, and that that will be a real asset for us going forward.

There are other things that are coming into the market and we will take a look at them.

But at the end of the day, I've told you guys many times, Valero does not have deal [heat].

We are clearly looking for assets that will add long-term shareholder value.

So, you know what's for sale out there.

We have all these confidentiality agreements, but the facts are we will look at them, see if there are synergies and see if the value is there, ultimately giving us the return, but we will continue to look.

Thanks, Bill.

Blake Fernandez, Howard Weil.

Thanks for taking my question.

I had a question on Three Rivers.

It sounds like you're going to be moving up to processing Eagle Ford crude up to about 60,000 barrels a day.

If I'm not mistaken, I think the capacity on that facility is about 100,000.

Is 60,000 the limit, or can you continue moving forward beyond that down the road?

Blake, 60,000 is the limit without capital investment down there; without any kind of significant capital investment.

So, that's just a logical number for us to get to and we can get there fairly quickly.

Because it's light, because of the light end.

And Lane could speak better to what would be required to run more, but at 60 a day, we don't have any significant investment.

Okay.

And then secondly, Bill, you kind of indicated that accumulating cash on the balance sheet is kind of the preferred method here going forward.

And then as it relates to M&A, we've seen the equity prices kind of move higher.

The implied kind of per complexity barrel valuation for the equity is fairly high compared to the M&A comps that we've seen out there recently, almost incentivizing, potentially issuing equity to do a deal.

Would you be more open to that in this environment?

That is not our plan.

We would not plan to issue equity on anything that we've been looking at.

Okay, perfect.

Thank you.

Mark Gilman, Benchmark Company.

Guys, good morning.

Ed, a couple things.

I wonder if you could just highlight Aruba's operational and financial contribution to the quarter, statistically.

Well, Aruba -- this is Klesse.

Aruba has been a difficult start up, even though we have maintained our people and did maintain the plant, I will say that it was very, very difficult.

We are now running there, and we've had some issues even here during the first quarter and as we've gone into the second quarter.

Do you have the numbers, Ashley?

Yes.

Bill, was it profitable?

No, it was not.

Yes, it was not.

We pretty much -- we prefer to report by region, and -- but it was not profitable.

Yes, so we don't give out the detail on that but we're answering your question.

Well what kind of operating rate do you average in the quarter, Bill, or Ashley?

Yes, we can get you that.

Its average throughput was about 140,000 barrels per day.

Versus a 235,000 to 250,000 operating rate.

Okay.

One from Mike if I could.

Mike, help me understand how you generated net cash of damn close to $1.3 billion.

Was there a huge working capital liquidation?

Was there something unusual about deferred tax?

And what was the cash impact to closing out the derivatives?

Okay, first off on the working capital, we had a -- if you look at our payables, receivables netted, we had about a $900 million increase in payable, which contributed to that $4 billion cash balance.

We also had a small decrease in inventories that helped it there, but most of it was due to just the payable increase.

And then we did close out the positions, and that was worth approximately -- I mean the $542 million.

I don't have my change in margin for the quarter here, but it wouldn't have been significant.

Was that a cash outlay on closing those positions out, Mike?

Yes, Mark.

Okay.

One more if I could with respect to the $116 million maintenance impact.

Is that showing up in expense?

Or is it an opportunity lost?

Or is it some of both?

Can you --?

That's opportunity.

That's margin opportunity.

So that, Ashley, there's no expense element?

Not associated with that number.

Okay.

Thanks very much.

Sure.

Jeff Dietert, Simmons.

I was curious if you could give us an update on the Keystone XL project and what you are expecting there as they work through the permitting process.

And, is that project at risk given the new projects that have been proposed with the Monarch pipeline by Enbridge?

And this morning, Enterprise is out with a project from Cushing to the Gulf Coast as well.

Jeff, this is Klesse.

Joe is going to answer you, but really, all we're going to answer you is what TransCanada tells us, so to get the real facts you ought to ask them.

But Joe will tell you what we know.

All right, so Jeff, you do know that this thing continues to be tied up in the political arena.

And just going back in history a little bit, what we are dealing with is the EPA attack on the Draft Environmental Impact Statement, where they said that it needed to look hard at the additional oil sands development, and at less oil sands crude would help reduce the USA's dependence on oil.

Well on October -- or excuse me, on April 15, the State Department issued a Supplemental Draft Environmental Impact Statement on the pipeline.

And this concluded that no significant issues were uncovered, and that the Draft EIS conclusion for the project would have limited impact and it was reaffirmed, so there was no change as a result of the supplemental work that was done.

Now this draft goes out for a 45-day comment period that ends on June 6.

And the State Department has reaffirmed that they expect to make a decision by the end of 2011.

So, in our conversations with those involved, we believe that the pipeline is still going to happen.

And that is certainly TransCanada's position and that would be our position today too.

Now if it does proceed forward, but the schedule we're looking at would be Cushing to Arthur completed in the first quarter of 2013, and then the [hardest big piece] to Cushing would be completed in the third quarter of 2013.

And, the guys that have continued to work on the materials and the right-of-way, and they've got the bulk of the right-of-way in place.

I believe now they've got 75% on the Cushing to Gulf Coast segment; 83% on the piece that goes across the Ogallala Aquifer in Nebraska.

So the project continues to proceed, and we expect that it's going to get done.

Now as far as these other projects to get crude to the Gold Coast, I mean I saw Enterprise's announcement this morning, and you mentioned the Enbridge lines.

You know, the difficulty, Jeff, is in getting shipper commitments on the pipelines.

And certainly the advantage that Keystone XL has right now is that they've got a significant number of shipper commitments which have made the project viable.

And I'm not saying that those other pipelines won't happen or can't happen or shouldn't happen, but they've got some work to do to get people to commit before you can invest a significant amount of dollars to do a pipeline like that.

There's a lot of oil being found, though, and so it is our opinion that some of these projects, whether it's TransCanada's Keystone XL or [where that] -- they will happen.

Just to give you a little reference, the Eagle Ford crude is around 70,000 barrels a day last year.

And they are saying by 2016, it will be almost 500,000 barrels a day.

You've seen numbers for the Bakken, which is now lower than 400,000 barrels a day, is going up to 1.2 million barrels a day in one estimate.

So where people a couple years ago said the Bakken would double, they're now talking about 3 times out here in the 2016, '17 period.

So there's a tremendous amount of crude oil that is going to continue to make its way not so much -- not the Eagle Ford, but the other crudes, even out in the Texas Panhandle, that are going to make their way eventually to Cushing and thus, there has to be an outlet.

And so something will be done.

It's just going to take a little bit of time where new pipe has to be laid.

Thanks, Bill and Jim.

Jacques Rousseau, RBC.

Just wanted to see if you could give us an update on the FCC projects at Memphis and St.

Charles and when you think they will start adding to earnings.

This is Lane Riggs.

Memphis is already -- has been a great project.

And we are -- part of that was reliability, part of which was gross margin.

And it's already been a really good operation and it's --

And I think what Jacques is talking about is we had the gas plant.

Is the gas plant operational at Memphis?

It is.

(multiple speakers)

(multiple speakers) Okay, so (multiple speakers) is not, so we --

Both the cryogenic recovery liquids projects are up and running, and the second project?

Is St.

Charles MSCC converted to a riser.

Yes, we -- as I alluded to earlier, we're in the progress of completing that revamp right now.

We are anticipating the startup here in mid-May.

And I think the number we sort of -- we are counting on is about $120 million annually.

And remember this will allow us, where we were running 12 to 18 months on both of these crackers, we'll now get a four-to five-year run on each of these.

And converting the St.

Charles cracker from a MSCC to this riser will give us 5 to 7 percentage points of yield improvement.

One more question for you, please.

Could you let us know what the turnaround schedule would be for the back half of the year?

We're going to look it up for you here, but we really do not have any major turnaround (technical difficulty) back half, no.

We're getting you the date.

Hi, this is Lane again.

We have The Corpus Christi HDS unit turnaround in the third quarter.

And Corpus Christi also has a crude coker in sort of the later third quarter.

And then we have a Three Rivers crude vacuum FCCU turnaround in the fourth quarter.

Thank you.

Sam Margolin, Dahlman Rose.

Hey, guys.

Thanks for taking me.

I guess this is a question for Joe.

A lot of people talk about the limitations of moving crude around the continental US, but I was curious more about product.

We've seen some pretty chunky gasoline draws over the past couple weeks really focused on the East Coast.

From the outside looking in, it looks like a utilization issue.

What kind of excess capacity is there to put more product on Colonial or maybe some more from the Mid-Con where refining margins are a little stronger to make up what looks like a gasoline production gap?

It doesn't seem to be really demand driven.

It just seems like a lot of capacity is off-line presumably because of crude pricing.

You are absolutely right.

And we have seen more barrels moving up the colonial pipeline, and to the extent that they can do without the line becoming prorated.

The other thing you got to remember about the East Coast markets, and it's what makes it so competitive, is that it's the destination for so many important barrels.

Whether they be coming out of Canada or Europe, it is the home for that.

And so, we've had refineries done up there.

Sun has had some operating issues.

[PBF] is yet to get back up to full operations.

Once they do though, I think that situation will be remedied and those margins will adjust back.

Okay.

Thanks a lot.

Paul Cheng, Barclays Capital.

A number of quick questions, Mike, can you tell me some [bond ship] item, what is the market value of your inventory in excess of FO?

Okay, it's about $8.5 billion in excess of our LIFO (multiple speakers).

Okay.

And how about the working capital including cash?

Okay, total current assets are $15 billion, and current liabilities are $10.4 billion, so about $4.6 billion net working capital.

Right.

And what is the long-term debt?

$7.8 billion.

$7.8 billion, okay.

And Bill, and the -- I don't know, [understand exactly how we read] it; in your retail, you have a statistic looking at the fuel volumes, gallon per day per site; it looked like it's down about 1% year over year.

Is that apples to apples or that is a change in the number, the different (inaudible) in there, so we saw it's not a really good one to read?

Or do you actually see a 1% drop for your retail network?

And also there, can you give us some idea how April may trend?

Hey, Paul, this is Ashley.

On our -- on the retail volumes, that's actually pretty comparable.

Apples to Apples was -- on the gasoline side, was down a little bit.

But you got to remember, in our system, it's -- we're concentrated in the Southwest and we had pretty bad weather this year versus last year.

We actually saw diesel same store volumes up over 6%.

So, if you look at recent data points, kind of weeklies year over year, they're starting to -- they are positive again.

Ashley, if I could, street prices are very high too, and so the fact that the demand has hung in there the way it has is pretty impressive.

And Ashley is right; we did have very poor weather, particularly in the north part of Texas.

If you look our South Texas operations, though, we actually had sales were increased in the first quarter.

So it was more a regional issue than a broad issue.

And how about in April?

You're saying that the volume is actually back up.

Is it now -- on a year-over-year basis, is it up positively or they are just down?

I mean the master cut survey and also the DoD over the last six or seven weeks seems like suggesting that we started seeing negative growth.

In our system, Paul, we've seen -- like last week year over year was same-store, it was up.

It was positive.

Okay.

And, Jim, can you talk about the April export volume and how that's comparing to the first-quarter average?

Exports.

Oh, exports, yes.

Paul, this is Joe.

Our first-quarter exports were limited somewhat due to supply rather than lack of demand because we have the turnarounds at Port Arthur and St.

Charles, then we had some hawk issues at Corpus Christi.

But the [ARB] to Europe still is open for distillates, and we continue to see supply/demand imbalances In Mexico and Latin America and Europe.

Specifically, in the first quarter, we exported 65,000 barrels a day of gasoline, which went to Mexico and South America.

And then our diesel exports were 165,000 barrels a day with 75% of that going to Europe and 25% into South America.

And how about in April?

In April, it looks like volumes are going to be above where they were in the first quarter.

Okay, perfect.

And Joe, you guys have announced a small expansion in McKee.

Other than that, is there any other facility like the Ardmore in Three Rivers that you have opportunity to expand that could take advantage of discount crude?

This is Klesse, Paul.

We're looking at minor work around condensates and NGLs between Three Rivers and Corpus Christi, only because of what I said a few minutes ago about this tremendous increase in production that is happening in the Eagle Ford area.

McKee, we've announced, although permitting is going to take us a little while.

We don't have a plan here at the moment to do anything at Ardmore.

Bill, is that because the costs will be too much because you need to expand on a lot of different conversion units?

Or that -- because given the discount is -- that is a little bit curious that why they [don't look] at Ardmore.

You are exactly right.

We can do this expansion at McKee and primarily tie it to the crude units vacuum area.

We have capacity in the cat cracking and hydrocracking areas.

And you get over to our -- for instance at Ardmore, we would have to do work in the conversion units.

And, because we think the spread will narrow over time, that advantage dissipates.

It still will be there, though.

We think there's a fundamental shift that we messed that, in fact WTI is going to sell for less -- WTI equivalents are going to sell for less than the foreign Brents or LLS just for the transportation difference.

But it doesn't justify the projects.

Sure.

Two final questions.

One is after St.

Charles and Port Arthur, the hydrocrackers, is there any other major investments currently that is under consideration?

And secondly, after those two projects up and running, how does that impact the crude slate in those refineries, or is only the product yield is going to be changed?

Yes, let me do the first part first.

The hydrocrackers in and of themselves do not change the crude slate.

However, at Port Arthur, we have and are making investments.

We've built a new crude line.

We're looking desalter work so that we can run this Canadian crude oil that, as Joe said earlier, we expect to come to Port Arthur.

So, as far as that piece of it, it doesn't change anything -- at least outside of our plans already.

We look at other projects around our system.

Certainly, when we get Pembroke, we'll take a look at what's there.

But, basically, as we look at it today, this is the projects we're trying to compete, and we go through our planning process, but we are very focused on getting all of these projects done by the end of 2012.

Thank you.

Chi Chow, Macquarie Capital.

Thank you.

Bill, I think you mentioned in your comments that your CapEx now is $3 billion to $3.2 billion for this year.

Is that correct?

Correct.

That seems to be up from the last guidance we heard.

What exactly was the change there?

It's not -- it's probably the last thing maybe that you saw, but it is what I've been saying at the recent conferences that I've spoken at.

And it's really a matter of some investments around Three Rivers Joe mentioned -- we got a small -- but it's $10 million; we're putting in a truck rack.

We're doing things like that.

But, it's really the hydrogen plants and the acceleration of the hydrocrackers.

And of course our capital spending is going to be up from the turnarounds.

Remember we include that in there, and we had -- frankly, have overrun our turnarounds.

Okay.

And then next year, 2012, do you expect the same level of CapEx?

I do today, but -- and I've indicated that, but we're like everybody.

We got into the planning process pretty soon as we really articulate our number.

But for guidance, I would say it's going to be in this $3 billion to $3.2 billion range.

And does that include some of the spending on McKee?

And have you identified actually the cost on the expansion at McKee?

Yes, we have, but I'm not going to tell you.

But it's a very good project, but right now, we have to wait for our permit; and what's going on in Texas, and our people are working diligently with the DTQ, but we have this CO2 issue here now.

But, we expect the permit will be issued eventually, and we will get this project done, but this is not -- it's a very good project, obviously, with the discounts.

Okay, great.

Joe, you mentioned some gasoline exports in the first quarter.

Just more broadly, is this a growing trend out of the US on gasoline exports?

It looks like on the monthly DOEs, it shows -- been showing a positive trend.

What are your thoughts on that end?

Gee, I believe it is.

And everything would point that way.

We have very efficient operations in the Gulf Coast, which make us very competitive globally.

And then if you look at the market conditions, you've got Mexico demand exceeding their supply, and it's continuing to import products.

They're up to 350,000 barrels a day of gasoline and 110,000 barrels a day of diesel.

Petrobras has reported record domestic gasoline consumptions, around 400,000 barrels a day in 2010; and everybody believes they're going to need imports to satisfy their demand.

Venezuela and the Caribbean refineries are having lower crude runs, which means that there's fewer barrels available there to export.

And then even in Europe, you know, we've got the absence of the Libyan grades, which are affecting the overall distillate production over there, and so that's tightening things up.

Then of course we've got the Chinese demand and so on.

So I do believe that we are seeing just a long-term trend here that's going to allow Gulf Coast refiners to continue to export barrels.

This is going to be sustainable for a while here going forward?

I sure do.

Are you exporting out of the West Coast, by chance?

We are not.

Okay.

Okay, one final question maybe for Mike.

Does Valero still have crude hedges in place even after closing out the product hedges?

And if so, do you have both the realized and unrealized impacts in the first quarter?

No, we -- on those forward product sales, the crude hedges that were put in place in association with those have all been closed out, and the cash is moved.

Now these are -- Chi, these would be the crack positions that we -- the forward sales of the crack.

But we have position; paper markets are how we buy crude oil.

So we have many positions on -- that are tied to physical barrels and differentials and everything else.

But on -- where we forward sold, and I tell you it was only 10% of our production, forward sold the distillate and the gasoline crack, they are all off.

Okay, great.

Thanks, Bill.

I appreciate it.

Ann Kohler, CRT Capital Group.

Great; just following up on Chi's question, do you have the ability to export from the West Coast or you just -- basically deciding not to go ahead and do that?

Limited ability to export, but also, we haven't seen any demand pull out of the West Coast.

Okay, great.

And then what --

I think if you look at the cracks, you get the crack today and the gasoline out there is $30.

And you look at the Gulf Coast crack -- if you actually look at the numbers, the domestic California consumption, [pad by] actual consumption is better than exporting.

Okay.

And then could you just provide a little bit of additional color if there is regarding AB 32?

I know you highlighted it a little bit during your remarks.

But also sort of -- I know there were a number of issues that had to be resolved and whether those are being resolved or what the timing is on that?

Well, on the AB 32, we've gotten -- you just won't want like a total picture here, Ann?

Well, two things.

I know that you had initially indicated that there were some minor costs that would be -- that would impact you here, but that there were larger issues that still needed to be resolved, I guess by the California Air Resources Board in relation to the adoption of AB 32.

And I was wondering if there was any additional color on that or timing on that.

I will comment and Kim can add to it if she likes.

We've got the bill, so we paid -- I disclosed somewhere in one of my conversations that we would pay $5 million for the administration or development of the rules.

We have received those bills from CARB, so we will pay them.

The -- some of the other programs, for instance, for stationary sources from our refineries, which is a little over 3 million metric tonnes, that fee really doesn't start to occur until about 2015 because they are giving free allowances, so we don't expect any real impact from that.

And then what Joe commented on was this high carbon intensity crude oils, which is part of the LCFS.

And the facts are those rules still are being developed, and what Joe is indicating he was anticipating those, and so we have not run some of what we know will be or expect to be deemed high carbon intensity crude oil.

But those rules are still being developed here, so, it needs to wait and see.

And then, on the mobile sourcing, so in other words, the burning of the gasoline or diesel fuel in your car, those rules do not take effect until 2015 as well.

So, here in the short run, the next couple of years, the only thing is the administrative fee we've got, there may be some minor expense depending on the free allowances for stationary.

The high carbon intensity crude oil, we need to see what the final rules say.

And that will really impact our crude selection if they follow through with it.

But, now to give my commentary, I am optimistic that California is going to realize that this puts all of their refining and thus the taxes and everything at a disadvantage to other imports.

And so, I am of the expectation that this high carbon intensity crude oil piece is actually going to get a lot more discussion before the rules actually come out.

Okay, great.

And then sort of a follow-on I guess would be looking at the EPA on a national level and their desire to look at regulating CO2.

Do you have any sort of update on that or how you view that's going to play out?

Yes, Kim Bowers will answer you there.

Yes, the EPA is going forward with barring CO2 permits now starting January 1 of this year.

So, across our system it's something we're going to have to look at every time we look at an expansion.

In Texas, as Bill mentioned, it's more difficult because the state is going to be issuing permits and then we will have to go to the EPA for a separate CO2 permit, but I think we will encounter challenges as will everyone else in the industry going forward with the CO2 coming from EPA.

But, you know, all -- and I know you guys like to get me going on this, but for all of you that have kids and you think about business, here, we have projects that we are willing to do and we're having to wait for permits that are going to take us maybe over a year to get on CO2 that would put people to work, increase the tax base.

This is a very serious issue that we have in our country.

Faisel Khan, Citigroup.

Quick question.

On the West Coast, the throughput volumes were a little bit lower than what you guys had guided to earlier.

Maybe you elaborated on this in your prepared remarks, but I may have missed that.

Well, it's because the Benicia turnaround extended quite a bit.

We had start-up troubles after we finished the turnaround, and so we did not run the volume at Benicia.

Okay, understood.

And then going from -- looking at your -- the capacity numbers you guys published in your 10-K for your refiners kind of this year versus -- or 2010 versus the previous year, it looks like there was a bit of capacity creep in those numbers.

Just curious what causes that kind of creep to take place.

Yes, some of it is some bottlenecking projects.

Some of it is just re-rating because certain plans -- we've done some things coming out of turnarounds.

So they're just some minor little tweaks.

And those are permanent today?

That's correct; until we decide that something is not economic to run and it cuts capacity or some unit that is no longer in good shape.

Okay, got you.

Thanks.

Ed Westlake, Credit Suisse.

Yes, just one follow-on.

I'm just curious if you've rerun any of the [maths] on Chevron's acquisition.

And also the $1.8 billion of EBITDA uplift from your hydrocracker investments, given that we've -- well we will see what happens in Libya, given the strong global demand for diesel?

I'm going to let Ashley answer you on the hydrocrackers because I know he does.

But remember, a big basis there is crude oil price or, a sense, oil price versus gas price.

And we don't see any real fundamental change on that, so we still view running the hydrocrackers, the volume lets you get through --the liquid volume lets you get through the hydrocrackers.

And then they make a lot of diesel as the right project for Valero.

And you know, I'm like everybody.

I wish I had them today, but I also think we were prudent to stop them here a year or so ago.

Ashley, do you have --?

Yes, Ed, on -- in our publicly available and posted presentations, the most recent one had updates.

And really this is just using deltas on forward curve pricing.

And you look at the hydrocracker projects, and using a recent forward curve, and they contribute about $1.3 billion of EBITDA annually.

And the total program?

Sorry?

I'm sorry, what?

The total program?

Oh, it's up to about $1.8 billion -- and that -- depending on the change, how the forward curve changes.

But it's still -- it's continuing to show -- using 2011 forward curve very strong EBITDA generation.

And then Chevron refinery acquisition, presumably with it being complex and able to process heavier crudes and sour crudes and acid crudes as opposed to Libyan, that should be advantaged and perhaps make more money on the forward curve there as well?

Well it didn't really process sour.

This is Gene.

But it does process some acid crudes.

And I think the guidance we gave earlier on in the presentation is still pretty close [ever].

Yes; on our publicly held conference call, the slides that accompany that, that's still the best indication of earnings potential.

Great.

Thanks very much, everyone.

There are no more questions at this time, so this concludes our call.

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