瓦萊羅能源 (VLO) 2006 Q3 法說會逐字稿

At this time I would like to welcome everyone to the Valero Energy third-quarter 2006 earnings release conference call. [OPERATOR INSTRUCTIONS.] Thank you. I would now like to turn the conference over to Eric Fisher, the Vice President of Investor Relations. Please go ahead, sir.

Thank you, good morning, and welcome to Valero Energy Corporation's third quarter 2006 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, Joe Gorder, head of Marketing and Supply, and other members of our senior management team. If you've not received an 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 these tables, please feel free to contact me after the call.

Before I turn it over to Mike Ciskowski to go through our financial results, I would like to direct your attention to the forward-looking statement disclaimer contained in the release. In summary, it says that statements in the press release and on this conference call that state the Company's or management's expectations or predictions of the future are forward-looking statements intended to be covered by the safe harbor provisions under federal securities laws. There are many factors which could cause our actual results to differ from our expectations, including those we've described in our filings with the SEC. Now I'll turn the call over to Mike.

Thanks, Eric. Thank you for joining us today for our third-quarter conference call. As you saw in the release, our third-quarter earnings came in at $2.55 per share, or $2.42 per share excluding the $132 million pretax gain, or $0.13 per share after-tax gain on the sale of our 41% of our ownership interest in Valero GP Holdings, LLC.

Net proceeds from that IPO were approximately $355 million. Overall, this was the best third quarter in our history, even surpassing last year's third quarter, which was affected by the hurricane. Higher throughput due to the Premcor acquisition was the key driver for the better third-quarter results compared to the third quarter of last year.

We also had strong contributions from our wholesale business which generated $80 million in operating income, and also US retail, which added $80 million in operating income. Margin realizations were also much improved in the third quarter compared to the second quarter due to continued wide sour crude discounts, more reliable refining operations, and strong wholesale marketing margins. As a percentage of a hypothetical 532 product margins weighted by refining region, our actual margin realization increased from 82% in the second quarter to 97% in the third quarter.

On the cost side, third-quarter cash operating costs at the refineries were down slightly from the second quarter. This was primarily due to better plant reliability and lower energy costs. General and administrative expenses dropped significantly to $136 million. The decrease of $35 million from the second quarter was primarily due to a $12 million decrease in variable compensation expense, $11 million decrease in charitable expenses due to funding our foundation in the second quarter, and lower regulatory and legal expenses.

Total depreciation and amortization was $294 million, which was flat with the second quarter. Interest expense net of capitalized interest was also unchanged at $46 million versus the second quarter. Our effective tax rate was 34.3% for the third quarter, and 33.6% on a year-to-date basis.

Now with respect to our debt position, at the end of September, our total debt stood at $5.1 billion, which compares to $5.4 billion at the end of 2005. We finished the quarter with a debt-to-cap ratio of 18.9% versus 24.8% at the end of '05. Capital and turnaround expenditures year-to-date are at $2.8 billion, and we continue to expect to be around $3.7 billion for the year.

As for our stock buyback program year-to-date through October, we have purchased 33 million shares of our common stock for a total cost of $1.9 billion, of which 10 million shares were purchased in the third quarter, and two million shares were purchased in October. As we announced last week, our Board approved a $2 billion stock purchase program. Going forward, we intend to utilize this new program, as well as continue to purchase shares in the open market to offset dilution created by our employees' stock incentive programs.

Now looking ahead to the fourth quarter, turnaround activity is moderate. Rich will discuss that in more detail here in a moment, but the main activity in the fourth quarter is at our Houston and St. Charles refineries. Those turnarounds have reduced crude throughput by an average of 275,000 barrels per day in October, and reduced gasoline production by 80,000 barrels per day, and total distillate production by 60,000 barrels per day. So for your modeling purposes, you should expect to see Gulf Coast refinery throughputs of approximately 1.5 million to 1.55 million barrels per day in the fourth quarter, Mid-continent throughputs should be around 555,000 barrels per day, West Coast at 300,000, and the Northeast system around 570,000 barrels per day.

Total refinery operating expenses are expected to be near the third-quarter levels at about $4.45 per barrel, and with respect to some of the other items for the quarter, we anticipate general and administrative expense to be around $150 million, net interest expense about $48 million, and depreciation and amortization around $300 million. And then finally going forward, you should be using a 34.75% tax rate for your modeling purposes.

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

Okay, thank you, Mike. Operationally, we had better refinery performance this quarter than we had earlier in the year. We were able to correct several equipment reliability issues, and we were absent any major, unplanned events as we saw in the second quarter.

There was much activity in starting up new equipment to satisfy regulatory requirements. We successfully commissioned a new gasoline desulfurization unit in Krotz Springs to meet Tier II gasoline requirements, a flue gas scrubber in Delaware City to meet state air quality requirements, and a new sulfur recovery unit in Port Arthur related to our planned crude unit expansion.

Similar activities are continuing this quarter with a new distillate hydrotreater having already been commissioned in Memphis, and new hydrotreaters now in the startup phase in Ardmore and Port Arthur related to ultralow sulfur diesel. Late in the year, we also expect to bring online our Port Arthur crude unit expansion, which will raise our crude capacity to 325,000 barrels per day. Our primary plant maintenance events in the quarter were the major turnarounds at Aruba and Lima.

This included reliability upgrades on Aruba's crude units, and the completion of our coker expansion project. We have now increased coking capacity from 66,000 to 76,000 barrels a day on Aruba, and increased crude throughput to over 270,000 barrels a day, the highest we've experienced since taking over the refinery 2 1/2 years ago. In Lima, we completed a replacement of the cat cracker reactor to increase yields and efficiency. Unit performance there has improved as expected.

Currently, we have the Houston refinery down for a plant-wide turnaround that should finish by late November. This turnaround includes final equipment modifications for Tier II gasoline, reliability upgrades to the cat cracker regenerator and power recovery turbine, the commissioning of the new sulfur recovery unit, and the startup of the new flue gas scrubber to reduce cat cracker air emissions.

This will complete our major turnaround activity for the year. You may have also seen that we have filed for a permit for expansion work at the St. Charles refinery. As you know, we view St. Charles as one of the major internal growth platforms within our refining system. This was a preliminary step to get required permitting in place before we would commit to major funding for engineering on this project.

We are evaluating the addition of the new gas-oil hydrocracker to process excess sour (indiscernible) currently produced at the refinery and exports. This new unit would primarily convert sour gas oil to ultralow sulfur diesel. We believe the global demand for diesel is going to grow more rapidly than gasoline, and this expansion would capitalize on that trend.

However, I should emphasize that this project has not been approved by our Board, and even if approved, it's not likely to be online until late 2009. Now I'll turn things over to Joe Gorder for an overview of industry fundamentals.

Thanks, Rich. Beginning with the gasoline market, it's an understatement to say that gasoline margins were volatile in the third quarter. For the entire month of July and into early August, Gulf Coast conventional gasoline margins averaged around $20 per barrel, extending the strong performance we saw in the second quarter. But in the second week of August, gasoline margins began to fall sharply, eventually finding a bottom around breakeven in early September.

We believe there were several factors that contributed to the sharp drop in margins. First, we observed the impact that financial markets can play as the Goldman Sachs Commodity Index announced in early August that they would reallocate the majority of their portfolio attributable to the RFG contract to other commodities, and not to the RBOB Gasoline contract. Although it's hard to measure the direct impact this reallocation had on the RFG contract, the announcement itself triggered the hurry to sell, putting tremendous pressure on spot gasoline and margins.

In addition, we had weak gasoline fundamentals. Higher-than-normal imports contributed to support high inventory levels as the summer driving season approached its traditional Labor Day close. On top of that, we witnessed an easing of geo-political tensions that took a fair bit of the hype out of the energy market in general. Despite these factors, the average Gulf Coast gasoline margin for the quarter was very strong, around $12 per barrel.

In October, gasoline fundamentals improved substantially. In fact, the last two weeks' DOE gasoline inventory stats have shown an 8 million barrel draw in gasoline supplies, reflecting the impact of reduced production and imports, resulting from extensive refinery maintenance in western Europe and North America, combined with good demand. At these inventory levels, inventories on a Days-of-Supply basis are below normal for this time of the year, and very close to where they were at this time last year.

In spite of falling pump prices, October Gulf Coast conventional gasoline margins averaged $4.45 per barrel, which is very good for this time of the year. With respect to distillates, third quarter margins were great. Gulf Coast off-road diesel and heating oil margins averaged around $9 per barrel, nearly double the five-year average of $4.60 per barrel. Even more impressive was that Gulf Coast on-road diesel margins averaged almost $17 per barrel.

Historically, the spread between on and off-road diesel is only a few pennies a gallon, but with the onset of ULSD is widened considerably, and it is important to keep an eye on. In general, the transition to ULSD has gone smoothly. We did see significant inventory builds of distillate in September, and believe this reflects, in part, the pre-stocking of ULSD at terminals to facilitate the transition at the retail level before the October 15th deadline. In October diesel demand, like gasoline demand, has been strong, and Gulf Coast on-road diesel margins were $13 per barrel.

Looking at the forward curve for the fourth quarter shows Gulf Coast on-road diesel margins continuing to be about $13 per barrel. As with the gasoline market, we saw tremendous volatility in the crude oil markets, as WTI prices dropped sharply during the quarter from $78 per barrel down to the upper 50's in a matter of weeks. From our standpoint, what was important was that despite the steep drop in the benchmark price, the discounts remained wide.

Discounts for medium sour crude oil such as Mars averaged $7.50 per barrel in the third quarter, and continued to price in that range, while heavy sour Maya discounts averaged $15 per barrel. Currently, there are ample supplies of medium and heavy sour crudes available in the market, so we don't expect the recently announced OPEC production cuts to have a material impact on sour crude discounts. We believe the industry will adjust quickly as it did when ANS barrels came off the market earlier in the quarter.

We also have our discounts at medium sour crudes from Saudi Arabia locked in for November deliveries at levels which are slightly better than October levels. As to heavy sour grades, Maya is currently priced around $13 per barrel under WTI, which is down a bit from the third quarter. We think discounts for Maya will widen later in the year for several reasons. First, as inventory maintenance ends, more residual fuel oil will come to market, putting downward pressure on resid prices. As you know, residual fuel oil is 40 % of the Maya pricing formula.

Second, at current prices, Maya is relatively expensive compared to similar heavy sour grades, which are pricing around $3 to $4 per barrel less than Maya. So that gap should narrow to make Maya more price competitive.

Third, we continue to find good alternative heavy sour crudes for both South America and Canada that are financially attractive substitutes for Maya. So going forward, with ample supplies of medium and heavy sour oils that we can find at competitive discount prices, Valero's complex refining system should be able to keep generating strong profits as compared to refineries that process light sweet crudes. And with that, I'll turn it over to Greg.

Thanks, Joe. Based on Joe's comments, we expect to finish 2006 with another quarter of very good earnings to cap off what will be another record year for Valero. Before we open it up to Q&A, I'd like to make a few comments on our outlook for 2007. We just completed our strategic plan review. And a part of that process is to take an in-depth look at the market going forward. Looking specifically at next year, we see a continuation of the same positive factors that have made 2006 such a great year.

First and foremost, you have to look at our business globally. And global refined product supplies have not grown fast enough in 2006 to exceed demand growth. So we expect the market will remain tight next year. The market will continue to fluctuate seasonally as we've seen this year, but it is still tight. And looking at projects around the world, there aren't enough major capacity expansions coming online in 2007 to meaningfully ease the tightness in refineries.

Demand, though, is obviously the key. The world economy continues to look strong for next year, particularly in the developing world. Most consultants are calling for 1.5% to 2% global demand growth in 2007. Group prices look to be lower next year as compared to this year, and that's also good for demand and the global economy. The industry is having a hard time keeping up with diesel demand, particularly for low sulfur grades. Basically, the U.S. and Europe are competing for the incremental barrel of low sulfur diesel, and that's keeping these margins wide.

Looking at the forward curve for next year, on-road diesel is selling at over $13 a barrel in the Gulf Coast. If those numbers held, it would be a record year for on-road diesel margins. And even though the forward curve for gasoline is not as liquid, it's also pointing to a very strong year in 2007. For example, Gulf Coast conventional margins are already trading over $9 a barrel for next summer.

So in closing, I'd like to reiterate that we are very bullish about our future, and that you should continue to see the tremendous earnings power of our assets in this environment of tight refining capacities, strong refine product demands, and favorable discounts for low-quality feedstocks. Our stock is the best value in the refining sector, especially when you consider the current valuations for refining assets. Going forward, you can expect that we will continue to increase shareholder value by optimizing our existing portfolio of assets, seeking out accretive growth opportunities, and actively buying back out stock. And with that, we'll open it up to Q-and-A.

[OPERATOR INSTRUCTIONS.] Your first question comes from Doug Terreson from Morgan Stanley.

Good morning, guys. Several of the integrated oil companies mentioned last week that due to some of the cost issues in the downstreams that they were in the process of reassessing their CAPEX plan in refining, and the likely outcome obviously is that project deferrals will be meaningful and that spending will be lower than they previously thought for '07 and maybe '08. And so my question is whether or not a similar message is present in your capital budgeting meetings, and whether or not a similar outcome is likely in your situation, and why or why not?

Well, we've gone ahead and announced that our capital budget for next year is going to be about $3.5 billion.

Okay.

But there is no question that costs have increased. We've seen costs increase at least on the Gulf Coast anywhere from 20% to 30%. But the bigger issue has even been -- and Rich Marcogliese can give more detail here -- is productivity. We've had a real fall in contractor productivity primarily because there is such a demand for people -- for people here, that people are coming into the work force that are not as productive as others. So that is affecting -- and that then affects the timing of projects and also causes our overhead and everything else to increase.

Now, having said that, there's still projects we're finishing. We're finishing some of our ULSD projects have to get done. We also have some strategic capital that has returns, energy projects we've told you in the past that are over 20% IRR's, and other type work in refineries that are over 30%. Very good projects for us, and that have been in the queue here as we finished all of the Tier II spending.

So this year, you have seen it. We told you earlier in the year that we were going to be at 3.5 and now we're at 3.7. We will be in the 3.7 range. There is some tax advantages for us to finish some projects at December 31, which we intend to try and do. But we try to account for this as we've looked at our 2007 budget on these productivity and cost numbers that I mentioned.

Okay. Okay. Let me ask you another question. Were trading gains significant in the third quarter, and also if you have any numbers for full year trading gains or results, that would be appreciated, too.

Some trading gains, you're talking about paper?

Sure.

No. We don't have anything of significance.

Okay.

Any of the trading we're doing is we're in the market, we do do paper, as you know, in certain situations. But it's all basically hedging and insignificant.

Okay. Great. Thanks a lot.

Your next question is from Paul Sankey from Deutsche Bank.

Hi, guys. Good morning. I had two for you. The first one was the announcements on the buyback. Can you just give us an idea on the timing that you intend to progress that program, and whether we should consider the past course to be a good indicator as to the speed that you'll undertake it. Thanks.

We're maintaining quite a bit of flexibility on this program, Paul. But what we said earlier in the year, we were going to do this 5%, and we're very close to that now. That 33 million shares. So our plan is to get to -- and we've done a lot of different calulations, but our number is approximately 35 million shares for this year. And we will complete that program.

We also have some significant cash requirements here in the fourth quarter. We're going to make a contribution to our pension plan. We also have a significant tax payment that's due in December. So as we look at those cash expenditures here, this will be pushed into next year as we look at the buyback program. And then what we have desired to do is this balanced approach that I've talked about, and we'll have a rateable-type program as we go forward into future years.

Okay. So you're saying that the upcoming Q4 is -- is a very onerous one from a cash use point of view, that you wouldn't expect to see repeated?

We've not -- would not expect us to do a lot more than what I just said here in the fourth quarter.

Okay. And so then the 2 billion will kick in for next year. The new -- the new program, that is. And secondly, you have said -- you seem to be hinting quite strongly at disposals. Can you talk a little bit more about whether or not you're working toward a targeted level of disposals or -- or just any more commentary that you could give on disposals would be interesting. Thanks.

Well, we clearly know that we have a portfolio of assets. And from retail assets to refining assets. You have seen us sell and continue to sell some retail assets. And those are minor. Just here in October we sold our Mt. Bellview assets, which is small, but we have continued to do that. Earlier in the year we exited the ammonia fertilizer business. It not so much in taking proceeds there, but we did avoid a capital expenditure that was going to be required to maintain our ammonia plants.

Also, we are continuing and have stated that we're going to sell our interest in DLC or BEH, and our plan is to continue to push that forward, with a desire to complete that before the end of the year or early next year. We do look at all the refineries, as Greg mentioned in his comments. We have completed our strategic plan, review with our Board. And as we go forward here, we will look at all of our refining assets to be sure that they are contributing. And as I've said, we have demonstrated the willingness here to dispose of assets.

That's great. Thank you. I'll leave it there, thanks.

Your next question will come from Neil McMahon from Bernstein.

Hi, good morning. I've got a few questions. The first is it's interesting about your comments on the gasoline market in August and September. Particularly around the influence of the financial markets and the Goldman Sachs commodity index. Just looking at the current Contango and the market, we've got $6 if you look out six months in terms of the crude market, $8.25 if you look out 12 months.

Are you concerned about the impacts of further financial market activity on refining markets as we go forward, given the influence that ETFs and commodity funds are having in the marketplace today, and has that led you to change any of your strategies around how you play your own storied situation or, indeed, how you think about trading within your own portfolio?

Well, I'll start. I mean, we did see mid to late August the tremendous exiting by the funds from the -- the gasoline marketplace. And Goldman Sachs was part of it. But we believe that based on looking at the Commitment of Traders report that they weren't alone. I think their announcement triggered a significant exodus at that point in time. And really what that did is it intensified the severity of the drop in the markets. And -- and so I don't think that we're going to see that.

The funds are still in the markets, but they're not in, I don't believe, to the extent that they were in at that point in time. So going forward when we look at what the -- what might the impact be, well, we're not absolutely sure. But it will probably be choppy. It will probably be in and out and try to take advantage of it and play it as we have in the past.

I think I would -- this is Klesse. Clearly the commodity funds, all the paper investments, is the major part of our business today. It is our business. You have to be involved in all of these markets. Their activity, in my opinion, increases volatility. It's very visible. We see a lot of volatility. And thus, we do try to manage our volatility even more effectively than we have in the past. The question dealing with Contango, yes, we have a very strong Contango market which tells you that you should be storing whatever components and there's enough carry there to do this.

So clearly, it is to your benefit to store crudes, gasoline, and distillate here in this market. However, and you can tell much of the storage is full. It's hard to get permits on storage. And quite frankly, there's a lot of maintenance in storage tanks that takes time. So your observation is correct. It does cause us to look very, very seriously at these markets. And yes, they're clearly in carry.

Just given the absolute scale of your storage activities, it would seem like going forward if things were in your favor in terms of holding costs, given your storage position in any case, to play a certain component of this Contango market given we've rarely seen it as strong as this going out six months and getting $6 on crude. Is this going to be part of the strategy going forward over the next six months?

Well, we have built distillate inventory for the winter like people -- you would expect us to do. The market's in carry. But frankly, you don't have the tankage. So you don't have tankage that is just sitting there idle. And when you have -- Doug Terreson asked us earlier about our capital budget. You look at your capital budget in project work or tankage work.

And you have to say do I want to be building tanks that have to have heels and spend our money that way, or are we better off doing some of the energy work and project work within the refinery? So longer term, there's not a desire to build a lot of tankage, and shorter term, your observation is correct, but you tend to be full.

Okay. Just one very quick last one. It looks like from the guidance you gave for third quarter, your third-quarter crude runs in the Gulf Coast, and the levels that you've come in at look like you reduced utilization right toward the end of the quarter in the Gulf Coast. When the rest of the industry, to be honest took a long time to reduce utilization nearly waiting, well pretty much waiting until October. Is that what you were doing in the Gulf Coast, basically seeing your marginal configuration go to zero or negative, and then reducing runs?

I'm not sure I understand. Let me try and answer you this way. And then we'll try again here. But we buy crude oil so far out, we have crude oil coming to us. For instance, we bought all our November crude. Now we have price risk managed, but we have bought all our November crude oil.

So when the market collapses in August, you already have the crude. So our ability to make these turns on the dime are, just like anybody in this business, isn't that easy. You either have to sell crude, and in most cases, since your previous question on Contango, crude storage is full, the ability to sell crude and not get skinned is not good. So what we tend to do is run out and plan our business for the next month.

Okay. It was -- just purely on a guidance basis. And then the actual numbers you reported. But that's great. Thanks for my questions being answered.

Well, you should call Aaron after the call. He can give you the exact numbers, okay?

Great. Thank you.

Your next question is from Jennifer Rowland with JP Morgan.

Thanks. My first question is in regard to the Port Arthur expansion. Can you give a sense of where that project stands as far as how far along completion it is, and if that's going to be on line in November, or is that more of a December timeframe?

Sure. This is Rich Marcogliese. We continue to be challenged by labor availability on that project. But it appears that we will complete construction by the middle of December and have the unit online just before the end of the year.

Okay. And then just another one. On the east coast, it looks like your gross margins held up remarkably well in light of what the benchmark craft did in the east coast. Is that solely related to what you were talking about with the ULC margins, or is there something else happening there in the quarter?

Jennifer, we did have ULSD production in Quebec online for the whole third quarter that clearly held. We also had great [lead] margins at Paulsboro, the best we've seen. Keep in mind, if you're looking back at the second quarter, we did have Paulsboro and Quebec in turnaround during the second quarter. So they really underperformed distinctly in the second quarter. So definitely much, much better quarter in the third for the Northeast.

Okay, great. Thank you.

Your next question is from Jeff Dietert with Simmons.

Good morning. This is a bit of a follow-on question. But if you were just to use your linear programming models to run your business, you would maximize throughput at -- at current margins, even to the extent that you were building inventories because margins are positive, and we've got a carry market. Is -- are you running your business purely based on linear programming models, or are there qualitative factors that are contributing to decisions on how much crude to run through your -- your refineries?

I'll go ahead and answer that. This is Rich Marcogliese again. We develop monthly operating programs. We do that on the basis of price forecasts that our industry analysis group puts together. We combine that with access to raw materials that our supply group is going to get for us, and we run it through our linear program, which are actually very complicated models that model our individual refineries very accurately.

And we developed an optimum case for raw materials and throughput to meet our identified marketing demand. That doesn't always result in a maximum throughput level, but it results in a throughput level that represents the optimum around profitability.

Do your inventories or industry inventories influence decisions on how much to run?

What I would say is our assessment of industry inventories is all ground into what we think our price forecast will be for the coming month. And then the price forecast in turn is put into the model, and we run our economic cases.

Very good. Thanks for your answers.

[OPERATOR INSTRUCTIONS.] The next question will come from Anne Kohler with Caris & Company.

Good morning, gentlemen. If you could just provide some color regarding your view of the sulfur credit market for gasoline as some of the easy credits expire at the end of this year, and then the new credits, or I guess the vintage credits for next year, how you would see that impacting the gasoline import market for 2007.

Okay. We're -- this is Gene Edwards. We're still in a period right now where we can use early credits which were generated by us producing gasoline with lower sulfur than what the current standard is. So there was, obviously, [inaudible] people that converted earlier to generate lots of credit. All credits expire at the end of this year.

Next year we go to vintage credits, which the only way to generate those is by producing gasoline below the current spec which is only 30 ppm. It's much more difficult to generate those. In fact, our plan is to go a little bit up above the 30 next year and actually consume credits. And so we won't have any to sell. And I think a lot of the imported gasoline that comes in is above 30 ppm this year. They're using early credits to be able to blend down to the 30.

With the lack of vintage credits next year, tighter markets, there is some question about some of the blends that came into the markets this year whether they'll be able to stay in next year. So we think that the gasoline that does come in next year is probably going to have to be cleaner, on average, than it's been this year because of this reason.

Do you have any estimate as to how from a volume standpoint of view the market could be impacted next year?

No, not really. You just look at the imports, and Europe's pretty much making low sulfur gasoline. A lot of Eastern Europe is above the spec, and there's been a lot of imports this year. It's just a matter of how they rejuggle their own gas and blending to see if they can meet a 30 ppm spec or not, or find somebody that can sell them credits or not. Right now, it's a fairly tight market on credits, though.

Thank you very much.

Your next question will come from Gary Wilhelm with NPV Consulting.

Good morning. My first question is about how much operating income was foregone in the current quarter due to planned downtime, and then how much from unplanned downtime.

Okay. From a planned downtime point of view, we had turnaround impacts of roughly $90 million. On the unplanned piece of the business, our stewardship of what was in the plan versus what the refineries actually ran was about $130 million impact.

So $130 million for unplanned in the third quarter?

That's correct.

Okay. And looking to the current quarter, for the fourth quarter, based on what you see right now, what kind of operating income impact would you see from a -- from the downtime that you see in the fourth quarter, I guess which is mostly Houston?

Mostly Houston, and then an outage that we have already completed in St. Charles and -- and in total it would be about $40 million.

$40 million. Okay. Thank you so much.

Your next question will come from Chi Chow with Petrie Parkman.

Good morning. You've shown a chart in past presentations on the breakout of your CAPEX between regulatory Tier II's and strategic. Do you have those numbers for your upside '07 program?

Yes, Chi. I do. For 2006, regulatory is 570, Tier II, 975, sustained, 1295, 1.3 billion, and then strategic is about 860. Total is $3.7 billion.

How about for '07?

'07, regulatory, $425. Tier II, 375. Sustaining, 1575. Strategic, 1125. Gives you 3.5.

Okay. Thanks. Given the cost pressures on capital projects we see sort of industrywide, is that .2 any sort of bias toward acquisitions for any significant growth opportunities?

Chi, we could still expand like we're doing at Port Arthur right now for less than what we see in the acquisition market. And my -- my numbers are like your numbers, Lyondell/Citgo, Come-by-Chance being two recent ones, and of course, Western's acquisition of [indiscernible].

Okay. And given Greg's comments earlier on potential development, do you think -- do you feel like you're done growing your asset base other than expansions, that Port Arthur-type expansion?

I missed a word in there. I think you asked are we done -- let me go with -- Are we done expanding at our -- at some of our refineries?

Are you done growing your asset base other than what maybe you can do organically at some of your --

Okay. So from acquisition perspectives, the answer would be we haven't seen an asset that we, Valero, have felt was at the right price for us to acquire. Now, in the U.S., we would have certain regulatory issues, but there are markets we could acquire something.

That's why we've also mentioned in all these calls that we continue to look to Europe as an opportunity for us dealing in the Atlantic basin. And we continue to do that. That part of it is -- continues, we just haven't found a transaction that we think adds shareholder value. And we're going to be very disciplined and -- in our approach here.

Okay. Great. Thank a lot, Bill.

Your next question will come from Paul Cheng with Lehman Brothers.

Hi, guys. Good morning. There's a number of questions -- maybe the first one is to Mike. Earlier you answered the question in breakdown for '06 and '07, different component of your cap your spending.

If I look at the amount of money that's spent for [rectory and sustainable which I consider is] maintenance requirement to sustain your business going forward, there's about $1.8 to $2 billion a year on average. Is that number a bit high? I thought previously that it was more in the 1.5 -- is it just because '06 and '07 just so happened in the cycle there, they spent more money, or that going forward the 1.8 to $2 billion is a reasonable proxy for us?

I think that that number's been fairly consistent here recently over the last year or so for 2006 and '07. Tier II, though, will go down significantly in 2008 as we're pretty much finished with our Tier II spend. So, --

The reason I -- excluding Tier II I assume that will disappear. I'm just looking at what you consider as the other regulatory requirement, the $570 million in '06 and $425 million in '07, and what you consider as the substainable. I just look at the sum of those two items.

That's right. I -- I misspoke. That's correct. I think that's a fairly consistent number when you add those two.

So we should assume going forward that $1.8 to $2 billion a year is sort of like the minimum that you have to spend?

Yes, in that range is correct.

Okay, very good. And then wondering if Rich will be able to give us some maybe estimate at how the first quarter '07 turnaround schedule looks like. Is it going to be substantially more heavier than the fourth quarter, or a similar level?

Turnarounds upcoming in the first quarter, we have hydrocracker turnarounds planned for the first quarter. It is not going to be a particularly heavy turnaround year in -- in 2007 as we go across the year.

We have a 34-day hydrocracker turnaround in McKey in the first quarter. The Benecia hydrocracker turnaround 32 days, also in the fourth quarter -- the first quarter. And then the Port Arthur hydrocracker also in the first quarter.

So you consider that 2007 asset year as well as in the first quarter will be relatively light turnaround cycle for you guys?

Yes. If you look across our turnarounds, and we just updated this on a five-year plan basis, 2007 will be lower than the average.

Excellent. Rich also said in the upstream side of the business, some of the other companies have indicated they started to see some moderation of the cause in patient pressure and also the ability of people as well as the -- the hardware. Have you guys seen a similar trend in the downstream side of the business, or is that as bad as before?

No, I would say we have not seen moderation at -- at this point. As Bill Klesse mentioned we are able to acquire people, but what we have found as late is the marginal entrance into the construction and maintenance work force are not as productive as what we've seen in the past. So in the end, what you have is, labor is more costly on a dollar per hour basis, but it's also less productive. That situation really has not changed as we see it.

Uh-huh. And maybe, this is for Mike. Mike, after $3.5 billion 2007 CAPEX budget, do you have a rough percentage estimate that -- how much of them will be handled by your own in-house technical people and how much you need the major outside supplier or vendor?

Well, for major projects, we do use outside contractors to do our engineering. And we have a rigorous development process for capital projects. We use our own staff very heavily on the economic analysis and the project screening. But if you're going to do anything significant of a grassroots construction nature, you're going to use outside contractors to do the engineering.

Sure. Fully understand. That's why I was trying to understand the $3.5 billion how much was really within your control in the more direct way that is your own technical people just going in charge and how much rely on outsider. Is it 50%, or 60%, your own in-house staff control? Any kind of rough estimate that you can provide?

I don't have a number that I can give you. I would say that from a screening and development point of view, we use our people exclusively for that. To actually go ahead and engineer and construct projects, if they are large projects, it's virtually all outside engineering. Now there are -- there is a variety of small projects that are done at a refinery level where we use our own people. But it does tend to be the smaller kind of local projects.

Okay. Three final questions. One on -- Bill, wondering if you can comment whether you have any plan on the ethanol and biodiesel part of the business. And second, have you seen any with the public stock market, the refining share count has come down -- have you seen the acquisition market, the outside market, the potential seller, the view on the asset value have changed, and finally wondering that if you can share with us how much money that you earned in September month.

On the first question, dealing with ethanol and biodiesel, we continue to look at it. I mentioned on the last call that I don't think there's a single stockholder that wants us to run up to Iowa and build an ethanol plant. However, we do know and Gene Edwards, along with some of Rich's people, have been looking, and that if we co-locate an ethanol plant at a refinery, we can build it for less, and we can operate it for less than a freestanding, separate plant. So we're actually looking at that.

Clearly, ethanol is part of the U.S. gasoline going forward. I don't think people really understand the story, but I won't digress and go into that. But it is a part of it. And so we are looking at it. So in that one we're doing. Biodiesel, we haven't done much in biodiesel yet at all except that we continue to look. Remember that Colonial's just come out saying they're not going to ship biodiesel because of the jet fuel concerns. So there are issues with biodiesel. We do not see biodiesel as being a significant contributor to the distilliate market here for the foreseeable future. Acquisition values -- of course, some of the deals are still pending. So I assume you're talking about refineries and companies here. So clearly the refinery values have fallen of companies. But the individual asset values, we do not think have fallen very much. We think they're still up there.

And so let me tell you we haven't seen the peak yet, and we're refining because refineries are being built around the world. And they are at full replacement cost. When we talk about the growth in crude oil, nobody burns crude oil, you have to build refineries. If crude's up, and I'll go to the actual barrels, 1.5 barrels to 2 million barrels a year here going forward with the economic growth, you take a 300,000 barrel a day refinery, which is a very large refinery, you're talking about five to six new refineries every single year here. That's why we've continued to say refining is tight. And that's why we think the values are up [at replacement].

Our monthly numbers, I don't believe we ever give out any monthly numbers. I will tell you on a monthly number, though, we were profitable in the month of September. But I don't believe we've ever given out a monthly profit number. And so I'm not going to start that now. But we were profitable. We were profitable in the month.

Perfect. Thank you.

Good.

Your next question will come from Mark Gillman with Benchmark Company.

Hi, guys, good morning. I have a couple of questions, but I promise it's less than 17. Should we be cognizant of any LIFO inventory considerations for you as we approach year end?

No.

No.

Okay. Mike made the comment about the wholesale contribution in the quarter of $80 million. I wonder if you could put that in in some historical context in terms of the contribution of the wholesale business in prior periods or normal.

Yes. We're going to look it up for you here, Mark. You want to ask us the next question?

Sure enough.

We'll come back to that one.

The Contango in the markets as Neil McMahon alluded to previously has been pretty steep. And that's typically I think a period where you get some benefits in the mid continent unit. Wonder if you could take a stab at quantifying what that's been?

Okay. We're going to answer your first question on wholesale. Then we'll come back to the Mid-continent.

Okay. For the second quarter, this year, we made about $4 million dissolve from the wholesale.

Mike, what did '05 look like for example for the year?

I don't have that information here with me, Mark. I'll get that and give it to Eric, and he can give you a call.

Okay. That's great. How about the mid continent issue?

We're going to -- I don't think we're going to be able to give you a good number on the Contango except that your observation is exactly right. It does lower our crude cost. And thinking back on the month, and it was over $1 several months there, so I'm sure this benefit is over $1 to the crude cost to the Ardmore, McKee and those refineries. But we don't have a number the way you want it. But your observation is correct.

Let me try -- you're running noticeably more resid on a systemwide basis in the last couple of quarters. I wonder if I could ask, are you arbing resid against the Maya? Is that what gets backed out when the resid feed -- I assume straight-run resid feed goes up? And are there any contract minimum offtake requirements in terms of arrangements with PEMEX regarding Maya specifically?

Okay, first part of your question is yes, that's exactly what happens. We put into the LP all these thing that we think we can buy. And the expected prices. And your observation is right. The -- these resids that have come in are very economically priced. So that's correct. Then the next question was --

Are you arbing primarily against Maya so that for every barrel or resid you're running, essentially you're running one less barrel of Maya?

We have a contract of Maya. We do have volume there, but we also run other resids in the system. Some are not under contract, some are. Plus as you know, the Maya volume has been down a little bit here. So that has given us some extra opportunities.

But we do honor our Maya contracts and minimum volumes. Then we just back out other heavy sour.

Can you say what that minimum is?

I have said many times that we run around 500,000 barrels a day of Maya. And so that's very close to where we are.

Guys, thanks very much.

[OPERATOR INSTRUCTIONS.] Your next question will come from Ed Mustafago with Pritchard Capital Partners.

Hi, guys. How you doing? Two quick questions, one is just kind of a follow-up on the gasoline import issue. One of the reasons that I've heard that we had such an increase in gasoline imports this past several years is from the differential between diesel and gasoline in Europe. And that's pretty much all but dissipated now. And so how does that speak to any change or any increase in imports coming out of Europe next year?

I think there's two things going on. First of all, in Europe, the diesel demand continues to grow and gasoline demand continues to shrink. They run the refineries full-out to make the diesel during the surplus and more gasoline. And that's a big factor of what's been coming here. The other thing is the tax structure in Russia. They tax the crude coming out at a lot higher rate than they tax the product.

So it encourages the refineries to run crude as much as they can at the refineries, even though they're relatively unsophisticated to try to make more light products which they can export a lot at a lower tax rate. They see a lot of gasoline coming out of Russia and former Soviet Union countries for that reason. Again, it's a little bit higher sulfur. They've been using credit so far this year to get them in. What happens next year, they're just going to have to readjust and see how they can meet our specifications.

Okay. Great. And the other one is certainly a little bit more related directly to you guys, but a little macro, as well. That is, post-ULSD transition here, if you look at inventory levels and really sort of proxy them off an 80/20 rule, it really suggests that applicable inventories are probably under 20 days of supply. And obviously you guys said you're still struggling to keep up with demand.

How does that speak to what we could sort of look at in terms of growth in inventory in terms of days-of-supply next year? Did things remain extremely tight which is certainly extremely bullish with you guys with such leverage to the on-road market. And from there how does that potentially affect what goes on in terms of the -- the export ULSD?

I don't know how it relates specifically to the absolute inventory levels. We fully expect that demand for ULSD is going to continue to grow in the Mid-continent, for example, where HSD isn't available. They're going to have to run ULSD for that. So it's going to continue to stimulate demand. Gene, what about inventories in days-of-supply?

I think that's the biggest factor, day-of-supply being so tight on the tighter sulfur diesel. The fact that the high sulfur is just not available anymore. All these off-road markets are having to use it. Which demand is up very significant year-on-year, which the day -- day-of-supply is by demand, right. So the high demand is really shrinking the day-of-supply for this market.

And the final point I'll make, that's why the forward curve looks like $13 a barrel next year on the Gulf Coast. So all these factors are very bullish for -- and why we're bullish about distillate.

Right, I agree. I think some out there are looking at, let's say, aggregate, LSD plus ULSD inventories, which really suggests an increase in days-of-supply, and that's just, I think, the wrong way to look at it.

Uh-huh. I agree.

Great. Thanks, guys. Appreciate that.

Your next question will come from David Wheeler with New Berger Berman.

Hi, guys. Can you remind us when -- on the strategic capital spending what you expect the earnings or cash flow contributions to be in '06, '07, '08?

Okay. On the -- on the growth projects for 2006, we anticipate about a $90 million operating income, impact. That is lower than we have announced before, and it really reflects the extended timing on some of the completion of the projects that we've had as part of our capital program. For 2007, we anticipate that it will be at least a $300 million operating income impact in that year.

And do you have a number for '08, as well, or is it too early?

We haven't put together a number for '08 yet.

Okay. Good. Thanks very much.

At this time there are no further questions. Are there any closing remarks?

No, there's not. Thank you all very much for joining our call. And feel free to give me a call if you have any questions. Thank you.

Thank you. With that, we'll conclude today's Valero Energy third quarter 2006 earnings release conference call. You may now disconnect.