瓦萊羅能源 (VLO) 2003 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Third Quarter 2003 Valero Energy Corporation Earnings Conference Call.

My name is Kelera, and will be your coordinator for today.

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

We will be facilitating a question-and-answer session towards the end of this conference.

If you require assistance at any time during this call, please press star, followed by zero.

As a reminder, this conference is being recorded for replay purposes.

I would now like to turn the presentation over to your host for today's call, Mr. Lee Bailey, Vice President, Investor Relations.

Please proceed, sir.

Thank you, Kelera.

Hello, everyone, and welcome to Valero Energy Third Quarter 2003 Earnings Conference Call.

With me today is Bill Greehey, Valero's Chairman and Chief Executive Officer and other members of Valero's senior management team.

If you haven't gotten the latest release, you may obtain one off of our website at Valero.com.

The tables attached to the earnings release provide some additional financial information on our various business segments.

If after reviewing the attached tables you have some additional questions on the information, please feel free to contact us after the call.

We've also posted some additional information on gasoline distillate crude oil fundamentals to the Investor Relations portion of our website that you may also want to review.

Before I turn it over to Bill, I would like to turn your attention to the forward-looking statement disclaimer contained in the release.

In summary it says that statements in the press release and conference call that states the company's management or predictions are forward-looking statements intended to be covered by the Safe Harbor provisions under federal securities laws.

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

With that I'll turn it over to Bill.

Thank you, Lee.

Well, overall this was a strong quarter.

In fact, our net income of $191.1m, or $1.50 per share set a new third quarter record for Valero.

The net income was actually 50% higher than the previous record.

And these results could have been even better had we not experienced several unplanned refining outages early in the quarter.

Compared to last year, refined product margins were nearly double what they averaged in last year's third quarter, in each of our core areas.

And even though sour crude discounts were all that great this quarter, averaging around 3.15 per barrel, they were still a lot better than the $2.42 per barrel we averaged in the third quarter last year.

Most of the strength in gasoline margins occurred in the month of August when gasoline margins increased sharply when good demand, industry-wide refining outages, and lower imports.

Retail and wholesale also made surprisingly strong contributions during the month of September, as crude prices fell and retail prices lagged behind.

Now let me run through some highlights from the numbers we recorded.

Year to date, net income is $489.9 million, or $4.10 per share.

The operating income was $357.4 million, this quarter, up from $130.3 million in the third quarter of 2002.

Refining operations contributed $393.4 million to the total operating income, and as you'll see in reviewing the earnings release tables, each of our refining regions contributed substantially to the quarter's results.

In particular, the Quebec refinery once again had an excellent quarter contributing over $76 million of the northeast region's refining operating income.

Our retail operations contributed $47.3 million, which is impressive when you consider that nearly all of that was earned in the month of September. $33.3 million of the retail contribution was earned in the U.S. retail system which had an average fuel margin of nearly 16 cents per gallon.

The northeast retail contributed about $14 million with an average fuel margin of just over 17 cents per gallon, which is a good margin for this time of year in that market.

And going through some of the income statement items, you'll note that interest expense declined to $65 million from $77.9 million in the third quarter last year.

The decline in interest expense is due to lower average borrowings from the deconsolidation and sale of assets to Valero LP and the benefit from interest rate swaps we've had in place this year.

The weighted average shares outstanding for the third quarter were $127.6 million on a fully diluted basis.

This is up from the second quarter 2003 shares of $118.7 million, primarily due to the effect of the preferred shares we issued July 1st to the O'Ryan refining owners.

You are probably aware that the O'Ryan owners remarketed those securities earlier this week.

Also on August 18th, an additional $4.9 million shares were issued to convert the preferred securities which were originally issued in 2000 to fund part of the Benicia acquisition.

Total debt at the end of the quarter was approximately $4.4 billion.

That brings our debt-to-cap ratio down to 42% net of the $310 million of cash on the balance sheet at the end of the quarter.

Also, we currently have about $1 billion of available capacity under our revolving credit facilities.

With respect to our credit facilities, we're in the process of renewing our one-year, $750 million credit facility that expires next month.

The renewal process is going very well, and we expect to renew the facility on similar terms as our existing facility.

The good news is that the facility will be renewed for a three-year term.

You may have seen that last week our board of directors approved an increase in the quarterly dividend to 12 cents per share.

This is effective with a dividend payable on December 10th.

We view this increase as a reflection of not only good earnings and cash flow we generated this year but also on the positive outlook for our business.

And speaking of cash flow, a big positive for us this year and next is that we do not expect to make any U.S. income tax payments.

The current U.S. tax laws allows us to deduct 50% of our qualifying capital expenditures in the first year, and with the NOL carry-forwards from prior years, we expect to be able to eliminate the U.S. federal tax payment.

So obviously this is a big benefit to our cash flow position.

Turning now to operations, as I discussed in detail on last quarter's earnings conference call, we experienced an unacceptable number of refining outages at the end of the second quarter, some of which extended into the third quarter.

In total, unplanned outages reduced operating income $75 million for the quarter.

I'm happy to report, though, that all of our refineries are now running according to plan.

One other item on operation.

Over the last week or so we have been in the process of starting up the new 45,000-barrel-per-day Coker at Texas City.

The start-up of Coker and the tie-in of other units has gone very smoothly when it was completed ahead of schedule.

Currently we're processing around 40,000 barrels per day and we expect to be at full rates in the next few weeks.

On a full-year basis, we believe that the addition of the Coker will add around $80 million in EBITDA.

Next I would like to comment on the current industry fundamentals in our outlook for next year.

As is typical of most Octobers, this is a shoulder month where we wait on cold weather to spur distillate demand and adjust the system toward maximizing distillate production.

With that said we're seeing good distillate margins in anticipation of winter weather.

Gasoline margins have also been exceptionally strong for this time of year.

This is a reflection of the good gasoline demand and below-average inventory levels.

For example, October Gulf Coast gasoline cracks have averaged over $5 per barrel versus the five-year average for October of $3.23 per barrel.

You know, the good news is that the Gulf Coast crack right now is $7.37, and the cracks have moved -- gasoline cracks have really moved up in all of our marketing areas.

With the relative strength we've had this month in gasoline margins, the switch to maximum distillate production is occurring later than normal.

On the feed stock side, we've been seeing some narrowing of the sour crude discounts due to the delay in getting more Iraqi crude to market.

Discounts for our November deliveries of sour crude oils from Saudi Arabia narrowed to $2.95 per barrel from $3.28 per barrel in October.

However, we are encouraged by the fact that more crude is starting to come out of Iraq and Russian Euro grades are becoming more abundant.

Discounts for spot sour crude such as Mars have recently started to widen back out.

So we expect better discounts for December.

Looking further out, sour crude discounts should also benefit from increased demand for sweet crudes under the new low-sulfur specifications beginning in January, and resid demand is down globally putting more sour heavy crude stock and that puts downward pressure on the sour prices.

In addition as the economy continues to strengthen, crude oil demand will increase, pulling more incremental barrels of sour crude oil into the market.

Recently we've been getting a lot of questions on the regulatory changes the refining industry is facing over the next several years.

These changes present both challenges and opportunities for us.

Overall, we see the impact as very positive for our industry.

The EPA's Tier 2 fuel specifications will require large reductions in the sulfur content of both gasoline and diesel, requiring significant industry investments.

Beginning January 1st, refiners and blenders of gasoline will be required to limit the annual average sulfur content in gasoline to 120 parts per million.

Now, as you know, the limits keep getting tighter over the next few years.

Industry estimates for spending on Tier 2 alone average from a range of $15 to $20 billion.

Including the strategic investments we're making for hydrogen, Valero's own estimate is in the range of $1.2 to $1.4 billion for the 2003 to 2006 period.

While this is a large investment, the overall impact on earnings should be positive as margins respond to the reduction in supply.

In total, most industry consultants such as APEI, PYRA and EIA are estimating loss refined production capacity in the U.S. in the range of 100,000 to 200,000 barrels a day.

That's the equivalent of closing one or two world scale refineries, and those numbers don't take into account the impact the new fuel specs will have on imports.

Right now if you look at sulfur content of the gasoline that's being imported to the U.S., we estimate that about 50% of the barrels from Latin America, the Mediterranean, Eastern Europe, and Russia would not meet the 120 parts per million sulfur limitation.

That amounts to around 150,000 barrels a day of gasoline that would be disqualified from this market beginning next year.

These barrels will have to find a home elsewhere in the world because most of these foreign producers won't make the investment to clean up their barrels.

What has happened in Venezuela this past year is a good example of what we're likely to see next year.

Typically the U.S. has received between 80,000 to 100,000 barrels a day of gasoline from Venezuela.

This year they have only been able to deliver about 40,000 barrels a day of gasoline.

Like other producers, they have been focusing what limited capital they have on EMP investments and are now looking for new markets for their high-sulfur gasoline rather than invest in refining.

And don't forget, gasoline demand in the U.S. continues to grow at 1% to 2% per year.

So more imports, not less, are going to be needed just to meet demand.

Yes, refining system only produces about 93% of our demand.

The rest has to be met by imports.

So margins will need to move higher to attract the cleaner barrels to meet the U.S. demand.

On top of the lower sulfur specs next year, California, New York, and Connecticut have banned the blending of MTB into gasoline.

When you replace MTB with ethanol, you only yield about half the volume you would have had with MTB.

We expect that change to reduce gasoline supply by another 70,000 to 80,000 barrels per day next year.

When you look at all of this together, the experience that California has seen in its move to cleaner and cleaner fuels is about to be shared by the rest of the country.

Many of you may remember, too, that in any year in which we've had a change in fuel specifications, the first year is particularly challenging for both the refineries and the logistics systems to keep up with the resulting more volatile prices and higher margins.

The bottom line is that in order to meet demand, margins will have to move up to attract more supply to the market.

You know, what we're seeing in the marketplace today, I don't know how anyone can be negative about our refining business, and I've never seen a more positive outlook for refining.

With that we'll open it up for questions.

Ladies and gentlemen, if you wish to ask a question, please press "star," followed by "1" on your touch tone telephone.

If your question has been answered or you wish to withdraw your question, please press "Star," followed by "2."

Again, ladies and gentlemen, if you wish to ask a question, please key "star," "1" on your touch tone phone.

We will now pause for a moment while questions register.

Your first question comes from the line of Nicky Decker of Bear Stearns.

Please go ahead.

Good morning.

My question has to do with your comment on the EBITDA contribution for the new coker unit.

Can you just go through what your assumptions are behind that?

And to the extent that you can review the terms of the supply contract.

Thank you.

The basis of the $80 million EBITDA is essentially lowering overall feed stock costs that's based on running 90,000 barrels a day on crude.

That's $6 discount to WPI and upgrading the pitch on oil that we market out of the Texas City refinery today which is about 15,000 to 20,000 barrels a day through higher barrel intermediates, gasohol and low-sulfur diesel.

And on the [Maya] contract, five-year contract, 90,000 barrels a day.

Is there a guaranteed margin on that contract, coker margin like we've seen in some of the other contracts?

Yes, there is.

I really don't think they want us to go public on the terms of that contract, but there is protection on the margins, but it is an averaging.

So, you know, if you are over now and then you are under later on, it all averages out.

So it's not like you are balancing it out each month.

It's on a cumulative basis.

Okay.

Great.

Thank you.

Your next question comes from Paul Ting from UBS.

Please go ahead.

Good morning.

I've got two questions.

One is you talked about the fact that gasoline margins were very good, but if you look at the yield in your third quarter, the gasoline yield is 53%, slightly below the prior year, is that just because of the mix of the crude, or is there any other reason for a lower yield in spite of the strong gasoline margin?

Secondarily, you mentioned that distillate margins are good looking forward but there seem to be a difference in some of the comments that we heard from a company that reported earlier.

I was just wondering if you can give us some numbers about your current -- what kind of distillate crack are you looking at.

You said $5 for gasoline.

Can you fill on the blanks on the distillate part as well for us?

The first part on the gasoline production, as we talk, Benicia makes a lot of gasoline, and they were down in the second quarter which, again, went into the third quarter.

So that had a big impact.

And then we had the downtime in Texas City.

So it was the unscheduled downtime that reduced the gasoline production.

If I can add, Bill.

It was also because we're maximizing BTX production at every plant.

We have very good pricing for benzene, toluene and xylene and also, St. Charles refinery is in there in the third quarter, and that has affected our overall yield.

Sure.

For gasoline.

So with the things that Bill said and these other two items, that's why our yield is down, but you can rest assured we've been maximizing gasoline production.

Right, that makes a lot of sense.

What is your gasoline yield right now?

Right now it's about 54%.

54%?

Okay.

And distillate part, please?

Why don't -- you know, first of all, we have a lot of our distillate hedged for the fourth quarter, we have some hedged for next year, and, Bill, why don't you cover those numbers and what those prices are.

We have distillate hedged in the fourth quarter of 28% of our production east of the Rockies, and we have those hedges on at around $5, and the market here is about $4.65.

Okay.

And for next year, we have 24% of our distillate hedged for the entire year.

It's weighted a little different, more in the first quarter, second quarter, and less as we go out.

We put those on at around $4.18, and the current market is about $3.95 to $4.

Okay.

Great.

That helps a lot.

Appreciate it.

Your next question comes from the line of Doug Teracin of Morgan Stanley.

Please go ahead.

Good morning, Bill and company.

Hey, Doug.

I hope you are right on 2004, Bill, but I think you will be.

But that's not my question.

My question has to do with unscheduled downtime which you talked a little bit about today.

I think it cost you guys about 35 cents a share in the quarter related to the issues at Texas City and Benicia.

So my question has to do with whether or not this is a full list of plants.

If not, could you tell us which other plants may have cost you guys a little bit in the quarter?

And also, can you relate how you arrived at the loss profit figure of $75 million meaning, was this simply the opportunity cost that you computed and, if so is there any reason to believe that that amount or a similar amount shouldn't show up in the fourth quarter?

You know, first of all, what we do is we count every single unscheduled downtime, whether it's a day or two days.

So, you know, with that, you are always going to have unscheduled downtime for a refinery, but if you look at the third quarter, there were really only two refineries that we had the problems with.

They were both carry-forwards from the second quarter, Benicia and Texas City.

Okay.

And between those two, you know, that was close to $60 million.

Okay.

And when you have got 14 refineries, you are always going to have a refinery down for a day or two for some problem and again, you know, we just account for all that.

And what we do is we look at the prices during that day and what the production would have been and what we would have made.

And that's probably not a good way to look at it because in Benicia, you know, when Benicia goes down, margins go up significantly and we're using the higher prices for the lost opportunity, where if you wouldn't have been down, those margins wouldn't have spiked.

So, you know, the numbers are probably higher than they really are because, as you know, I mean, margins now are exceptionally strong because we have a lot of refineries that are down for turnaround, we have a lot of refineries that are down for unplanned outages, and anytime that happens and you get a big price spike just like we're seeing today in gasoline.

Sure.

It just shows how tight this market is.

Sure.

And one other question.

The run rate of SG&A seemed to have moved a little bit higher which I suspect may have been related to compensation expense, but I don't know that.

So could you kind of comment on some of the components that moved that number a little higher and also any updated run rate guidance you may have for us?

Okay.

Doug, this is Mike.

The increase in the quarter was about $14 million comparing to last year's third quarter.

About $6 million of that is due to variable cost compensation band $5 million of that is due to salaries, wages, and benefits.

Okay.

You know, on a comparison basis, last year in the third quarter, we didn't have anything for comp.

Sure.

So this year we're having a better year, we've got some accrued.

And, Doug, the run rate's going to be about 75 a quarter.

Okay.

Great, guys.

Thanks a lot.

Your next question comes from John Meloy of Simmons.

Please go ahead.

Afternoon, gentlemen.

A couple of, I guess housekeeping items.

I just want to check up, make sure I heard correctly.

There's no tax payments in '04 and, Bill, did you say in '05 as well?

No, we said '03 and '04, but --

the remainder --

But probably, you know, probably the same thing in '05 based upon our capital.

Yeah.

Okay, and on to that, $1.3 to $2 billion is what you said on the cost of Tier 2?

Or could you give me the timing in your spending plans for your environmental?

It's $1.2 to $1.4 billion on our Tier 2 capital and that's 2003 through 2006.

Okay.

And how much has been spent through the end of this year?

We're looking that up.

In 2002, we spent about $60 million, and in 2003 we've got roughly $420 million.

Will the majority of the remainder be spent in '04 or blended in through '04, '05?

It's in '04 and '05.

We complete the gasoline in '04 and then '05 is the diesel.

Okay.

Also, for John, what were you guys running at Texas City, or basically what's being displaced with the 90,000 barrels of MIA that you are running at Texas City now?

It's typically Middle East crude or medium weight.

Then we swap that out with the MIA running in our other refineries like Corpus Christi.

Okay.

And could we get some throughput guidance for the fourth quarter?

Yeah, John, this is Lee.

Yeah, fourth quarter, we're pretty much going to be in the same range for the mid continent, northeast, and West Coast.

We'll see a pick-up in the Gulf Coast obviously because Texas City's back up, and we have the coker there as well.

So we're expecting in the Gulf Coast to be up from the 9.33 in the third quarter to about 10.40, in that range.

Okay.

And every where else will be about the same as the third quarter.

Just a real quick point on the taxes, too.

You know, there's still some Canadian tax and state tax that will be paid.

So, you know, as you've kind of looked in the past, our run rate on deferred versus total has been about 40%, 50%.

For '03 and '04, given this accelerated depreciation and the NOL position that we're in, that deferred piece will be about 75% of total tax.

Okay.

And the total tax rate would still be in the range of 37.5% for a full year of basis.

About -- what is it, about $100, $200 million to cash flow?

About 100.

Okay.

Thank you.

Your next question comes from the line of Mark Gilman of First Albany.

Please go ahead.

Bill, Lee, good morning.

I had a couple of things I wanted to go over.

Just on that tax item, is this a new element of the tax law that you can write off half qualifying investments in the first year?

I'm not familiar with this.

Mark, this is Clay Killinger, the Controller.

The actual, the tax law has been in effect, but it was a 30% write-off of qualifying capital expenditures, and as part of the economic stimulation package of the administration, it's been increased to 50% for one year, and the expectations are until the economy turns around, that might be continued.

So it's not an old law.

It's a change in the qualifying percentage write-off.

I got it.

Secondly, is the registration statement for the mandatory converts effective?

Can I assume it is with the remarketing?

Yes, it is.

Yes.

All right.

Can you break down the $75 million in outage impact by regions?

I know you said 60 associated with Benicia and Texas City, but can we do a little bit finer job on that?

You know, I can go through these refinery by refinery if you'd like but again, there -- you know, Benicia's 33, Texas City's 25, Corpus is 4, Three Rivers is 4.

Actually these are not grouped.

Krotz Springs is a million and a half.

St. Charles is a million and a half.

Paulsboro is a million and a half, Wilmington is a million, Three Rivers is a million and then the other is just miscellaneous.

Okay.

Thanks.

What was the St. Charles throughput in the third quarter, if I could?

I've got that marked.

It was -- this is Lee.

It was 191,000 barrels a day.

You know, keep in mind that in the third quarter, as soon as we bought it, we had both of those sulfur plants down for turnaround.

Okay.

And, Bill, if I could just follow up on the comment you made regarding the performance of Quebec and its contribution to the northeast refining.

By subtraction, if I could still do any of that, it implied that Paulsboro's performance was not too terribly good.

Is that an accurate observation in your mind?

That is right.

And what are we doing about it?

What we're doing is obviously now our move margins are much better.

We're also trying to broaden this crude slate for lube production, which we have an agreement with Exxon to do so.

So we're doing that, thus we can run different crudes with lots less work on our crude cost.

We're working --

Can you speak up a little bit?

I'm having trouble hearing you.

We're working on our crude costs by going for a variety of crudes to make lubes, and we have a procedure with Exxon that lets us do that.

That broadens the slate of crude oil we can put in.

Also, as Kirkuk crude which we hope will come back into the market here, that is also an acceptable crude and it's priced better.

We also have issues with our crude logistics there on shipping.

We are attacking that through looking at tankage and et cetera.

We're focusing on a big turnaround at that plant here in first quarter 2005 where we are going to expand the cat cracker.

If you look at the configuration of the plant, it is slightly under-configured to make clean products.

We are also building a reformer there at CCR which will also improve our gasoline yield at that plant, plus the GDU.

So we have many initiatives underway to improve the performance of that refinery over the next couple of years.

All righty.

If I could just one more.

Is there a number that you could talk about in terms of the backwardation impact on the mid continent results in the third quarter?

In the third quarter, now I'm talking about the crude that we actually bought for the month of July, August, and September.

If you look, if you'll remember, backwardation was very high in July.

So we incurred costs of somewhere around 80 cents for the actual crude that was delivered in the mid continents.

So the cost to us of backwardation for those refineries was somewhere in the $12 to $15 million range.

Okay, Bill.

Thanks very much.

And backwardation has come down significantly now.

Mark, this is Lee.

I wanted to just follow up, too, on one of the key factors in the mid continent during the quarter when you are comparing back to Q3 '02 is the deconsolidation effect, you know, pulling out the gross margin related to the Valero LP, and the total margin impact for the full company, both mid continent and Gulf Coast was about $26 million, and about 75% of that was tied into the Mid continent since that's where most of the LP assets where and if you put that on a per-barrel basis, that would mean that the Mid continent gross margin that was reported was impacted by about 75 cents per barrel for the deconsolidation.

So that had some impact on the Mid continent as well.

Your next question comes from the line of Mark Flannery of CSFB.

Please go ahead.

Hi, yes, I have a question on mid-cycle earnings guidance.

I know in the past, you've given this, either an EBITDA or EPS terms.

Companies change a reasonable amount since the last time we heard from you, and given the relatively bullish case that you set out for 2004, could you perhaps give us some indication on a like-for-like basis as what the corporation roughly should be expected to earn on a mid-cycle basis?

EBITDA or EPS, it doesn't matter, whichever you are more comfortable with.

You know, first of all, mid-cycle as everybody defines mid-cycle, is you just go back five years and you average what the prices are, which to me is kind of a meaningless number.

We really have not updated any kind of a mid-cycle number.

Well, for example then, in May 2002, it was suggested the margins average -- you know, the average margin between '98 and 2002, Valero could do $5.50 per share.

Is that kind of number still in effect, would you say, or not?

We just really have not updated.

Again, we have St. Charles, we've got the coker, we've done a lot of upgrades to the refineries.

We just have not worked that number.

Okay.

And let me try a second one then.

St. Charles did $10 million contribution this quarter.

Following the turnaround next year and when you really get into that thing, what's a good annual number that we should expect as a contribution from that plant into the corporation?

When the -- in the original economics we announced O'Ryan based on the price call, it was a little higher than $90 million.

It was in the $125 million price range EBITDA and on mid-cycle, it was about $80 to $90 million.

Right.

And those numbers are still current, are they?

Yes.

Great.

Thanks very much.

Your next question comes from the line of Greg Haas of Sanders Morris Harris.

Please go ahead.

Good morning, gentlemen.

I just have a question regarding natural gas price usage in the quarter and any sort of purchase price that you can give us.

John, you want to --

I may as well get it.

On natural gas usage, we average between 200 and 250 million cubic feet per day.

And as far as the price projection we're about, what, 450, be a good number to use?

You are talking about our fourth quarter natural gas price?

No, actually what you had experienced in the third quarter.

Oh.

I was going to say $4.58 a million in the third quarter.

About the same currently.

So $4.58 a million.

Okay.

And that was on a run rate you said of two?

200 to 250, but that includes natural gas as a feed stock to our hydrogen production plant.

Right.

So that's all purchased?

That's all purchased, that's correct.

Right.

Okay, very good.

And then the other question, it seems to me that the Midwest region had an exceptionally productive quarter in terms of run rate, and I think you indicated that it will be going forward at that level into the fourth quarter.

Is this a record for that and, you know, is there something that in my -- you know, the way I look at it, you think you guys were above rated capacity on that; is that right?

We did set a record at Ardmore as far as gas leak production in the fourth quarter and it's from excessive turnaround that we had earlier in the year.

And so into the fourth quarter, we should expect the same sort of level of production then?

Well, the one thing you've got to keep in mind at both McKee and Ardmore, we do produce asphalt.

From a seasonality standpoint we see weaker asphalt cracks in the fourth quarter and so there would be some minor reduction and throughputs at Ardmore.

But those refineries ran well.

I mean, they had so unscheduled downtime.

Probably -- we didn't look, but I'm sure it was probably a record for them in the third quarter.

At least as far as I go, you know, in my historicals, I think that's the case.

Right.

The other set of questions, I guess just one really, and I would love to hear how much you can say.

You know, as far as the MTBE outlook goes, I'm curious to know the current capacity of MTBE manufacturing at your plants, and if you can release to us the approximate book value that you have on those right now.

Okay.

I could tell you the total capacity is a little over 37,000 barrels a day of MTBE and paying production.

Now, in the third quarter, we did shut down our MTBE plant at Benicia as part of our car-free gasoline program but we're shutting down the MTBE and expanding the Appalachian unit.

I think going forward, you know, the -- we do plan on converting the Houston plant to iso-octane and we plan to do that late this year, early fourth quarter.

Incidentally, the MTBE plants have made good money this year.

I mean, even now, you know, looking at the blend value, it's still been very, very profitable.

You know, the good news is that, and Greg can comment on that, the energy bill, I mean, we've been concerned about MTBE liability, and the good news is that that is addressed in the energy bill, and you might bring them up to date on that.

Yeah.

You know, the energy bill has been stalled for the last several weeks on tax issues, primarily ethanol and the subsidies of the highway trust fund, but liability protection has been our top priority, and we feel good that we're going -- very good about getting that language in the final bill.

The issue has been MTBE ban or no ban.

The Senate wants a ban, the House doesn't.

And so far has not been any discussion about a ban or if there will be a ban, now they talk about maybe 2015.

So things have gone very well on that front with respect to MTBE.

Let me ask just clarification there.

In terms of the protection under the new energy bill that's being, you know, debated, if I understand correctly, it's what you-all are likely seeking is protection from the manufacturer of, I guess MTBE and having that not being considered a defective product, and I think that is pretty close to being agreed to, or is that not accurate?

No.

And then the second issue --

No, you are right on that.

Yeah.

You are absolutely right.

And I think the second issue is whether there is some sort of liability protection on tanks and pipelines and that kind of thing that may have leaked over the years, and I'm not so sure about that.

What is the status on that particular?

No, no, that has never been a part of the bill.

Yeah, okay.

What we have always said on that if if there's a leaking tank, then a lawsuit, you know, is justified in terms of at least finding out whether or not there's liability.

Yeah.

Don't sue us just because we manufactured a product that the Government mandated us to use.

Right, okay.

And so we have that in the bill.

So the status of that looks pretty close to being in the bill and such?

We believe it is in the bill, yes.

Yeah, okay.

Just to clarify, could you share with us the capacities in barrels per day of the Houston and the Benicia plant?

Yeah, the Benicia plant was about 2200 barrels a day and the one in Houston was about 2,000 to 2100 barrels a day.

Very good.

Thank you so much, gentlemen.

Your next question comes from the line of Chi Chow at Petrie Parkman.

Please go ahead.

Good morning.

I also have an MTBE-related question.

Can you describe the operational changes in your system to accommodate the upcoming ban in New York and Connecticut?

And if you plan on supplying the [arbove] product from the Gulf Coast and Quebec.

One of the -- I guess to answer your first question, right now at [Tulsa] we don't make MTBE or Quebec.

We do blend MTBE to make RFG for Pennsylvania and New Jersey.

Of course there is no MTB ban in either state.

We will continue to do so.

As far as Arbove, one of the things we're doing at Paulsboro as Bill mentioned earlier, is we're bringing on a new CCR, and that's a reformer, late March, early April.

This is going to reduce our production of low RVP,and high octane blend stock and that will help us to make some Arbove at the refinery.

So we're evaluating that now, whether we should import blend stocks from our Gulf Coast to increase our Arbove production, either out of Paulsboro or in the tankers that we lease in the northeast.

But right now we don't market in New York or Connecticut.

So that has no impact on our operation.

From the Paulsboro plant.

Right.

It sounds like you might be getting ready for the summer, though, and producing some Arbove for the low RVP?

Is that --

It sounds like a potential opportunity.

So we're evaluating that.

And then your other piece of the question concerning the John Glenn refinery, we do not ship material like that into New York.

We sell some U.S.-spec gasoline in way upstate New York and Vermont but that's all.

Okay.

I'm not sure if you can answer this question or not, but how ready do you feel that the domestic industry is to handle, you know, the change specific to the MTBE ban given that imports will likely be reduced, especially with the low RVP in the summer?

I think the system is strained right now.

We're dependent upon imports and, you know, I think we're going to see some supply problems the first of the year just going from MTBE to ethanol and going to Tier 2 and the impact it's going to have on imports.

So I think it's really going to strain.

I mean, obviously there's not capacity being added in the U.S. to keep up with demand.

So you are more dependent upon imports, and all the regulations keep shrinking capacity.

At some point, something's got to give.

Great.

Thanks a lot.

Your next question comes from the line of Jay Media of Forest Investments.

Please go ahead.

Thanks for the call.

Actually I have a little bit of a different question.

I want to ask about the dividend going forward, if you guys had reviewed, you know, dividend policy.

And also, if you could relate that to the preferred that you just issued, whether the preferred dividend will, you know, vary based on your indications for the common dividend.

Thanks.

Okay.

On an annual basis around the third quarter, we will look at our future projected earnings and cash flow and then make a determination of whether we want to increase the dividend in the fourth quarter.

So we'll look at that annually.

Our common dividend policy will not affect the dividend on the convertible preferred.

So it's 2%.

Okay.

And you said the third quarter, you will review that annually?

Right.

So you mean in coming up here, you are about to do the review?

We've already done it for this year because we've increased our dividend for the fourth quarter 2 cents.

So next year we'll look at it early in the third quarter.

Okay, okay.

Got it.

Thanks very much.

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

Please go ahead.

Thank you.

Hey, guys.

Quick question.

Maybe this is for Bill or John.

In terms of wrongful mix, how you guys know is it going to be reasonably normal, heavy, or not?

Rich Marcogliese is going to answer that.

We've got a moderate level of turnaround activity in the first quarter on the West Coast, we're going to take the Appalachian unit down in Benicia and that is to expand capacity on the unit to compensate for MTBE phaseout.

Also on the West Coast, in January we're going to take the cat-cracking complex at Wilmington down for about 33 days, and we're going to do a full reactor replacement project for liability purposes on that unit.

In the Gulf Coast we will take down the crude unit, crude and vacuum and St. Charles refinery and this is for a planned crude expansion project that will take us from 155,000 to 180,000 barrels a day.

Okay.

That's it.

Those are the big ones.

Your next call comes from the line of Ted Izatt of Lehman Brothers.

Please go ahead.

Hi, good morning, everybody, congratulations on a great quarter.

Really I have two questions.

One, on the Tier 2 environmental cost, you said $1.2 to $1.4 billion over the next three years, I guess, through 2006.

Can you give any more breakdown as to how much in each year?

And then Number 2, you've done a great job of getting your debt down and you are now I think down to where you said you would be by year end, into the low 40's in terms of capitalization.

Is that -- given the, you know, the environmental requirements here and given, you know, potential M&A activity in the future, do you see yourself staying at this level or do you see yourself going lower or do you see yourself going higher?

What's sort of the corporate objective now in terms of capital structure?

Let me answer the second part and then they are looking at the numbers you asked for by year for Tier 2.

We do plan on staying in the low 40% on debt-to-cap.

That's pretty much our target.

For Tier 2 gasoline, including hydrogen in 2003, we're looking at $400 million.

In 2004, $290 million.

And then in 2005, $130 million.

And then it's basically some little carry-over into 2006.

Okay.

Great.

Thanks very much.

And that was gasoline.

Your next question comes from the line of John Sees at Grassma.

Please go ahead.

Good morning, all.

I wonder if there's any fellas could get Bill to agree to show a little enthusiasm for the business.

Hey, that's ugly.

Do you remember that chart I put together that margins keep getting better every year?

Yes, indeed.

And one of the analysts said, you all agree he always says that, but it's not happening.

It is happening.

You have some right positive reports, get this stock moving.

You have some supporting evidence at the moment, I guess.

Could you tick off that the annual numbers for Tier 2 spending again?

I got scribbling a little too late.

Okay.

Now, what he is talking about is gasoline.

Yes, gasoline specifically.

Okay.

And including our hydrogen unit with the CCRs and stuff we're doing here.

Right.

Okay. 2003, $400 million.

Fair enough.

2004, $290 million.

Okay.

2005, $130 million.

Good.

And then it's about $20 million in 2006 but it's really just carry-over.

Right.

And by and large, that's the lion's share of the remaining $700 to 900 total number that you derive after deducting what's already gone into Tier 2 spending.

For gasoline, that is correct.

Okay.

Are there any new lessons at all that come out of the Benicia and Texas City outages?

Sure.

I can comment on both of those outages.

In the case of Benicia, what we had was a screen failure in the catalyst bed support system in one of the reactors.

The screen was found in a thin condition.

We renewed it.

As a matter of fact, we went to double layers on the screen.

I think that was the case where we had unanticipated wearout.

We would have replaced it in the next scheduled turn-around.

So it's rather a specific failure that was very, very simple to resolve.

In Texas City, we had a combination of problems.

We had to replace catalyst due to two events.

In one case, we had some fines in particulates from the old catalyst load which we failed to identify in the catalyst change-out.

Upon start-up, we swept those fines into a downstream reactor and created high pressure drop, and I think that is just a matter of being more diligent in the reactor clean-out procedures.

We also have a separate problem with conditioning of the new catalyst load which created coking and high pressure drop and we went and modified our start-up procedures to correct that.

I want to emphasize that we do know how to start up and turned around these resid finers, and I use by example the Corpus Christi resid finer catalyst change-out that was completed in 16 days very effectively.

So -- you know, but we have addressed the primary issues in both of those outages.

Good enough.

That's very, very clear.

It's -- even after all these years, there's still a learning curve, I guess.

Thanks very much.

Okay, John.

Your next question comes from the line of Andrew Fairbanks at Merrill Lynch.

Please go ahead.

Oh, thanks.

I made it.

Thanks, guys.

Just perhaps one last clean fuels question. $1.2 to $1.4 billion in spending seems to be a little bit higher than what you've talked about in the past.

Is that adjusted just for the expectations of what the O'Ryan or St. Charles plant clean fuel spending will be, or were there other changes also going on around the surface there?

And then just a larger strategic question, looking out at next year.

You've mentioned that, you know, your debt-to-capital ratio is basically where you want it to be.

What would the prioritization be for free cash flow being generated?

Would you look at share repurchases, additional acquisitions?

You know, what area would be receiving the highest priority in your mind?

I will answer the first question.

Yes, St. Charles is in there, but we also are higher on our distillate spending, or what we anticipate we'll spend on distillate, somewhere in the neighborhood of $150 million.

Primarily because a lot of the distillate capital for our low-sulfur was very preliminary estimates that have been given out.

As we've gotten into these projects, we have off-site expenses that we hadn't considered.

So as we scope them and starting to get them fine-tuned, we're spending on distillate Tier 2 will be about $150 to $175 million more.

On the second part, you know, the capex guidance we're giving for next year is probably $1.3 to $1.5 billion.

Again, we don't know how much we're going to carry forward from this year into next year.

It looks like the cash flow will be ample to fund the capital.

So, you know, the excess cash will be really used to reduce debt for next year.

Did a little bit more.

And then finally any last thoughts on the Aruba plant?

Yeah, we're -- you know, we are interested in Aruba.

We are one of the finalists.

We have gone into the data room.

We are visiting the refinery next week.

There's a lot of synergy between the refineries, our refineries on the Gulf Coast, moving intermediates.

So we're very much interested in the refinery and, you know, it's kind of like the O'Ryan refinery.

I mean, they have put a lot of money.

Coastal invested about $640 million in that and the last two years they have spent $140 million.

They just completed a big major turnaround.

So, you know, we think it has a lot of potential.

That's great.

Thanks, Bill.

Your next question comes from the line of Jennifer Rowland of J.P. Morgan.

Please go ahead.

Hi, I just have another question about Capex.

What were the capital expenditures this quarter?

This quarter, they are roughly about $290 million.

Okay.

And what's the outlook for next quarter then, for the fourth quarter?

Well, we have about, probably about $300 million is in our forecast, a little bit over $300 is in our forecast.

Okay.

And then just another question on hedges.

I know you gave the numbers for distillate.

Are there any hedges on gasoline for the fourth quarter in '04?

For the fourth quarter we have about 9% of our gasoline east of the Rockies hedged.

We do not have any hedged for next year.

Okay.

Thank you.

Your next question comes from the line of Charles Brunie of Brunie Associates.

Please go ahead.

Kind of naive, but I remember you talking about how the change in '06 with the -- from imports to exports.

Could you talk -- could you put those in percentage terms?

What is -- I don't know what imports are from Europe, and what do you think exports will be from the U.S. or they are dropping imports or something in that vein?

We have never talked about exports.

Okay.

As a product.

We've always talked about the refining capacity in the U.S. being limited and not growing to meet the demand and being more dependent upon imports and, you know, if you've got gasoline growing, you know, let's say 1% next year, you are talking about 90 -- close to 90,000 barrels a day, and that's the equivalent of a world scale refinery.

So refinery imports, or gasoline and distillate are both having to have to increase significantly in the future.

And what percent of -- you said imports are 7% of U.S.?

Right.

Okay, okay.

And that goes down to 5 or zero?

Well, it will keep going up.

The import percent will continue to increase.

I thought the sulfur change was going to make it that the imports went down.

Well, the imports will come in.

There are countries that are making the capital.

Canada.

Okay.

And the Caribbean.

And what will happen is the prices are going to have to be attractive enough to draw these imports in which will cause our margins to increase.

I understand it now.

Okay.

Yeah, they will find a home, but it's going to be expensive.

Okay.

Got you.

Thank you.

Your next question comes from the line of Andrew Rosenfeld of Prudential Equity Group.

Please go ahead.

Good morning.

Bill, I was wondering if the Tier 2 and MTBE is effective January 1,is it possible the recent strength that we're seeing in the gasoline market's really a function of the refining system getting ready for January 1, and really the next big data point that we should be looking for in terms of the big change in this is for the summer driving season which would be around March or April?

You know, I think what's happening right now and we talked about when this change would occur, you are probably going to see the other one happening more in December than today.

I think what you are seeing today is you are seeing just a lot of refineries that are down for a turnaround but you are seeing a lot of refineries that went down for unscheduled downtime, and I think that's what's happening with the market right now, and as you know, gasoline inventories are very tight.

Okay.

Thank you.

Your next question comes from the line of John Zhoringer of Lumas Sales.

Please go ahead.

I thought I heard you say that you had pretty much reached the end of the road in terms of managing down to debt-to-cap number, but then shortly thereafter, you told, I believe Andrew Fairbanks that any excess free cash flow that you would have after Capex for next year would go to debt paydown.

Could you clarify that part of your remarks?

Well, we're at, what, 42% now?

At the end of the quarter we're at 42.

Okay.

And so we're talking about the in the low 40s.

So if we get down to 40%, that's about where we would like to be, 40%, 42%.

Again we're not going to have -- you know, when you look at the capital program next year, there's not going to be all that much free cash flow.

So basically you might trim your current debt-to-cap number, but you are not going to go try to take it, drive it below 40%?

No.

Okay.

Secondly, do you have any plans in line to reduce some of your off-balance sheet debt-like liabilities?

You know, we have already this year brought a lot of items on the balance sheet.

Mike, do you want to cover some of those?

Yeah, we have terminated a couple of leases.

I think the total amount was about $200 million, and brought that back on.

Presently our balance is 1.2 million.

None of these mature next year.

They are all in 2005.

And we will be evaluating whether or not we want to bring them back on our balance sheet.

Around where is your pension fund status currently?

Pension fund?

At the end of this year, our projected benefit obligation is $720 million.

As of -- at the end of the quarter, we had $424 million in the plan, in our assets.

So that was about 59% funded, but if you look at our current liability funding, we're over -- we're in excess of 90%.

Okay.

So you don't anticipate making any cash contributions?

This year we made a total of 119 million, and that's included in the 424 million that I mentioned earlier.

Okay.

Nonetheless, the agencies are going to look at the deficit in your funded -- unfunded liability as a debt-like obligation and you are not planning to do anything in the near term to try to cut that liability down, or you might just allow the market time to come around to kind of close that funding gap by raising interest rates and appreciating your capital assets?

No.

Okay.

Thank you very much.

Our final question comes from the line of Mark Gilman at First Albany.

Please go ahead.

Hi, this is Mick Chow for Mark Gilman.

Could you talk about hedging impacts in the quarter by system?

And there's another question after that.

I'll give you the hedging impacts.

It's not necessarily by system.

In the third quarter, we had speculative trading profits of 8.3 million.

In our heat class position, we had a profit of $17.5 million.

Gasoline cracks was a profit of $3.8 million.

We lost a little on pre-buying and natural gas.

So that total for hedges was $20.8 million.

Okay.

And that's the paper side only.

Of the hedges, right?

And, I'm sorry.

How does that reconcile to 8.3?

Now, the 8.3 is straight spec trading.

Okay.

Classified accounting-wise as spec trading.

So really we had, you know, just summarizing, we had 8.3 spec trading plus 20.8 in hedges positive.

Correct.

So it was $29.2 million.

I got it.

The second question is regarding the coker again at Texas City.

Where does the EBITDA stand versus the minimum guaranteed margin?

I think on the contract itself as it relates to the discount, you know, we don't need the protection on the contract.

We're making more than the bottom side.

So that doesn't play into the economics at all.

The discount on the MIA crude today is in excess of the price protection.

Okay.

So I guess in other words, your $80 million EBITDA is about the EBITDA on the basis of minimum guarantee?

It's based on where we see the minor crude discount today and then going through the whole refinery as John Hohnholt explained taking the resids and everything else through the procession -- process.

But it's above the minimum in the contract.

That's correct.

Okay.

Thanks.

Gentlemen, that was our final question.

Please proceed with your closing remarks.

I would like to say thank everybody for listening and if you have any follow-up questions, feel free to give myself or Eric fisher a call.

Thank you.