瓦萊羅能源 (VLO) 2003 Q1 法說會逐字稿

Good morning and welcome to the Premcor 2003 First Quarter Release Earnings Conference Call.

All participants will be able to listen only until the question and answer session.

This conference is being recorded.

If anyone has any objections, you may disconnect at this time.

I would like to turn the call over to Thomas D. O’Malley, chairman and CEO of Premcor.

Sir you may begin.

Good morning, it is Tom O’Malley here.

With me are Bill Hantke, Premcor’s CFO and Hank Kuchta, our president and COO.

Bill will review Premcor’s first quarterly earnings and our present balance sheet.

Hank will provide a brief operational review, and I will use this opportunity to review our first year as a public company -- in fact today is our anniversary, one year.

I want to comment on the market and our prospects for the balance of the year and try and provide you with a roadmap for our future growth.

Bill.

Thank you, Tom.

Good morning.

For those of you on the call I would like to remind you that in addition to talking about our first quarter results we may make certain forward-looking statements that deal with our expectations.

Actual results may differ from those that we currently expect, and the factors that could cause actual results to be different are described in our earnings release and in our filings with the FCC.

I am going to assume that everyone has read this morning’s press release which is also available on our website, www.premcor.com.

I will comment mostly on items of particular interest to those trying to analyse or model the company’s financial results.

I would like to focus on what we call net income from continuing operations before special items, as that gets to the core of how we think the company should operate on a normal basis going forward.

On that basis, Premcor earned $55m, or 80 cents a share.

You should note that this figure includes a non-cash stock option expense of $4m, or 4 cents a share after tax.

Excluding stock option expense, we would have reported 84 cents a share from continuing operations before special items.

We point this out because this is an expense that we record that most of our peers do not, and we believe this is relevant for comparing results.

Let me also point out that in this morning’s press release, as well as in this conference call, we make references to our SEC filings and encourage you as always to review those filings thoroughly to get a better understanding of the company and our industry.

Premcor’s 2002 annual report on form 10K has been out for about a month now and our first quarter 10Q will be filed later this week.

Onto the numbers.

Our first quarter gross margin of $267m includes some hedging activities which were neutral to the quarter’s results on a with and without basis.

As we had pointed out in our SEC filings, you should keep in mind that the hydrocarbon price environment and in particular its volatility could have a significant impact on Premcor’s short-term results that cannot be seen simply by looking at the daily market indicators.

The first quarter’s operating data includes the Memphis refinery for only 29 days starting on March 3rd.

This means you should adjust Memphis reported throughputs and expenses accordingly when modelling its future contribution.

If you review our initial analysts’ presentation on Memphis from November 27th, 2002 which is also posted on our website, you will find that our initial assumptions on the refinery’s operating costs have held up well.

First quarter operating expenses reflected higher natural gas expenses of roughly $22m versus the first quarter 2002.

As pointed out in the press release, our natural gas for the quarter were $6.32 per mmbtu against a benchmark and quarterly average of $6.05.

As you analyse the company’s expenses going forward, you should keep in mind that we purchased $29m mmbtus per year, so you can do the math on the effect of our operating expenses of a dollar change in the price of natural gas.

Otherwise the operating cost structure for each facility going forward should look roughly like it did in the first quarter.

Again, you will need to adjust Memphis for the 29 day operating period this quarter.

First quarter G&A excluding stock option expense was around $12m, which includes a $1m incentive compensation accrual.

Going forward, we expect 2003 G&A to be roughly $52m excluding bonuses and stock option expense.

Our stock option expense estimate of $17m to $18m for 2003 has not changed.

First quarter depreciation and amortization of $24m includes one month depreciation on Memphis.

Had we owned Memphis for the whole quarter, D&A would have been about $27m.

Going forward, depreciation and amortization should continue at approximately the first quarter adjusted rate, increased for capital expenditures.

When calculating depreciation, we use an average useful life on major projects of 25 years and turnaround approximately four years.

Annual gross interest expense should run about $114m, less capitalized interest.

Tax expense should continue to be booked at a rate of approximately 37 percent.

Premcor continues to use large expenses net operating tax loss carry forwards to shelter taxable income and therefore does not pay federal income taxes to a material degree.

The balance of that NOL at the end of March was $460m.

Turning to special items.

I would like to comment on our large and discontinued operation.

The after-tax charge of approximately $4m relate to 30 retail site leases we assumed in connection with the bankruptcy hearings of Clark Retail Enterprises.

The purchaser of Premcor’s former retail operations in 1999.

There may be changes to this reserve, including the possibility of accruing additional liabilities in the future as CRE works through its reorganization plan and as determinations are made about environmental liabilities for the leased sites.

The amount of such changes cannot currently be estimated.

Pursuing our capital program for 2003, first quarter capex is approximately $22m not including the Memphis acquisition.

The Memphis acquisition was a total of $475m, $160m of which was hydro carbide inventories.

Turnaround expenditures were approximately $9m in the quarter.

We expect the remaining 2003 capex and turnarounds to total approximately $200m to $215m including spending on tier 2 low sulphur fuels totally $100m.

Our tier 2 investment is currently expected to total $682m, of which $335m is gasoline, and $347m is for diesel.

About $70m of this total have been spent to date.

Onto our balance sheet, the March 31st balance sheet continues to show improvement over earlier periods.

Our debt to capitalization ratio dropped from 56.7 percent at December 31 2002 to 52.7 at March 31st 2003 as a result of our quarterly earnings and our securities offerings during the period.

In connection with the Memphis acquisition, we raised $306m in net proceeds from common stock offering and $525m in new long-term debt of which $282m was used to retire existing short-term debt and high cost debt.

Our only significant remaining amortization over the next five or six years relates to our 12.5 percent debt at PAC, this is a sinking fund note and we are, as always, happy to pay off an expensive debt at 12.5 percent.

The current year’s payment is about $14m.

It escalates after that.

Cash for March 31st is $312m plus restricted cash of $54m, giving us a total of $366m.

Also during the quarter we amended our credit agreement to provide us with a three year, $750m price capacity, including $200m in permitted direct cash borrowing.

We currently have no cash borrowings outstanding.

Finally, for modelling purposes we now have 74.1m common shares outstanding and our diluted share base is roughly $1m more than basic.

I will now turn it over to Hank Kuchta, our president and COO with some additional comments on operations.

Good morning.

I am going to provide a summary of our operations in the first quarter, but first I would like to review the general industry climate that existed as the quarter began, and to some extent remain intact through the end of March.

There were at least three major factors that impacted refining operations, and consequently helped industry margins during the quarter.

First of all, there was a heavy maintenance program scheduled in pads 2 and 3 which impacted crude and product inventories.

Secondly, there was crude supply uncertainty associated with the events in Iraq and Venezuela.

Finally, we actually had a cold winter here in the Northeast and the Midwest.

Needless to say, Premcor enjoyed a certain level of economic benefit associated with these market conditions, but we also recognized some negative earnings impacts for virtually the same reasons the general market was strong.

Specifically, Port Arthur and Lima underwent planned and unplanned maintenance on various units at the refinery during the quarter.

In addition, all three of our refineries had their crude purchases restricted at times in the quarter due to the high absolute prices and extreme backwardation in the crude market.

Lastly, because of the cold weather, we experienced high natural gas prices at Port Arthur and Lima which Bill has already commented on.

Now we will review quarter numbers.

In the first quarter, the average crude oil throughput at Port Arthur was 244,000 barrels per day (bpd), which is only slightly lower than the refinery’s rated capacity of 250,000 bpd.

In January, crude rates were restricted to 230,000 bpd for economic reasons.

For this reason, we took the opportunity to complete some unplanned maintenance which we derived benefit from later in the quarter.

By late February, rates hit 260,000 bpd at Port Arthur as Gulf Coast cracks and sour crude differential strengthened.

In March, we actually set new processing records at the crude unit [Annacoker].

Looking forward to the second quarter, there is no major maintenance planned at Port Arthur, therefore we expect to operate at or above first quarter levels.

The story is essentially the same for Lima.

In January, the crude rates were restricted to an average of 134,000 bpd for economic reasons, but by mid-February rates hit 150,000 bpd as Chicago crack strengthened.

These high rates were maintained until the planned FCC turnaround began in late February.

The maintenance on the FCC was estimated to take 14 days originally, but due to severe weather was extended to 18 days.

As for the second quarter, we have completed addition maintenance in April which restricted rates during the month.

We expect to be able to run in the 145,000 bpd to 150,000 bpd range for the balance of the quarter.

The Memphis refinery was successfully integrated into our operations for the month of March.

Rates there averaged 164,000 bpd for the month and have reached 170,000 bpd in April.

For the record, the FCC is operating well after the turnaround taken by Williams in February, and as for the second quarter, there is no major turnaround activity planned on the major units.

Therefore, we plan to continue operating at 170,000 bpd which is consistent with keeping the conversion units full.

The operation of the Hartford terminal in conjunction with the Memphis refinery is expected to provide economic benefit to the company, and we saw evidence of this in the early days of combined operation.

For example, we have shipped less stocks to Hartford from Memphis to supply low RVP gas to St. Louis, and we will do similar operations into Chicago.

Our announced plan to sell certain assets from the Hartford refinery to Coneco Phillips will not impact this business.

I will now turn the discussion over to Tom.

Thank you, Hank and thank you, Bill.

As I mentioned in my opening statements, Premcor has been a public company for about a year, having completed our IPO on April 29th.

We are not a company that celebrates very much, but we will probably buy the two guys here assembled free sandwiches for their work over the past year.

The road show and various presentations prior to Premcor’s IPO provided a roadmap we have been following very closely.

We indicated we intended to shut down our Hartford refinery given its small size and large standing business investment requirements.

We just could not come up with a scenario that would justify continuing operations.

We completed that task in October and recently announced the sale of certain operational units at Hartford to Coneco Phillips for $40m.

We are certainly pleased that some industrial operations and jobs will continue at this site.

We strongly emphasis the need for an improved balance sheet and we have made progress in that regard, but we intend to continue to do everything we possibly can to improve the company’s credit standing.

This is a business where you need an investment grade credit rating.

We instituted a significant cost-cutting process and that certainly has contributed to the company’s profitability.

We said from the get go that we wanted to grow our business, and as Hank mentioned, the acquisition of the Memphis refinery in early March was the first step in that process and it has certainly been a successful step.

In our view, U.S. refining markets will continue to show some level of volatility, but it is our belief that there is a clear bias to the upside in refining margins.

Inventory for gasoline and the other products that we produce are generally at record lows, and crude oil prices have declined to what we consider to be a more level, at least within OPEC’s intended range.

The lower absolute crude oil price should encourage further growth in oil product consumption, and should improve our general economy.

The start of the reduction in sulphur content in gasoline at the beginning of 2004 will, we believe, restrict the number of refineries worldwide who can export to our market.

Progressive reduction in sulphur levels in gasoline and diesel over the next three years will have a beneficial impact on the environment and will, we believe, offer a greater return to those refining companies who are making the investments necessary to produce these cleaner fuels.

Our press release indicates that we believe the second quarter results for Premcor will be satisfactory, and we remain cautiously optimistic, whatever that means, for the balance of the year.

The oil product business is a macro economic activity.

We are dependent, clearly, on how the economy is going.

If we start to see some expansion in our economy, we will undoubtedly see more robust demand for oil products.

Again, I think the drop in the crude oil price is in essence a great tax reduction and should stimulate the economy somewhat.

We can never be sure of how we are going to do in a particular quarter, there are too many factors moving around, but I think the future looks pretty bright.

This is certainly not a business I would recommend anybody investing in for quarterly certainty.

We have built a small but excellent team of experienced executives and I certainly look forward to being part of this team for quite some time to come.

It is our desire to grow value for our shareholders.

In that connection, we continue to be interested in acquisitions, but we continue to follow our rules that acquisitions have to be accretive to earnings.

We also continue to work on internal projects; small ones which every refinery has lined up to do, but certainly projects internally have to be financed to the greatest portion internally.

It is encouraging to see the results that we are seeing now that we are building some cash in the company, that this allows us to do some small, very high rate of return projects.

We have continued to work on something that we mentioned when we did our road show when we first came public, and that is souring of our Lima refinery.

We haven’t arrived at a decision point but the plans are coming together.

I think it will be the better part of a year before we finalize anything in that regard, but it does look pretty good.

We have one other big internal project and that is, in the words of one of my former colleagues Dwight Wigg at the old Altasca company, low hanging fruit.

That would be an expansion of our Port Arthur refinery.

We can very economically expand the coking capacity there and that could lead to an expansion in the overall plant at a very high rate of return.

Again, this is a project that is off a year from a decision point of view, but I think ultimately it will happen.

We continue to look at all the refineries that are for sale out there.

We are not confused improved margins have raised the expectations of the sellers, but the other side of the coin is that we don’t think there are so many qualified buyers and we think in most cases the decision to sell by people is not one that is absolutely tied to the last dollar.

I have been around this business for many years, too many in some ways, but frankly I have never been more certain that the table is set for a longer term improvement in refining margins.

We will be happy to take your questions at this time.

Thank you. (Operator instructions) The first question comes from Mr. Doug Terrason with Morgan Stanley & Co.

Good morning, Tom and company.

I have a couple questions about operating costs, specifically at both Port Arthur and Lima you were obviously squeezed by higher natural gas prices, although it seems that lower costs elsewhere in the system served as an offset.

My question regards the identity of some of those items, and also clarification on some of Bill’s comments.

I want to see if we can get him to restate what was said about operating cost expectations for the three plants for the remainder of the year, if that is what he said.

Also, the price of natural gas that you are using in those projections.

Doug, it’s Bill.

Let me get to the right page.

Operating expenses.

We expect, aside from natural gas, we would expect them to trend the same as the first quarter for the rest of the year.

There are always moderate increases here or there, we expect that.

What was the other part of your question?

Well, it seems like you worked in allowances for natural gas prices at Port Arthur and Lima, obviously, but when you back in the effect of those price increases operating costs should have risen by more than they did, but they didn’t.

So that implies that there were cost reductions elsewhere in the system.

I just wanted to see if you could identify some of those.

One of the things we did here was actually lower the amount on natural gas that we use, particularly down in Port Arthur.

We succeeded in cutting our natural gas usage at that refinery by about 15 percent, starting in the beginning of February.

So that had some beneficial impact on the overall operation.

As for what is the budget going forward for natural gas, I think given the market that we see it is really hard to balance for the rest of the year, much less at $5.00.

That is $2.00 above our original.

It is a very sad factor.

It has a positive side.

We are seeing, throughout the energy market, substitution.

I think one of the issues that has been driving the middle diffluent consumption has been substitution of middle diffluent for natural gas in power operations, in a number of operations.

That certainly has impacted.

So there is clearly a negative side and we are not absolutely sure about what to do about the negative side.

There is some positive side.

Margins have adjusted, it seems, across the industry to adjust for those higher costs.

Along those same lines of the comments you just made, Tom, you talked a little bit about the press release, your gas purchase contract expiring in August.

If those were to expire today, for instance, do you have an order of magnitude idea what benefit to operating cost would accrue to the company?

Yeah, I have a very clear order of magnitude.

Nothing at the present time.

I think that is the clear answer.

I don’t think the contract that we have, absent it’s real pricing provision, is outside of the market norm.

The pricing provision, like many of these contracts, we price on the first day of the month.

That, particularly for the month of March, was very bad news because on March 1st the natural gas price was $8.00 plus.

I think it is a problem that our industry is going to have to deal with.

We have all benefited from 15 or 20 years of $2.00 or $3.00 natural gas.

I don’t think too many of the non-integrated companies have sat around and thought about this, what do I have to do to assure myself on the cost side of the equation.

Certainly I know at my last company we didn’t fantasize over that particular thing.

But when we look forward now we are really looking at a natural gas market, longer term, that we think will be driven by imports.

I think that probably means $4.00 north natural gas.

We have to come up with a game plan to work that, whether that means buying from somebody who wants to establish a significant import outlet -- remember, our natural gas, our big point of consumption is at Port Arthur.

Eighty percent of what we consume is right down there.

It might be an ideal company to sign up on an L&G contract.

Okay, thanks a lot guys.

Our next question comes from Mr. Arjun Merdy, with Goldman Sachs.

Thank you.

Two somewhat unrelated questions.

First on the Hartford sale, certainly seem very logical for both yourselves and Philips there.

I wonder if you have any sense or idea whether in return they would be looking to sell you any of their refineries, I suppose something like Alliance comes to mind.

I also assume there is no change in your general strategy for refining that position as the larger facility, et cetera.

And then a larger question in terms of the magnitude of natural gas use you can switch out on say a daily or weekly basis.

You mentioned the 15 percent reduction at Port Arthur.

How much could you reduce natural gas consumption if you wanted to, and how quickly could you do it?

Bill will answer the last piece, I will do the first piece.

The most we could really reduce is 15 percent, which is the amount we ramped up to in February and in March.

Principally, it is propane vaporization in a sense.

You take propane and your absorbent gases and just run the towers hotter and basically roll it over into your natural gas grid.

I wouldn’t expect that we could do much better than that.

That is for the system, or just Port Arthur.

Well Port Arthur is in essence --

It is the same issue in both places.

And we don’t really buy natural gas for Memphis.

Of the total that we buy, 20 percent is up in Lima, so if you look at this, this is a Port Arthur issue and that is pretty much where it is at.

Look, I think the transaction with Coneco Phillips seemed logical to both companies and we certainly were pleased that we were able to do it.

We are pleased to have an ongoing operation on the site for many, many reasons.

We are interested as a matter of principal in any large refinery that is up for sale in the United States.

We look at just about everything.

I am not aware that Coneco Phillips is offering anything at this moment in time, but certainly if they did we would appear on the list of people who would take a look at it if they gave us that opportunity, and I think they would.

Great.

Thank you very much.

Thank you.

Our next question comes from Mr. Fred Luffer with Bear Stearns.

Good morning.

I had a follow up question to Arjun’s question and then a few of my own if I can.

If you run propane and you run the tower hotter, what is the impact on product volume output?

Product volume at Port Arthur, about a percent-and-a-half to 2 percent.

And how much of that would be gasoline?

Rateable or specifics?

I am not sure I understand what you mean by--

In other words, is that coming out of the gasoline pool, or --

That is just coming out of your L&G pool.

You aren’t losing anything on gasoline.

No loss on gasoline.

All you are doing is just driving some additional molecules up into the fuel gas system.

Right, okay.

That is what I thought.

Do you -- can you tell us what was added to the tracking account balance in the first quarter?

It is currently $150m.

I forget what year end was, but it is up to $150m at the end of March.

What was the impact of hedging in the quarter?

What risk management tools are you using?

There is a reference to it in the release.

Look, we like many other companies, have to buy domestic crude each and every month.

Domestic crude, the buying process, finishes quite a long time before you sell the product.

The mercantile exchange, some terminal market trading, generally ends on the 20th of the month preceding the month of shipment.

In that case, if you took the midpoint of the month of shipment as the 15th of the month, you have in essence priced out all your crude 25 days on average before you are going to sell it.

So you are at a price risk in that period of time.

You can attempt to hedge by selling the next month forward, but if you are in a backward dated market, and indeed we have been in a backward dated market for the last couple of years -- that means the pump price is higher than the next month forward, there is a cost associated with that hedging activity.

In the first quarter of the year we did do some hedging of our operation and the cost of that hedging which probably ran up in the $15m to $16m category was made up by the money we saved when the oil price dropped.

So the absolute result was neutral.

It is a decision that is very hard to make when you get into a situation where you see the backwardation stretch out to $2.00 a barrel, you have to apply some judgement.

Is the risk greater, or should you just take the risk?

So that is a constant battle that we have intellectually with ourselves and among ourselves.

Of course it is a larger battle now because in the first two months of the quarter we were buying domestic crude principally for our Lima operation and there you were talking in terms of 4m to 4.5m barrels a month.

We have now added Memphis which at least in the early stages was primarily a domestic refining complex so that number went up to the 9m barrel range.

The problem has, to some degree, been ameliorated looking forward, because if you look at the crude price stretching out over the next seven or eight months, the amount of backwardation has really come in.

That has come in with the absolute price of crude oil.

So I think it has eased off, certainly in the first period the drop has been rather rapid.

So we try honestly to stay away from a lot of motion in the market place from a lot of hedging activities.

It is an expensive game and it distracts us from what we are doing in a basic operation.

Just one more.

The margin uplift at Memphis, Tom, I think when you closed the deal or announced the deal, you indicated that you thought the margin there would be something like a Gulf Coast 2.11 plus about 63 cents a barrel.

I guess you are getting some further uplift here from the Hartford terminal.

We are getting a little bit.

I would hate to quantify what it is going to be based on 60 days of operation, and based on an absolutely nutty marketplace over part of that time, but it looks like our 63 cent number will be a conservative number, but it is not conservative by -- you know, we are not going to get a dollar uplift.

It is conservative by 10 cents or 15 cents.

That would be good enough.

Just one really last one.

Do you have current assets and current liabilities.

Bill is in charge of that.

I have working capital, which is $232m.

And that is the net of the two?

Right.

Someone is handing me one, hold on a second.

Numbers are flying here.

Current assets, $1,468m.

Current liabilities, 69.7.

And that, by the way, came from the CFO in waiting, Cheryl Watson who Bill does not walk in front of Cheryl when he is on the street in NYC because Bill could be pushed in front of a bus.

Our next question comes from Mr. Mark Flannery with Credit Suisse First Boston.

I just want to get back to the hedging.

You got a neutral out of it this quarter, but without that crude oil price drop at the end, that could have been a pretty expensive program for you.

Now I know in the filings that you do you kind of give guidance along the lines of programs that are on the take, and here is the mechanism.

Is there anything more you can give us on that in terms of a rule of thumb?

You just said you didn’t want to make a lot of motion in the market, but it is potentially a big number.

Honestly, you were talking -- and funny I would ask you what you would have done.

Look, you had $36, $37 crude oil.

As a rule of thumb from our perspective, if you go north of $30 we think you are getting into -- $30 for WTI -- we think you are getting into territory that is above OPEC’s stated publicly level where they are not comfortable with it.

And since they are the biggest individual factor in the market, we think they have an important position there.

So really, as a rule of thumb from our perspective when you see numbers north of $30, we really get intensely interested in that subject.

As you go south of $30, our interest drops.

I also would say to you that when you see the cost of a backwardation hedge drop down into the 10 cent or 15 cent category, then my guess would be a prudent company would probably use some of that strategy going forward.

When you start getting up into the dollar plus category on backwardation and let’s say the price is below $30, you have to ask yourselves the question; do you really want to do that?

So it is very hard to set a rule without reading the tea leaves each day.

For instance this morning I am sure you are aware that there is now renewed chatter within OPEC that they want to drop it by another increment.

You know, in years past we tended not to take OPEC as seriously as perhaps we do today.

We should recognize that OPEC has been pretty successful with their programs, even though you may get individual cheating from a macro point of view, they have managed to adjust supply to the market.

So we take everything into consideration and try to act prudently.

I don’t think we can give you a lot more guidance than that.

Okay.

Thank you very much.

Our next question comes from Mr. Paul Chen with Lehman Brothers.

Good morning.

Tom, can we assume that right at this moment you do not have a meaningful hedging or trading position outstanding?

I think that is a pretty good assumption.

Secondly, on Port Arthur, if I look at sequentially from the fourth quarter, your realized margin is up maybe about $1.38 but the WTI, defence is widening by about $1.48 if we waited that was affected by a contribution of $1.20 in improvement.

That seems sequentially that you really didn’t take advantage of the widening in margins for the gas.

One thing that you have to take into consideration is that higher oil prices in an absolute sense --crude oil prices -- are a negative at Port Arthur because Port Arthur is a large producer of petroleum coke.

About 9 percent or 10 percent of the absolute make at Port Arthur comes out as petroleum coke.

You can say that each ton of petroleum coke has about five barrels of oil in it.

If you get say an $8 increase in the oil price and I think you are very close to that on average, you can say yes the petroleum coke price went up during that period of time, it probably went from $10 FOB the plant up to maybe even $20 FOB the plant, but you only recovered a very small fraction of the increase in the raw material cost for that, and what is the raw material cost?

The raw material cost is crude oil.

I can say to with great conviction that we are extremely happy with lower absolute oil prices.

Having the oil price down at $25 and then with the differential for [mire] bringing it under $20 is a great benefit to us when comparing it with the absolute oil price north of $30 in the first quarter.

So that is a bit what worked in that calculation.

In fact, I think our overall recoveries at Port Arthur, our clean products were marginally a little bit better in the first quarter, and Port Arthur is running, I may say, better than at any time in its history.

Port Arthur, for the month of March, exceeded 260,000 bpd.

We have achieved record rates on the coker and we continue to run that plant very well.

We’ve managed to wrap our arms around it and get better results than frankly we would have forecast when we took the company public.

Tom, do you have a raw number, how much is the loss with each of the petroleum coke sales?

Sure.

You can formulate that, because you can take -- if you make the assumption that a ton of petroleum coke sells FOB the plant at $20, that is $4 a barrel.

You simply can go on and say, well what is the crude oil price?

If the WTI price is $26 and the [mire] TI differential is $6 on a delivered basis, then you can say you have lost $16 a barrel.

That is the problem with every coking refinery that makes fuel grade coke.

If you make calcium coke, the loss is a little bit less because calcium quality coke sells at a higher price.

Our actual coke production down at Port Arthur runs almost up to 11 percent of the input number of crude oil.

If I could have two last questions.

One, for the tier 2 I think you have mentioned a number.

Can you just repeat what is the tier 2 spending requirement.

Also, when I am looking at the DDA, the three refineries total is $20.5m for the quarter.

Your total corporation is $24.1m so that implies the company is about $3.6m for the quarter.

That seems to be a bit high compared to the past.

I mean, is there any particular item that has kicked in?

I do want to tell you that the company has not bought me a 747 jet and we are not depreciating that so we will switch it over to Bill.

Maybe they should consider that.

Bill.

First on capital, tier 2 in total, this is spending from now through 2007 is $682m.

The split on that is about $335m for gasoline and about $347m for diesel.

To date we have spent about $70m of that.

In regard to depreciation, other things included in there are the terminal activities.

We depreciate Tom at $3m a year, so that gets expensive -- that is a joke.

I am sorry.

It is really the terminals, corporate headquarters, the amortization of lease improvements in general.

Nothing fancy.

Yes, but in the fourth quarter of last year that number is much lower, isn’t it?

I am just looking right now.

Let me see.

Where is the fourth quarter?

Sorry.

If you are asking the question do we have corporate depreciation of $12m a year, four times $3m, the answer is no.

The principal depreciation that we have in the company relates to the refineries.

The amount that we have tied up in corporate office is minimal.

On a comparative basis, I am just comparing last year’s first quarter now, depreciation is up $2.1m from first quarter 2002 to first quarter 2003 and amortization is about the same.

All right.

Very good, thank you.

Bill and Joe will both look at the number and clarify it to anybody who wants to call on that.

If you have further questions we will give it to you, but we don’t have anything in the corporation that would result in large depreciation.

Our next question comes from Mr. Mark Gillman with First Albany.

Hello, this is Mike Chen for Mark Gillman.

Most of my questions have been answered.

About the interest expense, sequentially it went up the first quarter of 2002 to the first quarter of 2003.

Was it driven by increased debt?

Yes, it was increased debt.

You might remember that we borrowed the money slightly in advance of the Memphis acquisition, and before we knew we were capable of some of the short term and longer term debt that had to be called.

So we had a period of time in there where we actually had debt outstanding on both issues.

That is why it should come down going forward, we estimate the future at 114.

That is really the only difference.

And of course, we paid off different levels of interest rate debt.

Some was high at 11.5, some was very inexpensive as a floating rate debt.

And there is no change to the offsetting items that were used to get the net interest expenses?

That would be interest income and capitalized interest, the same as always.

Okay.

In the Port Arthur realized margin, would it, in the first quarter, was it affected by unusual marine costs?

Not significantly, because remember in our case our primary source of crude oil is mine crude oil coming from a short distance.

We have on long-term charter three specialized crude oil tankers, two of which operated for the whole quarter, one of which came on at the end of March, which kept our marine costs at a relatively steady level to move and mine crude.

Rule of thumb, we really look at freight costs of about 50 cents a barrel to move that over, and that is pretty much what we experienced in the first quarter.

We buy additional crude for that refinery, some of it is domestic, comes in by pipeline.

The balance generally we are buying pieces of cargo that have arrived on the U.S.

Gulf Coast.

There is always a bit of barging around.

We don’t really load crude oil to bring it into the United States at this moment in time.

Other people do that.

Given your crude buying practice and your discussion about the hedging there, could you quantify the impacts in crude costs versus the managed market?

Did you pay a number more than the benchmark?

I think you will see in the quarter our average prices paid, we pretty much listed there.

We have crude differentials to the benchmark in our press release.

At Port Arthur we have a net gain of about $125m and that of course relates to the fact that we are buying very heavy sour crudes and that makes up for the fact that we have to sell a lot of petroleum coke.

At Lima, which is a refinery located north of the WTI -- north and east of the WTI delivery point and which requires the movement of the crude oil to the refinery, and that movement by pipeline is at $1.00 a barrel, we had extra costs of about $17m which is very close to the number of barrels we bought.

At Memphis, we are pretty much spot on to WTI, a little bit better location and we do use some imported barrels there.

I think those indicators, particularly for Lima, you have to look at WTI plus a dollar to get Lima delivery.

Hank says to me, well more than a dollar.

I say to him, you better improve.

I think we will see some premium also of the Memphis.

We just did a little bit better than normal in that first month.

Of course, at Port Arthur it is a function of the [mire] TI differential is.

I regret to tell you that we are not the guys that set that everyday.

Thank you.

Our next question comes from Mr. John Zarringer with Lumier Sales & Co.

Yes, could you give us a little breakdown on your letters of credit situation in the first quarter and the borrowing base on your facility?

The borrowing base is not an issue.

The absolute size of the facility is $750m.

There is a credit that varies during the month.

Right now it is about $571m.

We have the capability of doing $750.

That was $571m, an end of quarter figure or current day figure?

End of quarter.

Thank you very much.

By the way, I should comment on that letter of credit facility.

Since it requires so much domestic crude that does tend to probably balloon on the payment date, and the payment date is the 20th and 21st.

In a normal month, the price of crude has dropped.

When crude was high we were getting up around $660m on payment day.

Okay.

We are, by the way, little by little gaining some trade credit which is another goal and objective of the company and that is relative to the company’s credit standing.

Excellent.

Our next question comes from Mr. Jay Saunders with Deutsche Bank.

A quick question on the coker at Port Arthur.

Where did you run it, average, in the first quarter?

Where did it peak out at and what do you think you will do on a sustainable basis assuming say $620m for WTI?

For the quarter we averaged just under 80,000 bpd.

For March we were actually just under 90,000 bpd for the average.

It is a factor of how much [mire] versus the incremental crude that takes us up to that 240, 250 or 260 range.

If we have 200 of [mire] and then we buy a lighter solid crude to balance it off, we may only be at 85,000 bpd by the time we hit a hydraulic limit on the vacuum pipes.

So really, it is a function of which incremental crude we are buying, which one is the most economic.

I suspect we will run in the mid-80’s just because the dollar differentials are going to be, I think, still fairly wide.

I mean they will obviously come in some, but I think there is going to be relative weakness on the sour crude, so we will be able to buy sour crude which will bring us to an 85 comfort range.

Okay, and in the first quarter, did you maximize the [mire] tape?

What was the portion of the slate there?

Yes, we maximized [mire] in the first quarter.

I think our average was right about --

Okay, thanks.

(Operator instructions) Our next question comes from Mr. Che Tail with Petrie Parkman.

Good morning.

Back on the acquisition question, you mentioned you were interested in any large, U.S. refinery.

Would you have any interest in offshore refineries, namely El Paso’s facility down in Aruba?

Well I don’t want to call Aruba part of the United States, but certainly the Caribbean basin is a supply point.

Any domestic refinery would be interested in capacity down there.

That is a refinery that I first looked at back in the 1970’s I believe, or maybe 1980 when Exxon had closed it down.

That is a complicated situation and I don’t think El Paso has clearly made up their mind on what they want to do with that.

I would tend to give preference to a continental U.S. refinery.

I also don’t want to rule out anything offshore.

We never rule anything out, particularly if it would be a tributary refinery in terms of supplying the U.S.

East Coast.

I think our real focus is on what is available here in the United States.

We think there are a sufficient number of reasonable refineries up for sale.

We completed the last acquisition about 58 days ago and it has been very smoothly absorbed so we are ready, willing and able.

Now we just have to find something that we can make money on.

Okay, thanks a lot.

Our next question comes from Mr. Fred Luffer with Bear Stearns.

What was capitalized interest in the quarter?

In the quarter it is relatively minor because of the spending, it is only $22m in capex and runs about $1m to $1.5m.

What do you think it will run for the year?

For the whole year 2003, assuming the capital program as stated happens it will probably be close to $14m to $15m.

Okay then, so you are basically still assuming that the interest expense remains flat at about $25m in the next three quarters?

Yes, with that assumption on the capital.

I am going to pick on my engineer friends, but they never seem to spend money as fast as they tell me, but if they do, those are the good numbers.

I think what is important, Fred, is our principal capital spending in regard to clean fuel is taking place at Port Arthur, which is the place that we have the larger sulphur content in our gasoline, a large sour crude oil refinery.

That money is going to be spent and that project is due to come on stream at the end of October, very first days of November.

It is smack on time.

We will be spending in the period from June to September at a pretty rapid rate, the majority of that money is going to go right out the door.

That is going to allow us to program our spending -- Port Arthur is going to come in with the sulphur content in its gasoline, under 30 tons per million, which you know, for a big sour refinery that is really going to help us out on the rates we have to spend on Memphis and Lima and help us also in terms of what else we intend to do at Lima.

Lima happens to be the exception.

Well, we’ll get some rate of return at Port Arthur from these investments over and above whatever it is you get on clean fuels.

Lima has, actually, fairly interesting rates of returns for the clean fuels products that we are doing up there, so we are bouncing balls around here a little bit.

Thank you.

There are no further questions at this time.

I want to thank everybody for attending Premcor’s first quarter earnings call.

I look forward to hearing from you again.

Thank you very much.