瓦萊羅能源 (VLO) 2006 Q4 法說會逐字稿

Good morning.

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

At this time, I would like to welcome everyone to the Valero Energy fourth quarter 2006 earnings release conference call.

[OPERATOR INSTRUCTIONS] Thank you.

Mr. Fisher, you may begin your conference.

Thank you, Richard.

Good morning and welcome to Valero Energy Corporation's fourth quarter conference call.

With me today are Bill Klesse, our Chairman and CEO;

Greg King, our President;

Mike Ciskowski, our CEO;

Rich Marcogliese;

Head of Refinery Operations, Joe Gorder, Head of Marketing and Supply, as well as 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 valero.com.

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

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

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

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

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

Now, I'll turn the call over Greg.

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

I'm going to make a few observations about the year and then Mike will cover the quarterly results.

2006 was the best year in our Company's history.

Not only did we have record earnings of $5.5 billion, but we also ended the year with the strongest balance sheet in Company history.

The Premcor assets were a big part of the higher earnings, contributing more than $2.5 billion to operating income.

This acquisition has proven to be a home run for us.

Looking at the year, a key observation is that we delivered on our commitment to taking a balanced approach to investing our cash flow.

We spent $3.7 billion on our capital expenditure program.

We also bought back $2 billion of our stock, which was 5% of our outstanding shares.

This amount included completing the stock-purchase plan that had been outstanding since 2001.

As many of you know, this is the first time in our history that we have meaningfully repurchased shares, and we believe that our actions are a strong message of this management team's commitment to our shareholders.

Not only did we buy back shares, but we also increased our dividend twice in 2006, and just two weeks ago announced a 50% increase in the dividend, which brought our dividend more in-line with our peers.

The year also saw us get upgrades from two rating agencies, so that we are now rated BBB stable by S&P and Fitch.

I know many of you on the equity side may not see as much value in these upgrades as we do, but when you buy over 3 million barrels of feed stocks every day, it definitely makes Valero more competitive in the crude oil market.

Finally, we completed the sale of all of our interest in Valero L.P.

You'll recall that we acquired this MLP as part of the UDS acquisition, and over the years we have successfully grown it to the point where we felt this was a good time to separate ownership completely and to monetize our interest.

We contributed both our general and limited partnership interests to a new publicly-traded entity called Valero GP Holdings, LLC.

It IPOed in July when we sold 41% of our interest.

We then sold the final 59% in December.

Total proceeds to Valero Energy after expenses were $880 million.

After-tax, the cash proceeds were $555 million.

Mike Ciskowski took the lead on this deal and did a great job.

And with that, I'll now turn it over to Mike to cover the financials.

Thanks, Greg.

I'll run through the quarterly results and then make a few observations about the first quarter.

Fourth quarter earnings came in at $1.80 per share or $1.59 per share if you exclude the $196 million pretax gain on the Valero GP Holdings sell that we completed in December.

After tax, the gain was $0.21 per share.

For the full year, net income was $5.5 billion or $8.64 per share, including the full $328 million pretax gain on the sale of holdings.

Excluding that gain, 2006 full-year net income was $5.3 billion or $8.30 per share.

Other than last year's fourth quarter, this was the best fourth quarter that we have seen for refining margins.

Last year's fourth quarter was as good as it was due to the continuing impact the hurricanes had on refining capacity.

So seeing margins like we did this year with no hurricanes and the warmest December on record, it was impressive and reflects the supply/demand balance is still favorable.

On the cost side, fourth quarter cash-operating costs at our refineries were $3.61 per barrel, up a bit from the third quarter.

This was primarily due to higher natural gas and energy costs combined with lower throughputs from our turnaround activity.

General and administrative expenses were up slightly to $140 million, and total depreciation and amortization was $308 million, which was up by $14 million from the third quarter due primarily to the completion of several capital projects and turnarounds which Rich will discuss here in a moment.

Interest expense net of capitalized interest increased to $59 million versus $46 million in the third quarter.

The increase was due mainly to interest on tax-related matters and a reduction in capitalized interest as we completed some of our capital projects.

Our effective tax rate was 32.1% for the fourth quarter and 33.3% for the year.

The tax rate came in lower than anticipated due to the recognition of some tax credits in the fourth quarter.

With respect to our debt position at the end of December, our total debt stood at $5.1 billion, which compares to $5.4 at the end of 2005, and we finished 2006 with a cash balance of nearly $1.6 billion.

As for our buyback program, in 2006 we purchased approximately 35 million shares of our common stock for a total cost of $2 billion, of which around 4 million shares were purchased in the fourth quarter.

Now that we have disclosed our earnings and can reenter the market, we plan to resume our buyback activity under the recently-approved $2 billion program.

We will also continue to purchase shares in the open market to offset dilution created by our employee stock-incentive programs.

Looking at the first quarter for 2007, turnaround activity is relatively light, which Rich will discuss in a moment, but the main activity in the first quarter is that our Port Arthur, Benicia, and Lima refineries.

So for modeling purposes, you should expect to see Gulf Coast refinery throughputs of approximately 1.55 million to 1.6 million barrels per day in the first quarter.

Mid-continent throughputs should be around 565,000 barrels a day, west coast around 280,000, and the northeast system around 575,000 barrels per day.

Total refinery operating expenses per barrel are expected to be up slightly from the fourth quarter levels at about $4.75 per barrel.

This is due mostly to higher depreciation expense associated with the completion of capital projects.

With respect to some of the other items for the first quarter, we anticipate general and administrative expense to be around $160 million.

In the second quarter and beyond, I expect G&A expense to run around $145 million per quarter.

Net interest expense for the first quarter should be about $50 million with depreciation and amortization around $330 million.

And finally, for 2007 you should be using a 33.5% tax rate for your modeling purposes.

I'll now turn the call over to Rich to discuss refining operations.

Thanks, Mike.

This was a very active quarter for operations with combined turnaround activities and new unit start-ups.

In October we successfully completed a CAT unit turnaround at our Lima refinery.

It included an upgrade of the units reactor system and it was completed on schedule.

In November, we completed a plantwide turnaround in Houston.

This was a complex turnaround that included plantwide utility work and upgrading the CAT unit regenerator and power recovery turbine.

It also included refinery retrofits for Tier II gasoline, the commissioning of a new sulfur recovery unit, and the start-up of a new CAT unit flue-gas scrubber to reduce emissions.

Also within the quarter, there was significant activity in starting up new equipment to satisfy regulatory requirements.

We successfully commissioned new distillate hydrotreaters in Memphis and Port Arthur as part of our plan for producing ultralow sulfur diesel.

This plan also included starting up a new mild hydrocracker in Ardmore as part of our strategy at that refinery.

The addition of the hydrocracker at Ardmore should add an additional $10 to $12 million to Ardmore's 2007 EBITDA.

Lastly, in December we successfully commissioned a new CAT unit flue-gas scrubber in Delaware City to meet state air quality requirements.

Concerning 2007 activities, we successfully commissioned new crude and vacuum units at Port Arthur in late January.

With these units online, we have increased crude runs up to 310,000 barrels per day while filling downstream conversion capacity.

That compares to our prior crude capacity limit of about 260,000 barrels a day.

We expect that this expansion will contribute $90 million in incremental EBITDA in 2007.

Later this year, other new units will come on stream as part of our ULSD plant.

This will include mild hydrocrackers in Houston and St. Charles and distillate hydrotreaters in Benicia and Corpus Christi.

As for turnaround activities in 2007, this will primarily involve hydrocrackers at Port Arthur, Lima, and Benicia in the first quarter.

In addition, we'll be taking our 54,000 barrel per day CAT cracker down in McKee for two weeks to replace the unit's power recovery turf.

As you may have read, we also have a portion of our Texas City refinery down for repair following a fire on one of our crude units that occurred on Sunday.

The fire was related to a failure in a piping system, which affected adjacent instrumentation cable runs that support the CAT cracker.

As a result the CAT cracker will be down for about three weeks.

Finally, we are studying the Baker Panels recently-issued report for BP concerning refinery safety to determine if there is any need to strengthen internal process safety management systems at our own refineries.

Now I'll turn it over to Joe Gorder for an overview of the markets during the fourth quarter.

Thanks, Rich.

Well, products market sell down a bit in the fourth quarter leaving behind much of the extreme volatility we experienced in the third quarter.

The Gulf Coast Gasoline crack traded in a band between $4 and $6 per barrel while on-road diesel margins ranged between $12 and $16 per barrel.

For the quarter, the Gulf Coast gas crack averaged over $5.25 per barrel and the on-road diesel crack averaged $13.50 per barrel.

Both cracks are better than any fourth quarter we've seen, with the exception of last year's hurricane-affected numbers.

In the crude markets, sour crude oil discounts were also stable during the fourth quarter with the Mars discount averaging about $6.50 per barrel and the Maya discount averaging $13 per barrel.

Persistently weak residual fuel oil prices as well as the availability of good, heavy sour options have kept heavy sour crude discounts wide.

We believe both of these factors are going to continue.

One of the great things about Valero's refining system is its flexibility in handling feed stocks, which we took advantage of in the fourth quarter.

For example, we processed crudes like Cold Lake from Canada, Napo and Castillo from South America, and M100 from Russia at $2 to $4 per barrel better discounts than Maya.

We also maximized runs of heavy residual feedstocks to our conversion units, allowing us to back out higher costs to intermediate gas oils.

Doing so yielded a $5 per barrel benefit on the Gulf Coast.

In general, the benefit of processing sour crude oil was apparent in our Gulf Coast margin realizations for the quarter.

You may remember that at the end of the third quarter there was an interruption in the supply of A&S to the west coast.

In response we were able to run some more favorable alternative crudes that we we had been considering and found that they performed well at our west coast refineries.

These were primarily West African and South American crudes.

Even though A&S was in short supply, bringing these into the market pressured the A&S discount.

So going forward we expect to see these crudes come into that system more frequently creating the opportunity for us to back out some of our A&S purchases.

Now moving to products.

The bulk of the gasoline markets in the first quarter are off to a good start.

Gulf Coast gasoline margins in January have averaged $4.50 per barrel, while West Coast gasoline margins have averaged nearly $20 per barrel.

Lower crude prices have led to lower pump prices and, combined with a strong economy, has produced a 2.4% increase in demand this year versus last year.

The Gulf Coast forward curve is showing February gasoline margins increasing about $1 per barrel from January, then rising sharply in March to around $9 per barrel.

Turnarounds are kicking in, setting up for a tighter gasoline market as we start the transition from the winter grade gasoline spec to the summer grade spec in March.

As you may know, the summer grade gasoline spec requires a lower vapor pressure.

This is especially important in RFG markets.

What many people don't appreciate is the fact that ethanol is a very high vapor pressure blend stock requiring the removal of other blend stocks such as pentanes from the gasoline pool.

Doing so reduce the refinery's flexibility in producing gasoline, similar to last summer.

While we're on this topic, let me share with you our perspective with the impact of ethanol on the gasoline markets.

Clearly, ethanol volumes are increasing, and we expect to see about 400,000 barrels per day blended into gasoline this summer.

However, until significant investment in infrastructure is made, we believe that ethanol's primarily an RFG and mid-continent market discussion.

In the mid-continent, investments have been made in infrastructure to allow it to be blended into conventional gasoline.

In other conventional markets, the infrastructure does not exist to support large scale blending operations.

In the RFG ethanol markets, the ability to blend ethanol is effectively limited to 10%, except in California where its 5.7%.

In addition, the high price of ethanol and its low BTU value make it unattractive to blend where its discretionary.

As a result, we don't see ethanol having a serious impact on gasoline margin this is summer.

In the diesel market, low sulphur on-road diesel demand continues to be strong and is up over last year.

On-road diesel margins on the Gulf Coast average $12.75 per barrel in January and are currently at $14.25 per barrel.

Looking through the summer, the forward curve indicates that these margins will stay in this range.

In June, we'll also be facing another milestone when the off-road diesel market has its spec change.

Off-road diesel excluding marine and rail has to drop from a match of 2,000 PPM sulfur down to 500 PPM.

Even though it's only about 15% of the total distillate market, it's just one more limitation that we have to deal with in the refineries and logistically and should result in tight markets and attractive margins.

With that, I'll turn it over to you, Bill.

Thanks, Joe.

As we've mentioned on our last call for the last six months, we've been very focused on developing a solid, strategic plan for our Company as we look at the years ahead.

Even though the formal part of that process is complete, we continue to refine our plans.

The basic premise of our strategy is our focus on improving our returns.

We know that companies that deliver high returns outperform those that don't.

As we implement our plans, our goal is to deliver the highest return among the independent refiners.

Over the last decade, acquiring refineries has been the Company's primary focus.

Under Bill's Greehey's leadership, we were incredibly successful at that.

But now it is time to critically access our portfolio.

As an example of that effort, we have announced today that we are looking for strategic alternatives for our Lima refinery that we acquired with the Premcor acquisition.

As you know, we have looked at investing within Lima within Canada to process heavy sour crude oil from Canada.

Based on our review of that project, we felt that we had higher return opportunities in some of our other refineries and therefore did not pursue converting Lima.

That's not to say that this may not be a good strategy for someone else, so we've kicked off a process to explore strategic alternatives that could include selling the refinery.

Also, as part of our plan going forward, we will be working to improve our returns on our assets.

As we have grown rapidly in refining over the last few years, the primary emphasis has been on integrating and of course upgrading and meeting Tier II requirements at the acquired assets.

Opportunities to improve gross margins and overall financial performance are present in all of our refineries.

We believe that by focusing on reliability initiatives, better cost control and energy efficiencies we can improve the financial performance of our system noticeably.

Keep in mind as an example that a $0.25 per barrel improvement in either operating costs or gross margin is worth $300 million annually or after tax, $0.30 per share.

As to uses of our cash going forward, for 2007, we are committed to keeping our capital spending at $3.5 billion.

We do have some maturing and callable debt this year that we intend to retire because it is economic for us to do so.

Between maturing and economically callable debt, we should reduce our debt by $465 million to bring the total to about $4.6 billion.

I would also like to mention that we at Valero have a fully-funded pension at the end of 2006.

Buy backs will continue to be a key component of our use of cash strategy.

Our plan is to continue a program much like last year and we would expect to purchase around 5% of our outstanding shares again this year.

The management team recognizes that the shareholders own this Company and that it is our job to maximize their value.

And with that, we'll open it up for Q&A.

[OPERATOR INSTRUCTIONS]

Your first question comes from Doug Terreson with Morgan Stanley.

Congratulations, guys, on another great year.

Thanks, Doug.

Bill, you just talked just a second about how the Company was obviously the leader in the growth by acquisition phase during the past decade, and obviously that's been very beneficial for your shareholders, and also that we may be at the point where buying divestitures of nonstrategic plants may make more sense for returns in valuation.

At the same time, there does seem to be an increasing gap between purchase price and replacement costs again.

That is if you believe some of the new build quotes that are coming out of the Middle East.

When you guys think about this situation, how do you balance it with the strategy which is to improve your risk-adjusted returns and your valuation in the market?

Meaning, do you guys sense that there are acquisition opportunities in the market at this time, or is it fairly similar to that what we've seen over the last couple of years?

Doug, there are clearly acquisition opportunities in the market.

You just saw an announcement today from Petrol Plus.

Obviously Shell has announced plants in France.

So there's a lot of acquisition opportunities.

But you really are asking us how do we go about it, and we have a view of the future.

We look at the -- take that view based on the synergies and improvements we think we can make through refineries that we -- that are on the market or that we know about could be purchased, and we determine a purchase price.

And we look at the economics of the transaction versus then the asking price and what we have found over the last year is that we do not get convergence.

Point taken.

We do a rigorous analysis.

Sure.

I had one more question.

Rich talked about the new projects that are going to be completed in the refining business in 2007, and obviously they'll lead to better profits and returns.

On this point, I wanted to see if we could get an updated projection for the financial contribution that you guys expect from these investments, exclusive of Port Arthur, where I think Rich provided the number?

I'll recap that for you.

We would anticipate about a $300 million income improvement in 2007.

It was already noted, Port Arthur would be somewhere around $100 million.

If you combine the two mild hydrocrackers that we will start up later in the year, one at St. Charles and one at Houston, that will be about a $100 million contribution and then there are a number of other smaller projects that rounded out to the $300.

Great.

Congratulations again, guys.

Thank you, Doug.

Your next question comes from Doug Leggate with Citigroup.

Thank you.

Good morning, guys.

This is probably one for Joe, actually.

Joe, thanks for the rundown on the ethanol situation.

Last year we saw quite a hefty stake in some of the blending stocks.

I'm just curious on your outlook for how you see that this summer?

Are the bottlenecks still there?

Are we still going to see some tightness?

And what have you folks done to address your needs?

That's one and I have a follow up.

Okay.

As far as our view, we mentioned in the speaker notes that the infrastructure really is in pretty good shape in the mid-continent.

Chicago tends to be a market where ethanol trade through quite freely.

When we get to the northeast, things get a little tougher, and there's projects that are being contemplated today to take unit trains and move ethanol large distances.

But that's just not in place today.

So we think that there'll be supply available, but we don't think that people are going to be blending ethanol into gasoline where it's really discretionary at this point in time.

The Florida markets are looking at using more ethanol, but the infrastructure is not in place there either.

We don't see this as being an issue that's going to affect us really this summer.

Doug, I would add to that.

Some of the issue last year was when MTEB came out of the gasoline pool and we had to go to ethanol, for instance, in Dallas.

And much of the logistics issues that caused a lot of these shortages in Dallas and Houston had to do with truck transportation equipment actually going from the rail siding over to the terminals and those same trucks were used to deliver from the terminals to the service stations.

And that we would not expect to see at all this year.

Okay.

The follow-up I have is just relating to the flexibility you have to run resid versus some of the heavy oils.

You gave us some numbers behind that, but we've seen this continue to diverge in the first quarter, that is heavy oil discounts seemingly narrowing and resids seemingly widening.

Can you give us some idea as to how you respond to that and just how much incremental responsibility you have to move?

If you look at it on an absolute basis, you've got TI coming down from $70 to $50 over the period.

You really had resid pricing it on an absolute basis somewhere around $40.

You had a narrowing of the gap.

Now, we've seen lately is TI has increased in price, we're seeing a spreading of that discount again.

The way we do it, we optimize the feeds on a continuous basis and we run the resids when it makes most sense to do that.

Fourth quarter we had alternatives that would have led to perhaps a reduction in that as it tightened up a bit, and now as it widens out, I suspect it will be running more.

Let me just add, we run an LP.

Obviously, when you see the discounts you have we're fully loading the coker, but you have to run your LP to get the whole volume and profit equation to optimize.

So you can assume we are completely loading the cokers.

Then it's based on the prices that we see in the market versus the crude run, gas, resids, and 100 and the like.

Put those through the LP, we come up with our optimum charge life.

Great stuff.

That's it for me, guys.

Thank you.

Your next question comes from Jeff Dietert with Simmons.

Good morning.

My question is for Rich on maintenance activities.

I think it's been expected that maintenance would be heavy as we were preparing for tighter fuel specs, but many consultants are calling for heavy maintenance again in this spring.

Rich, could you comment on maintenance trends and if you're expecting more maintenance overall going forward?

Sure.

In our own case for Valero, it is a lighter year as it relates to CAT cracker outages for us, but we've got increasing turnaround activity on hydrocrackers and other fixed-bed hydrotreaters.

Going forward, particularly as I look at our own business, we've added a lot of new grassroots hydrotreating capacity to meet the demands of ultralow sulphur diesel.

These units in our case are probably going to run on about a two-year cycle, which would compare to CAT crackers and cokers that are on four and five-year operating cycles.

With sulfur requirements being as low as they are with gasoline at 30 PPM and diesel at 15 PPM sulphur, the fact that you've got to take these hydrotreaters off line on a more frequent cycle than some of the larger units, I think, is going to complicate the turn-around process going forward and probably create some utilization issues for refineries.

Good.

Also I'd like to ask Joe or Rich on what your LPs are telling you as far as maximizing gasoline production versus distillates.

If you look at the spot market, the distillates are trading at premiums to gasoline, but if you look forward, gasoline is trading at a nice premium out in April.

What are your LPs telling you and how are you situating your production now?

Jeff, you've got it right now.

Right now, we are in max distillate mode because the cracks would warrant that.

Going forward, I would expect that would change.

In our refinery system, we have the ability to swing the absolute production, probably 10%, Rich.

And so right now we're maximizing distillates and later, I'm sure, we'll switch to gasoline.

But you're right on target.

Thanks for your comments.

Yes.

Your next question comes from Philippe Lanier with Banc of America Securities.

Yes, good morning.

A couple of questions.

First of all just on a macro basis on the DOE stats, I think you've noticed regular increases on the import side gasoline of a classification of blend stock relative to finished gasoline.

And on the same time, you've noticed from the nation's refiners higher gasoline yields relative to what crude's going in.

Could you talk to that in terms of how you run your system and are you running different types of gasoline through your system to get a higher output, and how does that work?

This is Gene Edwards.

What's happening on the imports, a lot of what's happening was the ethanol blending.

A lot of the imports that were finished RFGs now come in as RBOBs.

So that's classified as a blend-stock option.

What happens is when this RBOB gets blended at the terminals with ethanol, the DOE's definition refineries include terminals.

So as you blend these ethanols with RBOBs at the terminal it shows up as increased gas production.

So what we do in our analysis, we back out the blend stock of imported to see what the true refineries are producing in gasoline.

We're finding that actually down from last year.

Okay.

A second question on the macro basis related to what the administration is doing pushing biofuels.

I wanted to see if political support continues to ramp up on the biofuel side.

Do you think that that's going to create a national shift of construction capacity spend away from refinery expansion into that arena?

And if that's the case, is that something you, too, would follow into?

We think that there is additional ethanol plants being added around the country.

And that's taking its natural course on to the current -- under the current RFS mandate through 2012.

Obviously, there is pressure in Washington to increase the mandate, but the reality of hitting the 35 billion-barrel target is very, very slim.

We think -- we think that actually that this process will take shape over the next couple of years in congress and that -- we think that the normal course of adding capacity in ethanol probably won't change that dramatically given just the President's message.

You're going to need to see further regulation in the congress before anything would happen.

Philippe?

Yes.

I would like to add to that.

Without some technology breakthrough, those goals are impossible.

Yesterday, I believe there was demonstrations in Mexico over the price of tortillas.

Yes.

It shut down the streets.

Corn has doubled from around $2 a bushel to over $4 a bushel.

We've done our work here, we think, and it's not just us.

There's been other publications that say maybe it's 15 billion gallons is absolutely the max that could come from corn.

There has to be some other --something else has to happen.

Right.

Exactly.

What I meant is along those lines, if you push into cellulose, can you get the appropriate funding for that?

Is that something that you guys -- if the political support just doesn't go away, it's an inevitability, is that something you can adjust your system to start incorporating and is that within your strategic vision should it happens to change?

I realize that it's not near term.

Well, sure.

The answer would be, if it's economic, sure.

Just one last question, as it does relate to Valero specifically.

There have been, at least in the headlines, some storm clouds brewing on the Cantoral field and what that means for Mayan production.

What's the reality on your front and your supply lines, and is there anything that you need to potentially shift in the next few years?

We talked to the Mexicans, who is a large supplier, all time.

And their tone would be one to calm our concerns about significant declines.

They also have KMZ coming on, which they expect will more than offset any declines that they have in their current production volume.

So their message to us would be just, let's not be too awfully concerned.

From our perspective, we continue to look for alternative sources of heavy sour crude.

Obviously, we're looking to the Canadians for some of that and so on.

Honestly, Philippe, we've been very effective at securing an optimized feed stock slate that includes heavy sours, medium sours and then some resids.

We don't see this as being a huge threat to us right now.

Super.

That answers all my questions.

Thanks a lot.

Your next question comes from Mark Gilman with the benchmark Company.

Guys good morning.

I had a couple things.

First one for Bill.

Bill, is evaluate strategic alternatives merely a euphemism for considering divestiture, or are there other possible strategic alternatives at Lima that are part of this process?

We would look at, and we have said we would look at options with the Canadian oil sands guys, we would look at asset swaps, but it could also include a sale.

Okay.

With respect to the impact of some of the capital projects and particularly the mild hydrocrackers in this year 2007 at Houston and St. Charles, Rich, can you give me a rough idea what kind of ULSD heat margin you're using to underpin the 100 million operating profit contribution?

Gene, what's our --

Yes, Mark.

I'll have to look that up and get back to you.

This is Eric.

Let me dig that out.

We don't have that level of detail.

Okay.

One more, if I could.

You might recall last quarter we talked about in the context of the mid-continent the impact of the Contango affect in the markets.

Kind of seemed to me that the Contango narrowed a bit, although it was volatile in the fourth quarter, yet it seems that in looking at the gross margins in the mid-continent, we're seeing an affect that is even more significant than was the case in the third quarter.

Wonder if you could shed some light on that issue and the impact in particular of changes in the shape of the future's curve?

Well, Mark, as far as the impact in the fourth quarter, if we think in terms of WTI and WTS as it affects McKee and Ardmore, we have a high degree of confidence that we have a $50 million benefit there.

There could be more there as we look at LLS, LNS, and HLS, but we'r very confident of the $50 million --

From the Contango.

From the Contango

That was your question last quarter, from the Contango.

I guess -- I don't follow, Bill.

We're saying, you asked last quarter what was the benefit of Contango in the mid-continent supply, the way we do our buying and hedging, and we're telling you it was $50 million this quarter.

Is that a third quarter number or fourth?

Fourth.

And how does that compare to the third quarter?

I don't have the third quarter number.

Okay.

Are there any other factors that are distorting what we're seeing in terms of the mid-continent margins one way or the other?

Not that I --

We ran well in the mid-continent, we had good operation -- reliability is such a driver to the realization, but we had good operations, asphalt was maybe a little better with the TI price falling.

Also during the quarter, WTS opened up and then came back in and we run WTS at Ardmore.

But it would be normal business.

Okay.

Thanks, guys.

Your next question comes from Chi Chow with Merrill Lynch.

Good morning.

Bill, in your comments you mentioned that you're focusing on reliability cost controls in your efforts to improve return.

How would you assess your operating performance of the refining system in '06?

Well, I would assess that we do an excellent job with what we have.

We bought Corpus Christi as a Tier I first core tile state of the art refinery, Wilmington, Benicia.

If you go through those refineries, they're absolutely excellent.

But then some of the refineries we bought, as we have said in the past, were clearly underinvested in over the years, and we have made tremendous improvements to those when you consider that the predecessors couldn't even run -- now St. Charles, they couldn't run Aruba.

We have Aruba up now most of the time running 240 to 250.

You look at our overall with the hand we were dealt, it's tremendous.

We've made, if you think of Delaware City, the best anyone ever ran the gasifier was -- I think 2005 was 666 tons for the year and we averaged this year --

Over 900.

Over 900 tons a day.

Through the gasifier.

And actually today are running the gasifier at 1700 tons a day, which is almost its capacity with where we have both drums on.

So you look at the hand we were dealt -- and I can go through every single refinery for you -- I think we're doing an excellent job.

And our people have thrown their hearts into this and have done a fine job.

Part of our high capital spending, and you see it in our maintenance costs, is we're fixing things.

As Rich and I tell our people every time we're at the plants, when we fix it, we're fixing it right or correctly or the proper word there.

So yes, we have trouble, yes, we leave a lot of opportunity -- or miss a lot of opportunity profits here.

But over time, we are improving those operations significantly.

Okay.

Those missed opportunities, just from an outsider looking at the situation, it seems like you had more down time unplanned in '06 than normal for Valero.

The reason I'm asking is just,what sort of improvements can you make in your system and do you expect '07 for it to translate into higher earnings, really, on '07 and lowering those incidences?

I think if you looked at our operations, delay coking and with the feedstock that is we run, we run very severe delayed coking operations and with that severity, we've had a number of issues this year with coke drum cracks.

Actually, those can be related to the original construction of these units and how they were built and how robustly they were built.

So we actually have a whole reliability initiative underway on delayed coking.

The issue you have is when you have unscheduled downtime on delayed cokers.

They're in your highest margin refineries.

So it tends to amplify the impact of the lost throughput.

That would be one example.

We have an issue with wall thickness on some of these cokers that Rich was talking about, and we have approved the project as we're going to go through and replace these coke drums at these two refineries that have the thinner walled coke drums that are cracking on us.

We believe it was an original engineering bust, at least with today's technology.

The other example I would use the CAT crackers, for example at Memphis and St. Charles, the design and configuration of these units, it is difficult to run them much longer than two years between turnarounds.

Where we would say our internal standard is somewhere four to five years between turnarounds.

We actually have retrofit projects in development for both refineries to allow us to achieve the longer runs.

So there are issues that we know about and we do have solutions in place.

And those projects are economic.

Each one is a little over $100 million and St. Charles will improve the yield there by 6 to 7 percentage points.

Remember, that's this millisecond CAT, one of three in the world.

Okay.

What two plants were you talking about with the wall thickness issue of the cokers?

That would be the Port Arthur refinery and St. Charles.

What we find is that, periodically, we will get cracks in the coke drums which you usually have to take off a pair of coke drums at a time for repairs that may take three to five days depending on the severity of the crack.

You have to think of the coke drum operation as heating up and cool down, there's tremendous stress is applied.

These are relatively thin-walled when you think about.

They're 3/4 of an inch to an inch.

When you look at the design today, if you did a new coke drum, you build them a little thicker.

It sounds that might be years off, given the backlog on vessels; is that correct?

That will be a few years off, but at the same time we've looked at our procedures and how we operate the drums to try to relieve some of the severity that brings on the cracking.

And remember, these aren't hydrocracker type vessels, the thick wall, 10-inch vessels.

The lead time isn't as long as the 10-inch, 11-inch vessels.

Okay.

Great.

Hey, thanks a lot for your thoughts.

We told you more that you wanted to know, I know.

That's fine, thanks.

[OPERATOR INSTRUCTIONS]

Your next question comes from Mark Flannery with Credit Suisse.

Hi, yes.

I guess my question follows on really from Chi's question.

It's about the magnitude of the operating improvements you're going for.

You mentioned on the call that $0.25 equals $300 million in annual savings.

I assume we shouldn't take that as a target.

But what kind of size of improvement are you shooting for in your internal plans?

And if possible, when do you think you would achieve various portions of that.

We have -- we do a five-year strategic plan.

When you look at our overall -- based on the 2004 Solomon indexes, which you're all familiar with, you go across our entire structure, we tend to be a fourth-quartile refiner in energy, maintenance, reliability.

So the type of thing we're striving to do with the core refineries here that we have is to move to the first quartile in that Solomon survey.

We won't necessarily achieve it in every category over this five-year period, but, clearly, if you look at energy or reliability, the prize is well in excess of $1 billion, if we could actually do what I just said.

That's for energy and reliability?

Energy, reliability, and maintenance.

So you're shooting for a prize of $1 billion over five years.

How are we going to know if you're on track or success in meeting your own target?

I guess you just have to ask me.

Okay.

We'll do that then.

Thank you.

Your next question comes from Paul Sankey with Deutsche bank.

Hey, Paul.

Hi, sorry about that.

Was on mute.

I asked you a great question, but you couldn't hear it.

In all seriousness --

Did you like our answer.

We had our answer on mute too.

Right.

It seems to me that a lot of strengths here is about diesel and we talked a little bit about trade and about the DOE data, but can you expand a little bit on what looks like very strong demand, which isn't really supported by trucking data and the extent to which you think that's either inventory build or rebuild or first-time build, I guess, in the case of ultralow-sulphur diesel, and exports and real demand.

Paul, the strong economy is driving distillate consumption.

Thanks.

Before the call this morning, Gene and I met with the team that does a lot of the forecasting activities for us and they actually showed us a statistic that the tonnage index had increased significantly over the last month.

And so, we really believe that distillate demand will continue to be healthy and the strong economy will continue to drive that.

Gene, is there anything else you would --

One thing -- I'm not sure where -- a lot of off-road demand is already having to switch to the on-road location.

Just because it's not available in terms of location.

You really see extreme increases in the on-road low sulphur diesel versus high sulfur diesel demand.

That's inflated the numbers as well.

Can you be a bit more specific on that?

Because that's intriguing.

You're saying because of a lack of availability, you're having to use it off-road, basically.

A good example is the mid-continent, where Magellan's pipeline doesn't ship high sulfur diesel to the markets anymore.

There's also construction equipment that they require 2,000 PPM today but they're having to go to 500 PPM or even the 1500 PPM, because there is not a 2,000 PPM availability up there anymore, so they're having to switch early.

As you get into July this year, a lot will have to switch to 500 anyway, but we're seeing them having to switch a lot earlier because of the logistics constraints.

Right.

I'm with you.

Are you saying you don't think that exports are a big issue?

We are seeing bigger imports than we had.

Exports he said.

You're talking about USLD exports?

Yes.

The theory was that the DOE doesn't really capture exports and so that could be a big reason why.

Until they give the final numbers, which are three or four months later.

We do know that a lot of discipline for the heating high sulfur has moved from primary storage to second and tertiary storage during the month of January and it was not moving -- you were filling up all the second and tertiary storages.

Now with the colder weather that's come in on the high sulfur side, we expect to see that move out.

But clearly I think that was affecting demand as it was moving to these other storage areas that don't get picked up.

Hey, Paul.

Just as a point of reference, too, we're not exporting ULSD.

Yes, that's what my question was leading towards, what you guys are doing, and I would extend the question to gasoline, are you importing a lot of stuff you were talking about earlier?

Gasoline, no.

Right.

So from your point of view, the trade story is not a big one, particularly not from the distillate, as a way of explaining away distillate strength, is what I'm trying to say.

A lot of it was moving from the primaries to the other storages and then wasn't getting consumed.

Now things are moving.

Okay.

That's interesting.

Thanks for your time.

Great.

Your next question comes from Ann Kohler with Caris and Company.

Good morning, gentleman.

Just a follow-up question regarding the initiatives for improving efficiencies and reliabilities.

Do you have any sort of a number associated with that in costs associated in trying to achieve that $1 billion?

Yes, we've had an energy cost that would be over the $500 million mark in the energy component and investments.

Now, not all of those would be done.

But what we'll do, Anne, is we'll get Eric to send you some stuff.

Okay, great.

And then also, you talked about you've done this five-year plan and your strategic vision, could you provide a little bit of color in terms of future for Valero and your strategic view?

Well, we believe that refining is going to be very good here at least through the decade.

We don't see new capacity coming on and demand is good.

There's more cars, there's more people in the whole world.

So we see gasoline demand is good, distillate is good with the rapid growth that we were talking about a minute ago, but in the entire world.

Demand is excellent, the economies are very good, still, even though maybe housing is not as good in the U.S., if you look at the far east, the rest of the world, it's pretty darn good.

So we see the growth.

Capacity is much slower coming on and much more expensive.

Now if you flip to Valero, we have certain refineries that we consider to be absolutely poor in our company and those are the refineries that you'll see us continue to improve dramatically.

So we see as a refiner and a marketer going forward.

So I take from that comment that there could be additional refineries that are reviewed for possible sale?

We have said numerous times and we're continuing this process, Ann, to look at all of our assets and decide how they actually fit into a Valero that's operating maybe in 2012.

And where do you see Valero in terms of -- in 2012, in terms of capacity?

And geographically?

I don't really have those numbers that I would like to give you.

But we see ourselves as a refiner and marketer.

Okay, great.

Thank you.

Your next question comes from Paul Cheng with Lehman Brothers.

Hi, good morning, gentleman.

With all the improvement you intend to do, should we assume the $3.5 billion CapEx is probably a pretty reasonable guess for the next several years?

Yes, you can.

Okay.

In terms of the portfolio, you continue to look at your portfolio, is there some kind of benchmark or criteria that you can share with us what maybe consider as keeper and what may be consider potential looking at our alternative.

If we're looking at Lima is a landmark and cost a lot of money to upgrade.

Is there anything you can share?

Sure.

We have certain criteria that we talk about.

We use when we look at refineries to buy.

We like water access, we like the capability to upgrade to run sour crudes, whether it's medium sour or heavy sour, which says that it either has capability -- either has coking capability or we can add it, meaning it has the proper metallurgy through the whole crude processing sections.

We want size.

We believe that you have to have a size that is over the 125,000, 150,000 barrels a day to get some economies at the site.

Also, we look at the competitive environment around the facility.

We have another criteria.

But anyway, we have five or six criteria that we look at our plants.

Primarily, though, it comes down to earnings power.

We've got a very classic, financial look at this type of stuff with the idea that the stockholders do own the Company.

Great.

Two final short questions.

One, in the event the alternative analysis that leads to a sell of Lima, should be able to believe the proceeds are mostly useful in buyback?

Secondly, wondering, is there any inventory in the quarter or trading or hedging gain in the quarter?

The first one was the proceeds, the second one was hedging?

Yes.

Any inventory gain or loss?

And also any trading or hedging gain or loss in the quarter.

So what we're going to -- we'll see what the proceeds are, because we are looking at alternatives there.

But if we assume it will sold, it will come into our cash balances.

We have said that we expect to buy back roughly 5% of our shares again this year which will be in that $1.5 to $2 billion range again.

We'll see how much cash we really have.

Without good projects or good economic opportunities, we've said we'll use the proceeds to buy our stock.

On the second one, really in hedging, we're just saying it's insignificant.

Okay.

I have told everybody, we're in the markets because I think a refiner today has to be in these markets, but it's insignificant in the scope.

Perfect.

Thank you.

Your next question comes from Gary Wilhelm with MPV Consulting.

Terrific quarter, guys.

I have three questions for you.

The first one is, about how much operating income was foregone in the fourth quarter due to planned down time, and how much to unplanned down time in the fourth quarter?

Okay.

In the fourth quarter, actually both numbers are close to $100 million.

We had about a $100 million lost opportunity from unplanned down time and about the same order of magnitude for planned turnarounds.

Okay.

So it adds to $200.

Yes.

Okay.

For modeling purposes, based on what you see now and based on what just happened at Texas city, about how much operating income do you expect to be foregone in the Q1 '07 due to refinery downtime?

We actually haven't developed a number for that yet.

We're so early into the outage, what you can model is we've said we're going to be short about 100,000 to 110,000 barrels a day clean products productions for about three weeks.

Right.

But probably more than that, right, probably more than just Texas City?

That remains to be seen, Gary.

And there are planned turnarounds that we do have going on in the first quarter, and that's going to be about a $80 million impact just from planned outages.

Perfect.

That's very helpful for me in my modeling.

The second question is, last earnings call you told us that wholesale marketing made a unusually high $80 million operating income contribution in the third quarter.

What was that comparable number in the fourth quarter for wholesale marketing?

It was $12 million, Gary.

Okay.

You would consider that a more normalized number?

That was low.

We had inversions on the west coast that would probably compress that.

Okay.

What number is normal? 20 to 25?

Yes.

It's volatile, Gary.

It's swings around a lot.

That's why, really, guiding to anything in that area is not really relevant.

It's such a small number in the grand scheme of thing, it's pretty volatile.

Okay.

My final question is this, it's a question about your stock market valuation, and a little background before I ask my question, the Lyondell/CITGO transaction suggested that if you apply their metrics, that Valero would be worth about $80 per share in the private market.

If you run the LBO economics on Valero, a take out price of $70 is easily supportable in an LBO.

Last August, Bill Klesse called Valero the best value in refining on a day when Valero was trading at $67.

However over the last six months, Valero has become an absolute pariah on in the private market now trading in the high 40s and low 50s.

In 2006, loyal, long-term shareholders, I'm going to include myself here, got a negative return on the investment.

So the question is, does Valero's current pariah status in the public market give you guys a greater sense of urgency to create value for shareholders, even to the point that you would consider something bolder than the status quo, such as a private, market buyout or recapitalization transaction or more aggressive buyback of shares?

Gary, I'm sorry that you did not have a decent return last year.

That's fine.

I've had a great return over three years.

But it does not give us a greater sense of urgency to do anything per se relative to the stock price.

What we're trying to do is operate our business here to generate the maximum value.

And we had record earnings for the year, we had a very good fourth quarter -- not as good as '05, but a very good fourth quarter.

So we're doing the thing that is we can control here.

Right, I understand you cannot control the share price.

I know.

I know you understand.

So we're doing those things and that's the thing that we're focused on.

In our business, because of lead times to do things, it's an execution.

We have to execute very, very efficiently and that's what we asked Rich to do here as far as the refining operation, and we do that.

We're making the improvements that I spoke about and every one in the entire refining group is focused on that starting right with Rich.

Now, you asked another piece of the question.

Would we do something radical here?

And we look at our options and we don't live in a box here.

We discuss what's out there.

But we are running a very solid business here that's going to generate long-term value for all our shareholders.

That's what we're about.

Excellent.

Thank you so much.

There are no further questions.

Do you have any closing remarks?

No, that's it.

Thank you for your time.

If you have any follow-up questions, just give us a call.

Thank you.

Ladies and gentlemen, that does conclude today's Valero Energy fourth quarter 2006 earnings release conference call.

You may now disconnect.