瓦萊羅能源 (VLO) 2005 Q4 法說會逐字稿

Good morning ladies and gentlemen, my name is Miles and I will be your conference operator.

At this time I would like to welcome everyone to the Valero Energy fourth quarter 2005 earnings conference call. [OPERATOR INSTRUCTIONS].

I will now turn the call over it Mr. Eric Fisher, Vice President of Investor Relations.

Mr. Fisher, you may begin your conference.

Thank you, Miles.

Good morning and welcome to Valero Corporation's fourth quarter 2005 earnings conference call.

With me today is Bill Klesse, our chief executive officer, Greg King our President, Mike Ciskowski our CFO, Rich Marcogliese, Head of Refinery Operations, and other members of are our senior management team.

If you have not the received earnings release and would like to get a copy you may obtain one off 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 those tables feel free to contact either Joe, Kim or myself after the call.

Before I turn it over to Bill, 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 that state the company's or management's expectations are 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 which could cause our results to differ from our expectations including those we've described in our filings with the SEC.

With that I will turn it over to Bill.

Good morning.

Thank you for joining us today for our fourth quarter conference call.

Since this is my first conference call as CEO, I would like to make a few comments about our leadership team and what we expect to accomplish going forward.

Under Bill Greehey's leadership, we've grown to become the large refining company in North America through well timed acquisitions and by investing in the plants that we acquired.

I can assure you that we will continue to be a growth company.

We are obviously going to stay very focused on operational excellence, maintaining safe and reliable operations is our number one priority, and I know that our leadership team has this same commitment.

Experience has taught us that safe and reliable operations go hand and hand with profitability so we'll continue to work hard in these areas.

Over the last few years, our focus on expanding our operations and making investments to improve gross margin has clearly been the right approach.

Going forward, we believe there are opportunities for us to focus on our competitiveness throughout our system and carefully manage our capital spending so that we can achieve the highest returns possible.

Acquisitions will continue to play a role in our growth, but as we have demonstrated in the past, we won't over pay.

We will continue to seek out assets that we can upgrade and are complementary to our system, offering us a good growth platform.

There is no doubt that this is a great time to be a refiner and we believe that the next few years will represent a period of tremendous earnings growth for Valero.

I know many of you share this outlook which is probably the reason that we're frequently asked what we are going to do with the free cash flow that we expect to generate.

Our plan will be to take a balanced approach to creating shareholder value.

That means that we will not only pursue acquisitions and strategic capital investments, but share buy backs and modest dividends increases will also be a part of it.

We will also pay off debt as it matures and, if economic, we will prepay long-term debt if the opportunity arises.

With respect to our management team, I am very fortunate to have such a talented and hard working group of executives to support me.

Let me quickly talk about each of their roles and then I will turn it over to Mike Ciskowski to go over our financial results.

Greg King will continue in his role as President, handling all of our financial, legal, and administrative functions for the company.

Mike Ciskowski remains CFO, and I expect he will continue to do the outstanding job that he has done in the past.

Rich Marcogliese is responsible for all of our refineries and, now, our Canadian operations which we operate as a business unit.

Many of you know Gene Edwards well, and he will now head up our strategic planning and corporate development functions.

His experience and knowledge of the market interactions will be key to our strategic development.

Replacing James is Joe Gorder, who formerly headed up on our strategic planning and corporate development group.

Rounding out our leadership team is Mary Rose Brown, who will continue in her role as senior Vice President of Corporate Communications.

Now I would like it turn it over to Mike Ciskowski to walk you through the financial results.

Thanks, Bill.

As we pointed out in the release, our earnings were the highest fourth quarter earnings in the company's history, making it our tenth consecutive quarter of record earnings.

Net income exceeded 1.3 billion or $2.06 per share, which includes a 55 million gain on the sale of our 20% interest in the [Havalina] off-gas processing facility in Corpus Christi.

This gain is reflected in the other income line on the income statement.

If you exclude that gain, net income was still a little bit over 1.3 billion or $2 per share.

For the full year, net income was 3.6 billion or $6.10 per share, which includes the 621 million LIFO charge incurred September 1 when we closed the Premcor transaction.

Excluding that charge and the Havalina gain, full year net income was 4 billion or $6.76 per share.

Overall, refined product margins were strong for the quarter particularly during the month of October.

The average product margins for the quarter are provided in the earnings release tables, and in reviewing those numbers you will also note that the sour crude discounts remained wide in the fourth quarter, which is a trend we expect to continue.

Bill will provide an update on our outlook in a moment.

On the cost side for the fourth quarter, operating costs at the refineries were up primarily due to turnaround activity in the Northeast region and the full quarter effect of the Premcor assets.

G&A expenses were 155 million up 26 million from the third quarter levels, depreciation and amortization was 260 million up 28 million from the third quarter.

Both of these increases are primarily due to a full quarter effect of the Premcor acquisition.

Now, for the quarter, interest expense net of capitalized interest was 75 million.

While the interest expense was up slightly from the third quarter due to the full quarter effect of the Premcor deal, it was lower than expected as we repaid the remaining 800 million balance on the term loan used to purchase Premcor.

In our original economics we had projected that the term loan wouldn't be paid off until the end of '06.

So getting that done in four months is quite an accomplishment.

With respect to our debt position at year end, our total debt stood at 5.4 billion which compares to 4.3 billion at the end of '04.

In 2005 we incurred 3.4 billion of debt due to the Premcor deal.

However, we paid off 2.4 throughout the year.

In addition, we funded 2.6 billion of capital investments for the year, and we purchased 570 million of stock out of cash flow.

At year end our debt to cap ratio was under 25% versus 31% at the end of 2004.

Since this was the first full quarter with the Premcor assets, I thought I would up indicate you on the earnings contribution from this acquisition.

In total, Premcor assets contribute approximately 485 million to operating income in the fourth quarter, and that represented about 23% of our Refining segment operating income.

And that was despite the fact that Port Arthur was shut down for the first two weeks of October and operated at reduced rates for the balance of the month.

Overall we've been very pleased with these assets, we believe it will be more than 20% accretive to this year's earnings, which is well above the 14% accretion we discussed when we announced the acquisition.

Looking ahead to the first quarter, for your modeling purposes you should expect to see the Gulf Coast refinery throughputs of about 1.6 million barrels a day, Mid-Continent around 500,000 barrels a day, West Coast 300,000 and the Northeast system around 600,000 barrels per day.

Total refining operating expenses are expected to be lower than the fourth quarter levels, about $4 per barrel.

We do anticipate the G&A to be around 170 million.

This is an increase of 15 million from the fourth quarter.

The increase is primarily related to IT costs that beginning in 2006 are no longer being allocated to the business segments.

However, in the second quarter, G&A should decrease to around 155 million as the arrangement with Premcor's headquarters employees will have ended.

For the first quarter, depreciation and amortization should be around 275 million, net interest expense should decrease to 55 million and you should be using a 34% tax rate in your model.

I will now turn the call over to Rich Marcogliese to discuss refinery operations during the fourth quarter.

Thank you, Mike.

The biggest event in the quarter operationally was at Port Arthur where we spent most of October getting that plant running again after hurricane Rita.

As you know we sustained significant damage to several cooling towers and had to deal with downed electrical lines and flooding inside the plant.

With the timing of Rita occurring just a few weeks after Valero's take over of the plant, it turned out to be a great opportunity for us to demonstrate the Valero culture in supporting our employees and I believe it actually accelerated the integration of our new leadership team.

We have a first class group of employees at Port Arthur, and they did a tremendous job getting our plant back up in just three weeks.

The rest of our refineries ran hard to supply the market and capitalize on the strong margin environment.

With the front core refineries now in the system, we set a new throughput record of just over 3 million-barrels per day in total.

With respect to turnaround activity, Delaware city conducted a major turnaround from the hydrocracker and coker in the fourth quarter.

Unfortunately these turnarounds took longer than anticipated due to the worst than expected condition of the coker and restart issues on the hydrocracker.

Following these turnarounds, we also shut down the cat cracker for repair of some of the legacy problems on that unit.

We successfully restarted the unit yesterday.

With respect to the coke gas fire operations at Delaware city, we're pleased with the improvements we've made so far.

That unit has been running at around 1100 tons per day of coke, versus 7 to 800 tons per day historically.

We think this is due in large part to the specialized technical and operating expertise that we have brought on board to support our refining operations.

One final note on the Northeast operations, you may have noted in the earnings tables that operating costs in the Northeast were $5.16 per barrel in the fourth quarter.

That was due to the turnaround work at Delaware city.

We expect that number will be back down to about $4 per barrel in the first quarter.

We have a very busy turnaround schedule under way in the first quarter.

At Aruba one of the coker's is down for about 40 days.

The Corpus Christi East plant is down for about three weeks.

Also in the first quarter, Memphis has a 30 day plant wide turnaround.

Krotz Springs will have crude and cat cracker turnaround, and Benicia and McKee will be doing hydrocracker work.

And, finally, Texas City will have turnarounds on two of three crude units.

In the second quarter, Quebec will see its large crude unit, cat cracker and TCR reformer down, and Aruba's other coker will come down along with a crude unit.

Despite the heavy turnaround schedule, we are expecting a great year from operations.

In fact, we're expecting $200 million in incremental income from the strategic capital improvement projects implemented in 2005 and 2006.

Before I turn the call back over to Bill, I would like to point out that 2005 was an outstanding year for Valero's legacy refineries from a safety perspective.

Excluding the Premcor plants, our injury frequency and lost time rates dropped by 20% versus 2004, and 8 of our refineries completed the year without a single lost time injury.

In addition, the St. Charles refinery was recently recognized as a VPP star site by OSHA, which is a tremendous accomplishment given the impact hurricane Katrina had on them.

This brings our total number of VPP star sites to ten, and keep in mind that only 20 refineries in the U.S. have that status.

Now I will turn the call back over to Bill.

Thank you, Rich.

Before we get to your questions, let me mention where margins are currently and where we see them headed.

We are off to a solid start for the year as refined product margins in January have been well above average.

To give you an example, Gulf coast gasoline margins in January averaged 6.75 a barrel and distillate margins were about 7.85 a barrel.

By historical comparisons, that's one of the best January's on record.

The key driver for the good margins certainly hasn't been the weather.

The good margins have been primarily due to strong economic activity in the U.S. and abroad and the anticipated impact of the tightening sulfur specs.

However, at our sweet crude refinery in the upper Midwest, we are seeing typical seasonal margin weakness on the incremental sweet barrel that we process.

Several factors are about to come into place that we think will further tighten our refined product markets throughout the country.

First half of the year is set to see a high level of turnaround activity on both crude units and upgrading units.

We're expecting that roughly 6% of the U.S. refining capacity will be down over the January to April time period.

March alone is expected to have 11% of the cat cracker capacity down which will impact gasoline production.

In addition to the heavy turnarounds, the industry will soon be dealing with the switch to summer grade gasoline in early March, which is made more difficult this year with the tighter gasoline sulfur specs that went into effect January 1st.

At the same time the loss of MTBE from the gasoline pool limits refiners flexibility to blend lower quality components in the gasoline, and you can't make up the entire volume with ethanol because of its high vapor pressure.

Premium gasoline in particular will get harder to make.

In total, we anticipate the removal of MTBE will mean the loss of approximately 145,000 barrels per day of gasoline production that has to be made up somewhere in the system.

Either more finished gasoline or more high cost blend stocks, like [alkalis], will have to be imported.

In either case, high margins are going to be required to attract the supply we need to meet demand.

Looking at light product demand, gasoline demand is up about 1% year-to-date and distillate demand is up about a half a percent.

Another way to look at this is on days of supply basis.

In the U.S., gasoline days of supply stands at 23.9 days, which is very low for this time of year.

Particularly when you consider that imports have been very high.

Days of supply for on-road diesel is also near five-year lows, while off-road diesel is at five-year highs due to the warm January and high imports.

The differences are highlighted in the margins.

On-road diesel margins are about $10.75 per barrel on the Gulf Coast while off-road diesel margins are just under $7.75 per barrel, or about $3 per barrel difference.

We think that spread will stay wide this year as on-road diesel supplies should remain tight relative to the high sulfur off-road diesel.

Remember, the on-road ultra low sulfur diesel spec of 15ppms goes into effect June 1 for refinery.

Discounts for sour crude are also expected to stay wide.

The combination of high margins and the new low sulfur specs have led to increased demand for sweet crude, which are easier to process and have a higher light product deal than sour crudes.

High utilization rates also put more residual fuel oil in the market supporting wider discounts for the heavy sour crude barrel.

So we expect to see mild discounts average in the $16 to $20 per barrel range and Mars, or medium sellers, to average in the $7 to $10 per barrel range.

In closing, let me say that we look forward to working with all the employees at Valero to create additional value for our shareholders.

We have the best work force in the industry and, as many of you know, we were ranked number 3 in this year's listing by Fortune Magazine as the best company to work for.

We had the most geographically diverse refining network and the most conversion capacity in the United States.

With these advantages, we're in a great position not only to continue growing but to also capitalize on this great refining environment.

Now we'll open it up for your questions.

[OPERATOR INSTRUCTIONS].

Your first question comes from the line of [Doug Harrison] with Morgan Stanley.

Congratulations [inaudible] on your record results.

Bill, you talked about a balanced approach to capital management, and I think you used the phrase 'strong shareholder returns' in your opening comments, and on this point if consensus estimates from the ballpark in 2006, then free cash flow for you guys should approach 3 billion which is obviously pretty significant.

And so within this context, I wanted to see if you would provide some specificity on how these funds may be balanced with the new approach that you talked about between capital expenditures, dividend growth and/or reduction of debt and equity that is an updated priority list with the new approach?

Sure, Doug.

What we would do here is Mike is going to just go through a couple of numbers so that we put the right framework on this conversation and then I will comment.

Okay.

Okay, Doug, kind of a back of the envelope free cash flow analysis, first call is roughly 750 to 760.

So that equates to about 5 billion in income, and based on the guidance, DD&A is about 1 1.

So with deferred taxes in there of 3 to 400, about 6.4 of cash from operating activities.

We gave the guidance of 3 4 on the capital.

Earn out is about 100 million, our dividends about 150 is our current plan and then 220 in debt redemption gives you about 2.5 million of free cash flow.

Okay.

We're pretty close there.

Okay.

Then what our plan will be is live to our capital budget, which we have told people is 3.4 to 3.5 billion.

Right.

And then we will maintain our strong balance sheet.

In March we have 220 million of debt that is due, and we intend to pay that off with cash.

Mike is also doing analysis on any of our other debt to see if it is economic for the company to pay off.

Then on top of that we will go ahead and buy stock if the cash is there.

Okay.

That we are diluting ourselves with stock option exercises and benefits, then we have outstanding from 2001 authorization from our board for a stock buy back of 360 million, what's left on a $400 million program.

Okay.

And we would do that.

Then we will see where we are, but we clearly are looking for a very balanced approach here.

Okay.

And that's a good message.

And so just to take it one step further, your balance sheet was 24% debt to cap at the end of the year.

In this scenario, if it materializes, it's going to decline considerably.

If you just retire the debt that's maturing, and so can you give us an update how you think about the correct levels of capitalization for the company in the new environment, and why any new objectives that you may have for the balance sheet at this time?

Yes.

We clearly -- your numbers are right.

We're less than 25%, but when Mike and I visit the rating agency, they add in many other components.

We absolutely are going to maintain our investment grade rating, and we would like to see it improved.

Okay.

So we will work with the agencies and actually we're planning to go see them, and see what their expectations are for us to get some improvement in our rating.

Okay.

Great.

Thanks a lot, guys.

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

Good morning.

I was -- you mentioned the challenges in gasoline coming up with the transition from winter to summer grade.

I was hoping you could go in a little bit more detail.

I think you've talked about MTBE being 145,000 barrels a day, and I think some would argue there may be some loss of some of the lower octane NAFTA in the pool as well, but could you talk about how you see Valero in the industry transitioning from winter to summer while reducing or eliminating MTBE and meeting the tougher sulfur specs?

Sure.

This is Gene Edwards.

Basically we always transition on a vapor pressure basis during 13.5 pounds to around 8 pounds during the month of March.

So really around the middle of March, that's really the same time we've got a lot of turnarounds going on as well.

So -- back out a lot of butane out of the pool.

At the same time, it's going to be harder to bring in higher sulfur components.

Some of the natural gasoline that are above 80ppm are going to be difficult to blend.

A lot of the imports, particularly from Eastern Europe, have been coming in at 150 to 200ppm.

The spec this year for the maximum amount per a gallon basis is 80ppm.

There is a corporate average of 30.

I think you will see a lot of credits used.

The practical number is still going to be 80 compared to 300 last year.

So, could be a lot more difficult to blend these higher sulfur strains.

At the same time, our plan is we can't have MTBE in the pool as of May 5th because that's 270 days after the energy bill was signed.

So, during the month of March is when our plans are to stop blending MTBE ourselves in order to meet Colonial's mandate that they're not ship anything starting mid-April.

Now, basically the rest of the industry, from what I understand, is on a similar time line and we currently blend about 140 to 150,000 barrels a day of MTBE in the United States.

As you know MTBE is about 108 octane, so that's going to reduce the ability to blend in a lot of low octane components like natural gasolines and raffinates.

You can add ethanol back in, but ethanol is really not a net gain because you're really going to be pulling it from the Midwest into the RFG area, so it is really -- there's some ethanol expansion but certainly not 140,000 barrels a day to replace the MTBE.

And also, when you blend the ethanol it's a high vapor pressure so it backs C5 or pentanes out of the pool.

So the net effect is, we think we are going to lose 145,000 barrels a day of gasoline production.

Something else you've to remember, too, is Europe blends a lot of MTBE in their gasoline that's imported into the United States.

They're not going to be able to do that either, or they can but they got to find a buyer on this side of the United States, and no one wants to buy the gasoline that has MTBE.

So that's going to be a further complication because of MTBE.

So, I think a combination of the MTBE phase out, lower sulfur and the seasonal transition RVP, that's going to be a triple whammy come around mid-March for gasoline production and imports.

Where do you see the incremental availability of alternative feed stocks to replace MTBE.

Well, they're not really available in the United States because we're already blending all the alkalit and high octane components that are available.

I think what's going to have to happen is the arbitrage has to work so that you attract cleaner components to other parts of the world.

Europe is about the only place that really has a whole lot of excess capacities components, everyone else has a lot of their gasoline is tough to beat the 80ppm on sulfur, much less the octane and non-oxygenated.

Thanks Gene.

But the arbitrage does work.

Supply will equal demand.

The margin has got to be good enough to attract those barrels.

Thank you, Gene.

Your next question comes from Doug Leggate with Citigroup.

Thank you.

Good morning, guys.

My question is on the OpEx guidance that you provided, Bill, on the call just there.

If I look at the fourth quarter OpEx across the firm it was running I guess around the $3.50 range.

Given that maybe natural gas prices backed off a little bit, that $4 number maybe surprised me a little bit.

Is that essentially the heavy maintenance period, in which case can you back that out and give us what the underlying run rate might be, and I guess just more clarification on that would be great.

Thanks.

Rich Marcogliese is going to answer you.

We anticipate that in the first quarter we're going to see operating costs that are pretty even with the fourth quarter of '05 at around $4.30 a barrel.

We do have a lot of turnaround activity in the Gulf Coast that I mentioned.

This actually offsets the turnaround activity that we saw in the Northeast in the fourth quarter.

We're looking at natural gas prices at around the $8 per million BTU level.

So we are expecting a pretty even quarter on the refining system in total.

That's really helpful.

Just one follow up, if I look at the West Coast OpEx in the fourth quarter it came down quite a bit from Q3.

Can you explain that for me?

Yes, Doug, that was the -- we had a settlement of some litigation issues with some insurance in California that flowed through this quarter [inaudible] about $25 million.

Okay, Rich.

Thanks very much indeed.

You're welcome.

Your next question comes from Nikki Decker with Bear Stearns.

Good morning, gentlemen.

Just on the macro front, we are -- our indicators are showing that perhaps gasoline margins in the Midwest have weakened to beyond levels that would -- to sort of incorporate seasonal effects.

Any insights as to what's happening?

Well, in the Midwest, I don't think we would agree that they've gone more than seasonal.

They did weaken seasonally here and of course they've recovered quite a bit in the last two days.

But I made reference to that in our comments that at our upper Midwest or Lima refinery, because of the very high cost of getting in incremental sweet crude to that refinery, we have actually cut crude charge to the plant.

Now, however, we are drafting intermediates and still running our conversion units, but we did cut crude here going into February.

Okay.

And so would that explain why your mid-con volumes were a little bit below our original guidance?

For the fourth quarter?

Yes.

Well, the McKee turnaround on the cat cracker there, what I believe Rich wanted a little longer.

Yes, that McKee turnaround on the cat ran about 35 days, the [Richmond] plant had it down for 21.

That would be your main.

I was speaking for right now going into February.

What's the utilization rate right now at Lima?

Be about -- about 1 [inaudible].

[Inaudible] you’ve got throughput.

Yes we're going to get it here.

It is about 120 out of 170 past the other crude unit.

A little over 70%.

All right, thanks.

Appreciate it.

Your next question comes from the line of [Paul Sanquin] with Deutsche Bank.

Hi guys, [Sanklin] will do.

The outlook you mentioned very specifically would include growth by acquisition, but you didn't mention that within your prioritization of use of cash flow.

Could you talk a little bit more about your philosophy on acquisitions, perhaps internationally, regionally, what might attract you.

Thanks.

Sure.

The reason, Paul, I didn't talk that much about it is we don't see as many opportunities that were in the past.

It is important to remember that Valero got into the acquisition business here in 1997, and it was much more opportunity.

As we look forward, the opportunities are just left were much bigger, so we do have some areas in the country we would not be able to do acquisition.

Also there is the absolute price in the quality of assets.

We don't see those out there today.

We have publicly stated that we will look at the Come By Chance refinery when the information becomes available, if they'll have us, but otherwise basically we do not see the same level of opportunity that was there.

Now, to your question internationally, we have also looked at Europe.

We've -- and we continue to study Europe.

The assets that have been available have not fit Valero, nor did we feel like the platform was the platform that we could do what we do best, and that is buy assets at low percentages of replacement and then upgrade them.

And we haven't found that type of an asset, and nor are we working on any today.

Great.

That's very helpful.

Thanks.

So we can put acquisitions kind of at the bottom of the list right now in terms of use of cash flow.

Well, you can certainly -- we don't see the opportunity at the moment.

That's for sure.

Great.

That's really helpful.

Thanks very much.

If I could ask you an environment question while I'm on the line, you've been very specific about the outlook for the U.S. refining environment.

Other particular regional imbalances or areas of particular tightness that you see this year just thinking of some of the issues that you've highlighted?

Europe is always a net importer of distillates.

They were for fairly long.

But the recent cold weather they've had is tightening up their situation.

So, we had seen barrels exported from Europe even coming this way which is very rare for this time of year.

But that's pretty much gone now, and Europe is actually importing barrels again.

I think as you move into the second quarter you got a lot of turnarounds in the rest of the world, Asia and Europe, which is going to reduce their distillate supply.

The whole world is probably growing at a higher rate than even the U.S., particularly on the distillate segment.

So I think distillates are going be tight throughout the world going into the balance of the year.

I was thinking sub-regionally within the U.S. as well.

I mean--

Oh.

Do you see any particular areas of tightness to think about?

Well, California is always right on the edge of supply and demand being in balance.

February 1, they went to lower vapor pressure in Los Angeles, and you saw supply-demand tighten up considerably there.

In the Bay Area, as they go to lower vapor pressure March 1, and we got some turnarounds going on there as well, so we're always just one event away from a major spike in the West Coast, as you know, all the time.

So I don't see anything changing from that standpoint.

The rest of the country, I think the Midwest, Gulf Coast, and the East Coast are pretty much in balance with each other as far as the arbitrage is a work on just a small differential.

Thanks very much.

That's extremely helpful.

Thank you.

Your next question comes from the line of Roger Read with Natexis Bleichroeder.

Good morning, gentlemen.

Question is more on the ultra-low sulfur diesel.

I know that is more of a June issue than first quarter issue, but, Gene, can you give us a little idea of, kind of, how that's going to play out, and is there any indication the EPA is going to back away from the 80/20 rule or are they going to stick with that?

We've seen no indication at all they are going to back off that at all.

I think I look at it -- suppose the 80/20 -- how much on-road diesel you can actually sell.

And just looking at our system alone, you get into June and we're going to lose about 100,000 barrels a day of on road diesel sales that we normally would have just on LSD.

By the end of the year, we'll have our Houston and St. Charles plants completing in the early next year, and we'll replace that.

But it's going to be a time frame in there where we'll not be able to make as much ourselves.

The rest of the industry says they're ready, but I think the rest of the industry mainly looks at their own down-stream requirements, and there is not a lot of branded on-road diesel.

A lot of it is un-branded, more than even gasoline.

So I think a lot of people aren't really thinking about that so much, so as the independents try it get supplied I see a very tight market for on-road diesel for the second half of this year.

And what percentage of your diesel today is ultra-low sulfur diesel?

Let me-- how much more conversion do you have between now and June 1 before the rules kick in.

Really, we don't make a lot of ULSD today we make a little bit at Three Rivers that we sell into [inaudible] municipalities.

But there is really no market for ULSD today, other than these little niche markets for clean fuel reasons.

But, so it is a very nominal number right now.

Okay.

Thank you.

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

Hey, guys.

Good morning.

The outstanding remaining residual hedging position [inaudible] all off --

We do not have any forward sales in the market.

Yes, paper.

Okay.

And maybe this is for Gene.

Gene, when we're looking at a lot of people talking about ethanol this day, and that given where the gasoline price is, and also where the [corn] price is, do you guys see that as a economically [inaudible] substitution, that without a government subsidize, or you think that it is still pretty much that we depending and relying on the government subsidy at this point.

You look at ethanol prices today, they're around 2.50 a gallon, and there is to way you could economically blend that into today's gasoline prices without the subsidies.

So, with the subsidy, is $0.52 subsidy, gets it where it is attractive to gasoline.

I think that over time though, as ethanol plants are being expanded rapidly throughout the U.S. so in a number of years they will over expand and the prices won't stay as this high of a level.

Is there a gas -- based on today's [inaudible] gasoline price, do you need 2.50 because I think they're selling at 2.50 that I know, but they probably have making for a decent profit--.

They're making a real good profit.

In the $0.30, $0.40 right now, right?

Right.

My understanding is the cost of producing the ethanol for a marginal-type plant's around $1.20, $1.30 a gallon.

Some people can make it cheaper if they get valuable by-products out of the process, so at 2.50 a gallon, they're making quite a bit of money.

So in other words, that if gasoline prices at $2, they maybe reliable substitution already.

Right.

And maybe this is for Bill and Mike.

Is there-- I think in the past that there was some discussion saying the rating agency won't allow you guys to adopt a bigger or more aggressive share buy-back program, is that still the restriction there?

No, I don't think that's a restriction.

What we would like to do, Paul, is get-- have a good meeting with the rating agencies and have a discussion and let them look at our balance sheet now since we have the year end financials coming out, and see if we can get an improvement in our rating.

Okay.

Bill or Mike, when we looking at your capital budget of 3.4, $3.5 billion for this year, is that including the 300 or 400 million in the turnaround and the capital spending?

Yes, it does.

It does, right.

Yes.

And, I presume that the 2.6 billion that you mentioned for the full year 2005 is also including that?

Yes.

Okay.

Finally, Mike, is there any early debt retirement opportunities that result paying a big premium in the near term, say over the next 12 to 18 months, and also that what is the absolute debt level that you guys will be comfortable at?

Okay.

We're still analyzing that over the next twelve to 18 months probably there are some Premcor debt that is callable at a lower number, and that's part of our analysis to whether we should wait 'til then or do it now with this excess cash flow.

As Bill said, we're going to be meeting with the agencies and we have made a lot of progress on our financial position, but we will continue to work with them and try to achieve some improvement in our ratings.

Okay.

Very good.

Thank you.

Your next question is from the line of Jacques Rousseau with FBR.

Great quarter, gentlemen.

Most of my questions have been answered.

Just wanted to see if you could quantify the cost and opportunity loss from the hurricane in the fourth quarter.

Yes.

The total hurricane loss of the two hurricanes, Katrina and Rita, is around the $300 million level.

For the fourth quarter and specific to Port Arthur, it's about 230 million.

And that was the expense and the opportunity loss?

That's the 234 Port Arthur was just the opportunity loss.

There was also some expense of about 45 to 50 million.

Okay.

And a second separate question, have you guys done any study to estimate at what level of a retail gasoline price demand starts to come down in the United States?

Well, no.

I guess the answer is we haven't done any study.

I don't mind telling you, after the hurricane when prices shot up over $3, and we had unavailability of supply, so it is hard to say if it was price, there wasn't gasoline at some stations, and also our President asked people not to drive.

We clearly in our market saw a drop in demand.

However, as soon as that crisis ended, prices fell back down into the $2.50 retail.

We saw demand come roaring back and for our own system in the first three to four weeks of the year here, our actual volumes are up over last year on less stores.

But to answer your specific question, we haven't done any -- we haven't done any study.

Okay.

Thank you.

Your next question comes from Jennifer Rowland with JPMorgan.

Thanks.

I have a question on your strategic projects.

I think you mentioned the income you expect in '06 incrementally is 200 million.

I think last quarter you said 280, if I am correct.

So, I am just wondering if timing of some of the projects has shifted, or what would cause that number to change.

And then also if you could comment on your plans for the Lima refinery now that you're not pursuing the joint venture with EnCana.

Okay, this is Rich Marcogliese.

I will comment on that.

Yes, our incremental income contribution for projects has changed.

It is lower as you observed, and I think what we are generally seeing is slippage of strategic projects related to the tight construction labor market and the market for major equipment for refineries.

For example, on our ultra low sulfur diesel investments, we have two mild hydrocracker projects we're installing, one in Houston and one in St. Charles.

We've seen slippage of about three months in each, and my sense is that it's a general industry situation that we are dealing with.

In addition, we've also seen a little bit of slippage in our project execution on Aruba.

It is a little bit more difficult to support construction on Aruba given its distance in some of the import issues for labor on the island and for example our vis breaker project we anticipated it would be up at this time.

It will be up actually mid-February.

For Lima we are going to continue to improve the refinery.

We have a turnaround there on the cat cracker here in the third quarter, and we're going to install a new feed nozzle in that cat cracker which will improve its yield.

We're also using some of our other successes at our other plants to go ahead and prove the operation.

For the next five years, our capital budget our strategic plan for the refinery, which includes turnarounds and catalysts, but also improvements in the entire operation, is over $400 million.

But our basic strategy is to continue to run that refinery as a sweet crude refinery in the upper Midwest.

Okay.

That's very helpful.

And just one other quick one.

You've provided the run rates for the first quarter, wonder if you give guidance for what you're expecting for the whole year, by region.

Yes, we can do that.

The Gulf Coast should be 16 to 17, the West Coast right around the 300,000 barrels a day, Mid-Continent I'd say around 550, and the Northeast, I'd say 550 to 575.

Just a little over 3 million barrels a day, 3 to 3.1 is what our plan is.

Okay, great.

Thank you.

[OPERATOR INSTRUCTIONS].

And we now go to the line of Chi Chow with Petrie Parkman.

Thanks.

Hey, Bill, you're asked a lot about acquisitions on every call.

But, what are your thoughts regarding asset divestitures.

You sold the plant here in Denver.

Are there any other assets you feel under performing or that you believe you can redeploy the capital elsewhere.

We do not have any asset divestitures planned.

We are going to make a major effort here to improve our competitiveness like I said.

Okay.

And how are you feeling about the current cost structure of the company.

Is that related to the improvements you're talking about here?

Well, we are very efficient, we have very good skills, technical skills.

But we have opportunity, as we look down the road, to try to make sure that we are competitive in an environment that, maybe it's 5, maybe it's 10 years, that we can compete.

So, all of the management team here, the leadership team here, is looking into their organization to make sure that we are working on maximizing profitability.

Okay.

Great.

Thanks, Bill.

Your next question comes from [Gary Willhull] with MPV, I am sorry, NPV Consulting.

Good morning, gentlemen.

I was wondering if, similar to what you did in the last quarterly call when you told us what October 2005 earnings were, if you could tell us what you're seeing in January 2006 this month in terms of earnings for operating income.

Well, it is very early in the quarter and--

Well, just for the month.

I know.

I know what you asked.

But it's, what we decided is it is very early in the quarter, all pricing is extremely volatile, and I mentioned that on I think it was Monday prices in the Midwest, our [cracks], moved a dollar a barrel.

We had the RVP transition, we have MTBE elimination, sulfur specs, we have turnarounds going on.

Right now we just think it is too early in the quarter to be talking about the earnings.

Okay.

My second and final question is, I am trying to get my hands around how accretive the Premcor acquisition is, and when I look at what you told us in September, that Premcor contributed $330 million of operating income but in the fourth quarter 485 million, just trying to figure out, maybe, what the monthly profile of that would have been in the fourth quarter, or maybe, can you give us a sense of what the normalized income is, for operating income is, for Premcor.

I don't have those monthly -- that monthly information here with me.

I can get that, and you can call Eric.

Eric will have that.

Okay.

That's it.

Thank you.

Your next question comes from Daniel Burke with Johnson Rice.

Morning, gentlemen.

Actually had a follow up question.

You mentioned the higher accretion associated with the Premcor acquisition.

Wanted to clarify if that was due to effective lower net interest expense, change in your forward strip forecast, or if it was actually because you're seeing better underlying operating performance from the Premcor assets.

Part of it is due to the lower interest expense obviously.

But the-- part of it is just -- there is not that much difference between the price calls, if you will, and I think it is just better performance than what we expected from the refineries.

Okay.

I understand.

And then just one follow up, or one other question.

I was wondering if, particularly in light of the decision not to move forward with the Lima project, if you're at all interested or believe there would be any opportunities to participate in projects to bring some of these heavy Canadian crudes down to the U.S.

Gulf Coast over the next couple years.

Well, we're very interested in processing heavy Canadian crude oil, so Exxon has brought some Canadian crude down to Port Arthur and Beaumont, and we actually purchased some Cold Lake from them and ran it at Port Arthur here.

But-- we're very interested.

Now, as to these projects, if it was the right economic transaction, of course we're interested.

But we're not working on one today.

Okay.

Thank you.

Your next question comes from Mark Gilman with Benchmark.

Guys, good morning.

I had a couple specific things.

Mike, what were the hedge losses in the fourth quarter, please.

$160.

I am sorry could you repeat that.

160 million.

160.

On the heat crack.

Okay.

I think Eric mentioned this settlement with respect to the West Coast, $25 million.

Is that after tax.

That's pre-tax.

Okay.

Well, our analysis says that there's a lot more going on there in terms of variance versus historical performance than just $25 million.

Anything else of an operational nature changed dramatically in the fourth quarter on the West Coast.

I would just say our two refineries, Wilmington and Benicia, had very good operations, and as a matter of fact had good operations all last year.

Well, Rich, the fourth quarter is really a stand out both in terms of unit costs as well as variance versus indicator margin, by way more than $25 million pre-tax by our analysis.

The only other thing I can say for Benicia, there has been an effort under way to reduce our dependence on A and S crude.

Now, we still run a lot of A and S crude in Benicia but we've worked with commercial group to try to get more of the heavily discounted crude into Benicia.

Okay.

Mike, it looks to me as if some adjustments were made in the purchase accounting in the fourth quarter, as the overall DD&A and the refining DD&A in particular looks lower than probably it should have otherwise been by something in the neighborhood of 50, $60 million.

Can you comment on that?

Well, we're still finalizing the appraisal.

There were some small changes to the PP&E allocation, but nothing that would have led to that much change in depreciation.

Well, I mean, you can't get from your third quarter number which included one month of Premcor, to the fourth quarter, which included three months including an uplift.

You're falling way short.

Okay.

If you do that math.

The DD&A effect was for Premcor, from the third quarter '05 to the fourth quarter '05, was about $36 million, and the increase for the quarter was 28.

Okay.

Maybe we'll take it off line.

One more if I could, please.

When does the Port Arthur expansion come on.

It's going to come on October of this year.

That is another example of where construction progress is slower than we anticipated.

Initial indications were that would be more of a mid-year type project, but our current assessment is October.

And that's both the coker as well as the crude unit, Rich.

Well, it's really the crude unit.

The coker has been expanded.

The expansion capacity is about 105,000 barrels a day, we've been able to run it upwards of 100,000 so far.

So we've really gotten a big piece ought of the coker, but the next crude increment of the 75,000, that will be later in the fall.

Okay.

Thanks a lot.

[OPERATOR INSTRUCTIONS].

Mr. Fisher, there are no further questions at this time.

Are there any closing remarks?

No.

Thank you, operator and if anyone has follow up questions, feel free to give me a call.

Thanks very much.

Ladies and gentlemen, we do appreciate your joining us today.

This does conclude our Valero Energy fourth quarter 2005 earnings conference call.

You may now disconnect.