瓦萊羅能源 (VLO) 2012 Q1 法說會逐字稿

Welcome to the Valero Energy Corporation reports first-quarter 2012 earnings 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 of Investor Relations.

Mr.

Smith, you may begin.

Thank you, John.

And good morning, and welcome to Valero Energy Corporation's first-quarter 2012 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, Executive Vice President and Chief Commercial Officer; Kim Bowers, Executive Vice President and General Counsel; and several other members of our Senior Management Team.

If you have not received the earnings release, and would like a copy, you can find one on our website at www.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'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've described in our filings with the SEC.

Now, I'll turn the call over to Mike.

Thanks, Ashley.

And thank you for joining us today.

As noted in the release, we reported a first-quarter 2012 loss from continuing operations of $432 million, or $0.78 per share, which includes a non-cash asset impairment loss of $605 million after taxes, or $1.09 per share mainly related to the Aruba refinery.

Additional information about this loss is disclosed in the earnings release financial tables under Note D.

Our first-quarter 2012 operating loss was $244 million versus operating income of $244 million in the first quarter of 2011.

Excluding the items mentioned in our earnings release, first-quarter 2012 operating income was $367 million versus operating income of $786 million in the first quarter of 2011.

The decline in operating income was primarily due to lower throughput margins in refining, lower gross margins in ethanol, and lower fuel margins in retail.

Our first-quarter refining throughput margin was $7.71 per barrel, which is a 22% decrease versus the first quarter of 2011 margin of $9.91 per barrel.

The decrease in throughput margin was mainly due to lower discounts on crude oils and feedstocks, and lower margins for other products such as petrochemical feedstocks and petroleum coke, despite the higher margins for gasoline and diesel.

In the first quarter of 2012, Gulf Coast gasoline margins per barrel versus LLS increased 72% to $6.56, from $3.82 in the first quarter of 2011.

Gulf Coast ULSD margins per barrel versus LLS remained very good, and increased slightly from $13.59 in the first quarter of 2011 to $13.68 in the first quarter of 2012.

The Maya heavy sour crude oil discounts versus LLS decreased 37% from $15.68 per barrel in the first quarter of 2011, to $9.89 per barrel in the first quarter of 2012.

Our first-quarter 2012 refinery throughput volume averaged 2.6 million barrels per day; that was up 449,000 barrels per day from the first quarter of 2011.

The increase in throughput volumes was mainly due to the addition of capacity from the acquisition of the Pembroke and Meraux refineries.

Refining cash operating expenses in the first-quarter 2012 were $4.15 per barrel, which was higher than our fourth-quarter 2011 due to lower throughput volumes and higher maintenance expense.

But it was lower than our guidance of $4.50 per barrel, mainly due to higher throughput volumes and lower energy costs than we expected.

Our ethanol segment reported $9 million of operating income, which was down $35 million from the first quarter of 2011, mainly due to lower gross margins, as ethanol prices were pressured by excess industry supply.

Even with lower margins, the ethanol segment operated well, and achieved two quarterly records -- the highest average production rate at 3.48 million gallons per day, and the lowest cash operating expense per gallon at $0.28.

Our retail segment reported first-quarter 2012 operating income of $40 million, consisting of $11 million in the US and $29 million in Canada, which was down from the first quarter of 2011, mainly due to lower fuel margins.

In the first quarter, general and administrative expenses, excluding corporate depreciation, were $164 million, which was in line with guidance, but above fourth-quarter 2011, mainly due to legal settlements that favorably impacted the fourth quarter of 2011 results.

Depreciation and amortization expense was $384 million.

Net interest expense $99 million, and the effective tax rate in the first quarter was a negative 28%, but adjusting for the Aruba impairment, the effective tax rate was 37%.

Regarding cash flows in the first quarter, capital spending was $884 million, which includes $158 million of turnaround and catalyst expenditures.

Our expected capital spending for the full-year 2012 is consistent with our previous guidance at around $3.5 billion.

Also in the first quarter, we returned $189 million in cash to our shareholders, as we paid $83 million in dividends, and spent $106 million to purchase 4.5 million shares of our common stock.

With respect to our balance sheet at the end of March, total debt was $7.6 billion, cash was $1.6 billion, and our debt-to-cap ratio net of cash was 27.4%.

At the end of the first quarter, we also had over $4.6 billion of additional liquidity available.

We made several notable improvements to our refining system in the first quarter.

We started our hydrogen plants at Memphis and McKee, which benefit from high oil and low natural gas prices, and were two of our key economic projects.

In addition, we completed large turnarounds at our Wilmington and Memphis refineries.

And we began a very large turnaround at our St.

Charles refinery, which we just completed last week.

Included in St.

Charles work was a project that replaced coke drums to improve reliability.

Regarding key capital projects in progress, our two hydrocracker projects at Port Arthur and St.

Charles remain on budget and on time for completion in the second half of this year.

These projects were designed to capitalize on high crude oil and low natural gas prices, while producing diesel and gasoline to meet the growing global demand.

We look forward to completing these projects, and enjoying the expected benefits of cash flow.

So, 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 1.44 million to 1.48 million barrels per day; Mid-Continent at 380,000 to 400,000 barrels per day; West coast at 275,000 to 285,000 barrels per day; and North Atlantic at 440,000 to 460,000 barrels per day.

Refining cash operating expenses in the second quarter are expected to be around $3.85 per barrel, which is lower than the first quarter due to higher planned throughput volumes and expected lower maintenance costs.

Regarding our ethanol operations in the second quarter, we expect total throughput volume of 3.5 million gallons per day, and operating expenses should average approximately $0.32 per gallon, including $0.03 per gallon for non-cash costs such as depreciation and amortization expense.

With respect to some of the other items for the second quarter, we expect G&A expense, excluding depreciation, to be around [$170] million.

And net interest expense should be around $70 million.

Total depreciation and amortization expense in the second quarter should be around $385 million, with the reduction in Aruba's depreciation and amortization expense, mostly offset by additional expense from new equipment entering service.

Our effective tax rate in the second quarter should be approximately 36%.

Okay, John, that concludes our opening remarks.

We'll now open the call to questions.

Thank you.

We will now begin the Question-and-Answer session.

(Operator Instructions) Doug Leggate; Bank of America.

Good morning, everybody.

I've got a couple quick ones, hopefully.

My first one is really on the crude charge.

We've obviously seen another relatively extended period of very attractive PI and in line discounts relative to waterborne crude.

I'm just curious, I imagine you're trying to optimize your runs.

If you could give an idea of how if any changes that you're making, or have made, in terms of trying to gain greater exposure to those spreads.

And, I've got a couple of quick follow-ups, please.

Okay.

Doug, this is Joe.

Obviously we are try together run as much of the light sweet domestic crudes that we can.

If I look at our crude slate in general, from last quarter, we did run more light sweet crude.

We also ran more medium sour crude and we basically backed out resid.

So we continue to look for opportunities to optimize the overall slate.

When we think in terms of what are we doing in the Gulf Coast here and what do we think the market is going to look like, the Brent to LLS -- or LLS to WTI spread could be anywhere from $5 to $25 over the next year.

We just, none of us really have any idea as to what that's going to be.

We do believe, however, that longer term that's going to come in to $3 to $4.

I think this view would be supported by the fact that the Seaway pipeline tariff is in that range or slightly below that.

Now, we know that domestic production of light sweet crude is continuing to grow and it's going to continue to do so over the next several years.

And a lot of these crudes are making their way to the Gulf Coast via the pipelines, whether it be Seaway or Longhorn reversal, the Seaway expansion, the Keystone southern leg, and so on.

So these crude prices, the discounts are going to continue to come in.

And in the system, what we're doing is looking for every opportunity to run more light sweet domestic crude.

We currently run about 200 a day and we think that we can take that up by perhaps another 200 based on some projects that we're looking at.

So that's our plan, and that's what I got for you.

Thanks, Joe.

My follow-up is related actually because you guys periodically have dabbled with hedging.

And I'm just curious if you have that view that spreads are potentially coming in over time?

I'm just curious if you're tempted to try and lock in some of those spreads currently in order to make whatever adjustments on near term?

Doug, this isn't directly the answer to your question, but we have, and I think everybody knows that we've shifted our hedging.

The parity point of crude pricing has shifted away from the Mid-Continent to the US Gulf Coast, and so we shifted our feedstock hedging from a WTI-related basis to a Brent-related basis.

And the true WTI barrels that we run in McKee and Ardmore, we are hedging with WTI.

Everything else has been shifted to a Brent-basis.

That had a negative impact on us in the first quarter, but as we head into the second quarter, we're getting it back.

And with our long-term view that these spreads are going to come in, we believe that we're properly positioned.

Plus just philosophically, it makes sense to use the paper.

The crude that you're running is pricing off of is the risk management tool.

And then your question goes broader to our hedging program.

We do for our trading program, we do things from time to time, Doug, but nothing material.

All right.

I'll leave it there.

Thank you.

Paul Cheng; Barclays.

Mike, can you give me a number of the balance sheet item in terms of working capital, long-term debt, market value of your inventory in excess of LIFO?

Paul, the total current assets are $15.8 billion.

Total current liabilities $13.1 billion.

Our cash is 1.6, as I'd mentioned in my notes.

And then our current maturities are $1.1 billion.

The cash is already included in the $15.8 million that you gave, right?

That's correct.

Okay.

Market value of our inventory is $14.2 million.

And value in excess of LIFO is $8.7 million.

Total debt, which includes long-term debt, $7.6 billion.

And stockholders' equity, $16 billion.

$16 billion is stockholder equity.

Perfect.

Bill, wondering, if we're looking in Pembroke, did you make money in the first quarter?

What I'm going to do going forward here is because we don't break out these refineries.

We deal by system, so we're not going to give you any going-forward how we're doing on the particular plants.

This will be the last time.

Okay.

So, at Meraux we've had a very tough start.

However, we've had a turnaround, several turnarounds.

We had high crude costs come through, and so now as we get starting here into the second quarter, we think Meraux is going to fit very well.

You asked about Pembroke.

Pembroke has largely been break even at the refinery.

Marketing's done a little better.

But basically I'd just say to you it's been a break even.

Where we are working there is on cost and structure.

Their costs are much higher than the way Valero will run these businesses going forward.

And just to give you an idea, in April, Pembroke is very profitable.

So, basically, we haven't made any money on either of these plants or the acquisitions.

But we still think they fit very nicely for us and we've made a lot of changes in six months.

In Pembroke, or in your overall experience in Europe, does it in any shape or form has changed your view whether you want to further expand into the European market?

Well, it wouldn't be related to our experience at Pembroke.

We look at assets that come on the market.

Because we're very satisfied with the Chevron acquisition.

We've just had to make some changes in the way Valero does business.

And we had Joe Gorder over there.

And he's made a lot of changes.

And now we're sending Eric Fisher over to run the business.

And we'll be implementing these changes over the next year.

So our experience and how it fits into our system overall and for the long term, we're very satisfied.

Now, you ask about expansion in Europe.

Well, we're very concerned about the financial crisis in the sense that's going on in Europe.

We're concerned about, frankly, the very large refining overhang in Europe.

And so, as we see these plants coming on the market, we're just going to be very cautious.

It really has to fit into our system going forward.

Do you have a number you can share in terms of the same-store sales in the first quarter and also so far in April?

Yes.

So now we're to the US retail.

And we'll give you Canada as well.

And Gary Arthur is here, who runs our retail.

Yes.

The same-store gasoline was up 2.5% for the first quarter versus a year ago.

We continue to benefit from the strength of the Texas market, where we have about 600 of our 1,000 Company-operated stores.

So Texas continues to be very strong.

We're a little bit weaker in the west.

And I think that's a reflection of both the economic climate not being quite as strong and competitive pressures that we see in that market.

How about in April so far?

April, so far, we're about where we were in March, about even with March.

And on a same-store basis on gasoline, we're down about 0.7% when you adjust for the fact that we have five Sundays in the month of April this year versus last year, Sundays being our slowest day of sales.

So when we adjust for that to get a true comparison, we're down slightly.

And then when you say in the first quarter up 2.5%, benefit greatly from the Texas strong market.

When you strip out Texas, what is your overall same-store sales?

If with stripped out Texas, I would tell you we would be down slightly.

Less than 1%?

Yes.

I would say less than 1%.

That reflects California, Colorado, Arizona.

And Wyoming.

Those four markets.

Arizona is down significantly, and so has been Colorado.

That's right.

It looked like that in many of the shale oil play, the production coming out is NGON condensate and Brent may actually be less than 50%.

Paul, I missed a couple words.

I'm saying that in the many of the new shale oil plays, whether in Eagle Ford or even in the Permian Basin, the new net quick production increase looks like it's going to be NGON condensate and half brack oil.

Do you see there's an opportunity for you to blend more of the condensate in your system?

Or that you build some condensate better to take advantage of potentially an oversupply of condensate?

You have a lot of questions there.

In the Eagle Ford, the quality of the oil has actually been better than what was originally expected.

That being it's a little heavier, so it's a better quality oil.

So we're running, as Joe told you, but we're running 100,000 barrels a day.

In another month or two, we'll be even higher.

Between Three Rivers, Corpus Christi and Houston.

We're actually taken some to Houston.

So that's been higher quality.

Some of the other basins, we're not really connected to.

So it's been an academic question so far.

And, obviously, up in the panhandle, Ardmore has all been good quality.

So now to condensates, yes, we would agree with all the chemical companies from NGLs to condensates that we see this, and how you divide them sometimes gets a little hazy there.

But we see a significant increase in ethanes, propanes, butanes, all these, even to C-6s.

So, yes, we see that coming to market.

That's why I think somebody told me the other day, there's nine ethylene plants announced.

And this is the resurgence of the petrochemical industry in the United States.

And we, at Valero, are looking for ways that we can participate where we bring real value to the conversation.

So we continue to look at our options.

But, yes, your general statement is absolutely true.

There is a significant increase in NGLs in condensates.

Thank you.

Faisel Khan; Citi.

On the Memphis refinery, I know you have access to the Capline Pipeline system.

What's your ability as a major customer on that pipeline to influence its reversal?

We would probably have no influence at all.

We're not an owner.

It's Plains and Marathon and BP.

Yes.

Is that right?

Plains, Marathon, BP.

And they're the owners of the pipeline, and they own the pipeline.

Okay.

Understood.

Can you give us an idea of how your Eagle Ford crude is pricing into your refinery systems today?

Pricing off of LLS minus a discount.

We are posting.

And it's a posted deal which you could look up but I think it's LLS minus 6.

Great.

Thanks.

I'll get back in the queue.

It's a posting, so it's readily available to anybody.

Thank you.

Jeff Dietert; Simmons.

Good morning.

I was hoping you could talk a little bit about the hydrocracker integrations at Port Arthur and St.

Charles.

And what's required with those plants?

How does that impact the operations, the facility, as you tie those hydrocrackers in?

So Lane Riggs that runs refining is with us.

Lane is going to answer you.

We anticipate starting up Port Arthur, as we mentioned earlier, in the second half.

And we will finish mechanical completion on St.

Charles right at year-end.

We have start-up teams on the ground already working to get these things started up from the license ores and our own internal refinery experts.

We have a pretty good strategy in terms of trying to acquire feedstock for them.

So we're working through all that.

On the product side, Jeff, we've got the stuff in place to move the barrels out.

At Port Arthur we're looking forward to having the high-quality high-(inaudible) diesels that we've put on the market and export.

Then at St.

Charles, we've got the export capabilities, plus we're doing the Parkway Pipeline project, which will allow us to move barrels out of that market up to Collins and then into Plantation or Colonial.

So, Jeff, let me go back and add a little more to Lane.

The process, we're checking so he's mechanically complete, and then we have to check it out here, and that's going to take us three, four weeks.

Then we have to do some pre treating, then you have to load the catalyst.

So when you actually look at this thing, even though we've been training our people here for a year, actually, from mechanical completion to the point of starting up here is really going to take us between 60 and 90 days.

So that if you actually look at this, where I've told some of you guys we could get this done in six weeks to eight weeks, it's really going to take us a little longer than that because of some of the catalysts.

Remember these are high pressure units running at 2,200 pounds.

So we really won't see the benefit from the unit at Port Arthur until the fourth quarter in the P&L, and the same would be true at St.

Charles.

It'll probably spill to very late in first quarter, or actually see the full benefit in the second quarter.

Got it.

Very helpful.

And does the integration impact, the throughput, into the crude unit?

Jeff, it's Lane again.

No, the tie-ins, previous turnarounds, we don't anticipate a throughput on the rest of the refineries.

Very helpful.

Thank you, guys.

Sure.

Blake Fernandez; Howard Weil, Inc.

Good morning, guys.

I hopped on a tad late so I apologize if you covered this, but I had a question regarding the opportunity cost of the downtime in the first quarter.

Obviously, a very heavy turnaround period and that weighs on your efficiency and capture rates.

I'm curious if you can give us an idea of what your normalized earnings may have looked like had you not had that down time?

Yes.

Hey, Blake, it's our estimate for first quarter impact was $170 million.

$170 million.

That's pre or post tax?

That's pretax.

Pretax.

Okay.

Somewhat related to that, obviously, as we move to a more normalized run rate and hopefully cash flow improves, the buyback run rate in the first quarter is about $100 million.

Should we think that run rate improves heading into second quarter with hopefully improved gas low?

I would not make that assumption.

It is tied to free cash flow.

I have said that we will look at our dividend again in July as we completed the Port Arthur hydrocracker.

We also have $750 million of debt that matures here in April.

We already paid.

We also actually called $107 million of tax-exempt debt that was economic to call and that gets paid right here May 1.

Later this week.

Later this week.

So we are also working the interest rate arbitrage that you have on our debt.

So there's things that we're doing with our cash.

But our intent, Blake, is to return cash to the shareholder as we've said, and have one of the highest yields among our peer group.

We continue to do that.

We think our equity is still very inexpensive.

Thank you, Bill.

Rakesh Advani; Credit Suisse.

Thanks for taking my question.

I know you guys had highlighted that you're seeing a pretty strong export environment.

Just wanted your views on how long do you think that was going to last for and what the impact of Motiva will be on it?

I'll tell you, you said it, and it's true, the export markets are very strong right now.

Diesel growth and demand abroad is very high.

We're seeing diesel exports not at the highest levels but certainly very near that.

And for the quarter we exported 170,000 barrels a day of diesel.

The bulk of that went to Europe, the rest to Latin America.

On the gasoline side, we're also seeing strong demand.

Gasoline exports are at very high levels historically.

For the quarter, we exported 80,000 barrels a day of gasoline, most of which went to Mexico and Latin America.

If you look at the factors that are affecting the export market going forward, they're not factors that can readily change.

Chile is importing as much if not more distillates as they ever have, and their demand continues to grow.

So far this year, they're importing 83,000 barrels a day.

Mexico diesel imports were 105,000 barrels a day, and their refining capacity just doesn't meet their internal demand for products.

If you look at what's happening on the gasoline side, you've got Venezuela with capacity off-line.

We've got Hovensa shut down so that production is out of the market.

Mexico gasoline imports have averaged 392,000 barrels per day.

That's up 5% over the previous year.

And Petrobras is importing significant volumes of gasoline and diesel.

So all of these are based on solid economic activity and lack of supply.

And so these aren't things that readily get addressed.

Now, how will Motiva affect this?

Obviously, any time you're going to put more product into the market you are going to offset other products, unless there's growth in the market.

Who would be at risk in this case?

It would be the marginal cash.

The marginal refiners, and that's not us.

I think I would add to this that Joe mentioned, Hovensa's down.

We've shut Aruba down.

Aruba made distillate.

It did it not make gasoline.

Marcus Hook is down.

Trainer is down, but I guess it's coming back.

So if you look at just the basics in the US supply, even though some's East Coast, some's Gulf Coast, really, Motiva is filling in a void that these refineries have left.

So initially there'll be some logistics as people try to jockey things around.

Some will go in the pipeline because Colonial has done an expansion.

Plantation has some room.

And some will get exported but, on the other hand there's been refineries taken off-line.

Just remember that Curasol is limping along, and obviously the Venezuelans are really no longer in the export market.

Thanks.

And just one final one.

I know in your slides that you put in your presentation you talked about the [brendel] lesson version.

You've given the range, maybe between 2014 and 2015, where you could see an inversion based on 2011, import of light, medium sweet crude.

Recent data showing that imports of that kind of crude is only averaging 510,000 a day.

Do you think this would alter your view on maybe it's happening sooner than expected?

Well, I think it's a very fair question.

Remember, on our slide, there is a little bit of a where you make the cut between some of the lights and the mediums.

So if you are looking at our slide, let's just stick with our numbers, because we probably have some medium crude in there.

But basically, the US is going to push out of the Gulf Coast the light sweet crude.

Now, it is happening quickly.

Eagle Ford production is increasing dramatically, and that is getting to the coast.

Some of the other crudes, Enterprise says they're going to start on Enterprise.

Enterprise Enbridge will start up, in May, right?

In May.

Don't forget you have Magellan on Longhorn so you have all these things that are going to happen in the next year.

So all that crude is coming.

The big piece of that I will remind you, and our assumption is that BP at Whiting, with BP's heavy up project.

And so that's a big, like 200,000 barrels a day of the volume that basically gets pushed back into Cushing.

So we still think it's a 14-15, but your question is correct, it makes a little difference where you're cutting the lights and the mediums.

Thank you.

Sam Margolin; Dahlman Rose.

You mentioned seaway.

I was curious if you have any guidance for Seaway barrels that you might be buying for second quarter or later than that.

I guess it's starting up, as you mentioned, in the next couple weeks.

We're not a shipper on Seaway.

It would just be availability of barrels on the Gulf Coast.

And for those, they'd already be repriced at LLS once they get there?

I guess.

It just depends how many of them there are.

All right.

Lastly.

More of a macro question.

There's been a lot of outside of industry interest in refining assets, presumably it's just a reaction to simple coastal cracks expanding.

It seems like the benefits of this capacity rationalization that we saw lead to events that offset those benefits down the road when you get restarts.

Are you concerned about the levels of light sweet cracks here on the coast as we get restarts and private equity or outside buyers chasing the market?

We believe there's still too much refining capacity in the US as well as certainly Western Europe.

So the Atlantic Basin has too much refining capacity.

So how does the industry balance?

It balances by reducing operating rate.

And so as these plants, certainly as Trainer appears that it's going to come back into the market, it's going to put some refined product back in there, and that will affect operating rates.

But the industry is slowly rationalizing capacity.

It just does some things die hard.

Thanks very much.

Doug Terreson; ISI Group.

Can we just summarize your comments on US gasoline and diesel demand to say that it appears, and I know this isn't perfect that we may be gravitating towards minus 1% to 0% growth year to date?

Is that consistent with what you were saying earlier?

Well, certainly it's down.

Gene is going to give you a comment.

If you look at the monthly data, the weekly data that has come out, it looks like gasoline demand has been off 4% year-to-date.

The DOE published the February monthlies, all the revised data, and I think they were missing exports last year on gasoline.

They were understating.

This year they've been overstating.

Also some discrepancies on naptha, whether it's a blend stock or a chemical feedstock and how that gets categorized.

So when they published the February data they revised gasoline demand up by 300,000 barrels a day, which put it flat to last year.

This is February.

January we had a similar thing going on.

We won't have the March data until a month from now.

But it looks like gasoline demand is a lot flatter to last year than what all the other data was showing.

Distillate got revised up.

The weekly data shows flat with last year.

The monthly data says up about 2% versus last year.

And that's consistent with what you're saying in your markets?

Exactly.

Also Bill you mentioned about the resurgence in the petrochemical industry or something along those lines.

So you mentioned you might be interest in participating in the value chain.

To the degree you're interested could you comment on what you many by that and does that includes grass roots or just petrochemicals?

I don't know if it includes grass roots in the sense of businesses where we don't participate.

You need to bring some value to this conversation.

But we make benzene, toluene, xylene.

We make light propylene today.

I'm sure we do something else.

Is there anything else we make?

We're big in propylene here so we've looked at midsylenes.

Obviously these condensates actually I think will replace some oil long term into gasoline.

So there's a lot of that type of thing and we're looking at how do we take advantage of this?

Because if you think strategically about Valero, we've largely made fuel.

80% of our output is fuels.

And it doesn't necessarily all have to come from oil.

That's correct.

Thanks a lot.

Paul Sankey; Deutsche Bank.

Just a follow-up to an earlier comment that you are running about 200,000 a day, I think it was WTI was how you described it.

You had several projection underway to double that.

Firstly, what's the time frame on the project?

And I guess the big question here is how much more light sweet US crude you believe you can run on a longer-term basis and how much that would cost?

Thanks.

Well, let me answer you then, and Joe could add to this.

At Three Rivers, Corpus Christi, we're approaching about all we can run without getting out a permit option and a project.

And that number is going to be 140.

Including Houston?

No that would not.

110 at Corpus and at Three Rivers, and then we're doing 30 or so at Houston.

Then we have numerous pre flash options that allow us 30,000 here, 40,000 there, at some of our other plants, which we can do because it loads up our light engine.

Beyond that, we are still basically a heavy complex coking refiner, and we still believe strategically that the Keystone pipeline is going to be built, it's going to be built on Obama's time scale, which is first quarter of 2013.

We think that there will be approval if he wins election and that the pipeline will get done by the end of 2014, early 2015 and that heavy crude oil will come to the US Gulf Coast But Valero still brings value in being able to operate these coking-type refineries.

It will all be driven he economically with our LPS, which we'll squeeze in light crude if it's priced properly.

The list got me to 200 of existing.

Where is the extra 200 coming from?

If we take a look at what we can do, Houston to run 100% light sweet.

This is all assuming that the economics make sense for us to do this.

You can run more poor light sweet crude in Texas City and we could run light sweet crude in Port Arthur.

I'll give you some numbers because obviously we do all this work.

We could run about 95,000 at Houston, 40,000 at Texas City, 40,000 at Port Arthur, 20,000 at St.

Charles, and 50,000 or so at Meraux.

And so we can do those kind of things.

Is that with no extra spending?

There is some spending but very minor.

And then if there was sorry to press the subject, but very interesting, and a very big story.

It's because every company you will talk to is going to try to do what I'm speaking.

And what do you think would be the next leg if you wanted, let's say, for example, if Keystone was not approved or it was uncertain for another three years, four years, whatever?

What would you do then?

What we would do is be forced to look at being able to run more light sweet, and light medium sweet crudes, at some of our refineries because it would all be depend on what the diff is for the heavy sour.

So second part of that first, what is the discount?

I think there's an approximate number to think about for how much discount, premium of heavy, whatever it is, that would cause to you say all light sweet from here?

Well, we think that between on a sunk coker, between 10% to 12% of the price, you can run a sunk coker and make money.

And if you would drop down, if you get down to 8%, 7%, if you still have $100 oil here, you're running out of economics on a coker.

Do you think so?

Depends on where the medium sour is.

Today medium sours are running between $5.50, $6 discount to LLS, so we're still see going margins to run the medium sours versus sweet.

Then look at the medium sour is going to be a switch between that and the heavy sour, and that's going to be about $6 as well.

So, this is what Gene is giving in more detail is what happens every single day.

We have a whole department that runs these models for us.

It would just be if we don't have the discounts out there for heavy sour, we're optimizing the system all the time.

Remember, we're buying our oil every day.

What I'm wondering, at what point would you start investing to up your light?

Obviously, you wouldn't do that until you were sure Keystone wasn't going to happen.

We might do some pre-flashing, but the issue you run into, quite frankly, is you load up your gas plant.

And your light ends capability so those projects certainly become bigger.

And then we have to be to be honest in the world we live in today it is extremely difficult to get these permits as long as we have to do CO2.

In Texas, it's terrible.

Kim is here and she's telling us even in Louisiana and other states it's extremely difficult.

And that's because you get more CO2 with a light sweet crude?

Because we may have more heaters, more processing.

If we tripped the rule we have to cover CO2 in our permits, whether you're in Texas or anyplace else, before we hit that major level.

Okay.

Is there any sense of what that level is?

Sorry to keep pressing but it's kind of crucial.

I think it's 75,000 or 100,000.

75,000 or 100,000.

It's a threshold that's higher than would it normally be to trip it.

Still almost any significant project will trip it.

That's interesting.

That makes us and everybody else have to get a permit that addresses the CO2.

But I think, final point, you don't expect the crude export ban to be lifted, right?

We do not.

Is there a specific reason for that, or is it just a general opposition to raise, effectively raise crude prices in the US some?

It's just we just felt that's going to be very difficult to have happen but I wouldn't say within scientific or any better answer here than would you have yourself.

Okay.

That's all extremely helpful.

Thank you very much.

Sure.

Evan Calio; Morgan Stanley.

Follow-up on this broader Gulf Coast impact from US production growth.

Just beyond maxing out light runs in your system which clearly isn't optimal or current differentials isn't optimal for many of your refineries.

But before any major Canadian solution is available, as a next step, can you talk through an increased blending opportunity or with the overload of lights to blend into some of these medium crudes to press those discounts or recreate those?

How do you see blending playing out when you have system in the Gulf of Mexico?

And you could debate the time, based upon what you think production growth rate is, where you are going to back out at least one type of crude, at some point, debate the time frame, but over the next couple years?

How does blending play into that?

It's a very good question.

We aren't blending or anything at terminal so this is all at refineries.

We are at St.

Charles and at Corpus Christi putting in facilities that will let us run a broader selection of crudes, then we will blend them for the process unit because we would like to show the process unit a relatively steady diet here of crude.

So we actually have two of our plants have projects underway right now.

One is tankage, one is a lot of pipe.

To allow us to blend crudes for the unit which will let us run a broader spectrum of crude.

And we're looking at the same type of projects for the other plants as well.

So we're doing it at the refineries.

That lets us then optimize that crude cost.

Does the blending raise the potential ceiling of the light sweet diet that's ultimately blended into something else before it's run versus what you've stated?

Yes, we would optimize.

You're asking something here, so we're going to give you how we view it.

This is Lane.

The number you heard from Bill earlier in terms of the mellow light sweet crudes in each one of the refineries is pretty much the number on a blended basis into these refineries for the light end constrained, [accrued capacity], backing out medium sour or light sweet in that.

Okay.

So there's not incremental back-out of any kind of medium barrel, if the price allowed it without a front end investment?

We look at the relative values of these domestic sweets, or any sweet, for that matter, versus the medium sour, and we increment up to a constraint on the refinery.

The numbers that Bill had given you earlier is roughly our constraint, (inaudible) probably backing out, depending on the refinery, medium sour or sweet.

Okay.

Understood.

Different question on Keystone South and I didn't know if you had in your comments.

Do you have to nominate in that line to maintain a position in the Keystone Excel, the transnational line?

No.

They're reserving space in the south segment for those who nominated space as part of the bullet line.

Right.

But, I mean, if you didn't take Keystone South capacity, would that negatively impact your ability for your nomination when the line is ultimately done.

No, it would not affect our commitment from Hardesty south.

We have our space.

The committed shippers on the northern segment will have their space all the way down, When I ship from Cushing south, then we need to nominate incremental space.

We've got our space from Hardesty to the Gulf.

If we want to move Mid-Continent south from Cushing, we would need additional, we would need to nominate.

Understood.

Maybe lastly do you have any closure cost estimate on the Aruba refinery?

As of today we've just suspended operations so we are working all our options and still continue to work our options.

And so it's a different situation than some of the other numbers that you've seen in the marketplace.

But our's would be less than $100 million, but the facts are that it's not what We're working here really some options here that will be good for our shareholders.

Okay.

Maybe if you could sell to Delta.

Thanks for taking my calls.

Arjun Murti; Goldman Sachs.

Just so I'm understanding the light sweet ability in the Gulf.

You can do 200 today.

To do another 200 requires some modest amount of investment and then to go beyond that you have the issues with the permits and more meaningful CapEx?

Am I understanding that correctly?

That's correct.

Any quantification on how much minimal investment is and the time frame to do it?

Not much.

Like Bill said, to do more than we have the capacity today we'd have to put some pre-flash towers in some of the heavy sour locations because the capacity of those towers really were designed to run a heavier diet.

No, I don't think we have a great number for you.

Okay.

And then separately, you talked about ongoing portfolio optimization.

You've obviously taken action at Aruba and the East Coast.

Does California fit in, in terms of how you see this part of your system?

Presumably not as bleak of an outlook as the East Coast.

Do you see any light at the end of the tunnel or any other actions you can take to improve your California outlook?

Thank you.

Arjun, we are taking action.

Our costs have been too high and we have been addressing that to get our per barrel costs down.

We continue to work there.

But the California market is a big market.

And we still have 11% unemployment in California so there are many, many economic issues in the state.

The thing that is struggling to us is that their policies, primarily from CAR, are extremely anti-business, and the consumer really does not understand how much his prices are going to go up which is what CARB wants so that they get the conservation.

So you ask the proper question, where it tried to optimize our portfolio so that we could compete long-term, and we're trying to evaluate all of these issues and what our real potential is on the West Coast.

Would separating it from Valero make sense, and is that a consideration for you?

I haven't thought of that.

You mean like separated interest, a freestanding business?

Yes, Valero California, whatever you want to call it, separate company, spun out from Valero corp.

We have not looked at that.

Thank you so much.

Chi Chow; Macquarie Capital.

Sorry to circle back on the light sweet issue.

So if you put in these flash towers with minimal CapEx, does that change your crude flexibility at all going forward?

In other words, can you swing back to the heavier barrel if need be if prices are correct?

I guess.

Yes, we can.

You guys are asking us things that we have not engineered here.

We're off in a conversation that is probably four years out.

But, yes, if that would happen.

But I want to emphasize what we do every day, and frankly what our competitors do every day, is they're running their LPs, and they go to a crude mix that they believe is the optimal for that facility.

And what we're doing right now is we're building some tankage at St.

Charles.

We're doing work at Corpus Christi that will allow us to blend crudes, give us more flexibility here so that we can run and buy some other crudes that are priced economically.

When they're available.

When they're available.

But as this volume continues to increase, we, as everybody, wind up being able to run more of this light and medium crude oils, because we will do things around our plants to let us do it, because we do believe that LLS is going to sell at a discount to Brent.

And that's the main point that will drive you that way.

Right.

Okay.

Thanks.

Mike, couple of quick items.

What's the remaining CapEx on the hydrocrackers as of the end of the first quarter?

And did I hear you right, the debt maturity in April you paid that off?

We paid off the debt maturity.

The remaining capital on the hydrocrackers, on Port Arthur we look like $300 million left.

On St.

Charles $500 million left.

Okay.

Great.

Thanks a lot.

Just so you know, there's a couple of other little projects around there that are finishing as well.

Faisel Khan; Citi.

Just a follow-up.

Where does Memphis fit into all this?

Clearly, I think that's consuming LLS benchmark crude.

So what kind of crude slate is that consuming and how with that benefit from LLS discount versus Brent?

Well, it will benefit in the sense that what the product prices are, but your observations are correct.

Memphis runs an LLS plus because the Capline flows north so this goes back to a question earlier that someone asked about Capline going south.

Also, some crudes can come into the refinery by water as well.

But the plant runs LLS plus.

It does have a very strong local market, though.

That, I guess it's the largest rack in our system, or very close.

And we have a big customer with the turbine fuel, and so we operate in more of a regional capacity at the Memphis plant.

Okay.

And on the hydrogen plant investments that came online, I believe you said in the first quarter slide you gave us some guidance in your slide presentations of around 100 million in EBITDA, base days.

Using 2011 prices you said about $176 million using LLS, but I assume that was based on last year's natural gas prices.

Trying to figure out what the lower gas price for this year means in terms of potential uplift for that investment.

The guys are looking it up.

Remember, at McKee we have the cat-cracker down.

We're still running some oil there.

But we have a big turnaround going on.

So the McKee hydrogen plant has not run to capacity yet.

Hey, Faisel, this is Ashley.

For every dollar change in the price of natural gas per mmbtu it adds about $6.5 million a year in EBITDA.

Based on 2011 pricing, we're effectively using $4 natural gas.

So you could easily, on your call, whatever your call on natural gas is, it's at least a buck lower, could be more.

Okay.

Got it.

Thanks.

Appreciate it.

Harry Mateer; Barclays.

Quick one from me.

Mike, can you confirm the April maturity.

Did you pay that down with cash on hand or did you use the bank facility or the AR line?

We have dipped into our AR line a little bit while we've paid off this maturity but we started the quarter with $1.6 billion of cash.

Okay.

So what's the pro forma debt number we should be using?

Oh, I guess we're probably going to go ahead and issue some tax exempt bonds that we have the ability to do.

So if you want a good number, I'm going to say to you 7.1 or 7.2.

Okay.

We have no further questions at this time.

Thanks to John.

And I want to thank investors for listening to the call.

If you have any questions, please contact Investor Relations Department.

Thank you.

Thank you, ladies and gentlemen, this concludes today's conference.

Thank you for participating.

You may now disconnect.