瓦萊羅能源 (VLO) 2003 Q4 法說會逐字稿

Good morning and thank you all for holding.

At this time, your lines are in a listen-only mode until the question-and-answer session of today's conference.

Today's call is being recorded.

If you have any objections, you may disconnect at this time.

I'd now like to turn the call over to Mr. Bill Hantke, Premcor's chief financial officer.

Thank you, sir, you may begin.

Thank you, operator.

Good morning everyone, and thank you for joining us this morning.

I'm joined on this call by Tom O'Malley, our chairman and CEO, and Hank Kuchta our president and COO.

As required, I would like to remind you, that in addition to our comments concerning the fourth quarter and year-end results, we may make certain comments regarding forward-looking statements in response to your questions that deal with our expectations.

Actual results may differ from those we currently expect.

And the factors that could cause those actual results to be different are described in our earnings release and our filings with the SEC.

As always, I will assume that everyone has read this morning's press release and I will comment mostly on items of particular interest to those trying to analyze or model the company's financial results.

As I give guidance on future core structure components, please keep in mind that the numbers I give do not include the effect of the pending acquisition of Delaware City Refining Complex announced on January 14th, 2004.

The items on the estimated impact of Delaware City is contained in the slides from our January 15th investor presentation available on our website.

I'd like to focus on what we call Premcor's net income from continuing operations including 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 13 million, or 18 cents a share in the fourth quarter. 165 million, or $2.24 a share for the year.

You should note that these figures include on-cash stock-based compensation expense or stock option expense as it's commonly called.

A 4.4 million pretax, or 4 cents a share after tax in the fourth quarter.

And 18 million pretax, or 16 cents a share after tax for the year.

We point this out because this expense that Premcor records, but most of our peers do not.

We believe that is relevant when comparing results.

Our stock option expense estimate for 2004 is 19-20 million, which will drop off to 8-10 million starting in 2005, due to a full vesting of significant options issued in 2002.

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

Our fourth quarter gross margin was approximately 240 million.

The fourth quarter results reflect weak refining margins in the Gulf Coast and midwest markets, and lower crude oil throughputs due to maintenance activity at all three refineries.

The gross margin for the year was approximately 1.085 million.

And we experienced four consecutive quarters of positive core earnings due to relatively strong margin environment.

And on average, the entire year, a solid operating results.

Hank Kuchta will describe our operations in more detail in a minute, including our forecast for the first quarter of '04.

Fourth quarter gross margin includes income from approximately $11 million related to the change in the value of our net long fixed price purchase and sale commitments including hedging effects.

Gross margin for the year, includes a course of approximately $28 million related to this issue.

This morning's press release singles out this impact and excludes it from our analysis of our individual refining operations, in order to reflect a clearer comparison of the realized margins to the market indicators.

As we have mentioned in our SEC filings, you should keep in mind our hydrocarbon price environment, and particularly its volatility, it can have a significant impact on Premcor's short-term results that cannot be seen simply looking at the daily market indicators.

Turning to operating expenses, natural gas costs remain above historical averages, our average natural gas cost for the quarter was $4.57 per MMBTU and 5.29 per MMBTU for the year.

Bench mark -- average was 4.94 for the quarter and 5.36 for the year.

These amounts are higher than we paid in 2002.

Our average natural gas cost for the fourth quarter of 2002 was 3.99, and for the entire year of 2002, 3.29.

As you analyze the company's expenses going forward, you should keep in mind that we purchase and consume 29 million MMBTUs a year.

We have taken steps to reduce our natural gas consumption, but the financial impact of higher natural gas prices is and will remain significant for Premcor.

Our natural gas costs for January '04 to date are $5.70 per MMBTU.

Turning to G&A, fourth quarter G&A excluding stock option expense was approximately $18 million, up from $7 million in the fourth quarter of '02.

Excluding a bonus accrual of 2.7 million, G&A was 15.1 million for the fourth quarter of 2003, compared to 11 million for the fourth quarter of 2002.

G&A expense for the year, excluding a bonus of approximately $10 million was 57.4 million, as compared to 52 million for 2002.

G&A expense, excluding bonus, increased from prior periods primarily due to increased employee benefit cost, professional service expenses associated while tax consulting, the Sarbanes-Oxley Compliance Project and our ERP systems implementation.

We expect first quarter 2004 G&A, excluding bonuses and stock options, to total roughly 13-15 million.

First quarter bonus accruals will obviously depend on the company's financial results.

Bonus compensation is based solely on our achieving net earnings in excess of $2.00 per share on an annual basis.

Our board of directors typically excluding special items, bonus expense and stock option expense when determining the threshold EPS number.

Fourth quarter and 2003 annual depreciation and amortization was 29 million and 106 million respectively.

In the future, G&A should continue to approximate the fourth quarter rate, adjusted for increases in capital expenditures.

Average use for life of cap ex is approximately 25 years, and turnarounds average approximately four years.

Net interest expense was approximately $30 million, compared to $20 million in the fourth quarter '02.

And $115 million compared to $102 million in the year '02.

Increase relates primarily to the 525 million and the $300 million bond issues during '03.

For 2004, gross annual interest expense should run around 133 million, plus annual amortization deferred financing costs, approximately $9 million.

Capitalized interest and interest income are deducted from this to produce the reported net interest figure.

2003 year-end, our effective tax rate was 34.1, as compared to 38.7 in '02.

Tax expense should continue to be booked at an effective rate of around 35%.

The rate will vary since the overall rate is a blend that depends, in part, on where our profitability is generated.

Premcor continues to utilize expensive net operating loss tax carry-forwards to shelter taxable income.

Balance at the end of '03 is approximately $120 million, and therefore, we do not (indiscernible)

In regards to the presentation on the income statement for operating revenues and cost of sales, I want to point out that we have reclassified certain amounts for all periods presented to the forum to the fourth quarter application of the emerging issues task force, B-11.

Please note that there is no effect on gross margin or net income as a result of this change. 311, which was published in '03 provides guidance, presentation and the income statement for contracts not held for trading purposes.

In accordance with the EITF 311, force of sales for all periods presented, includes a net effect of buying and selling crude oils (indiscernible).

Formally, these activities were presented on a gross basis.

Again, I want to point out that this reclass has no effect on the gross margin or net income for any periods presented.

Turning to special items, we have incurred one time cost associated with the shut down our St. Louis back office.

We are relocating the administrative information technology and financial functions to our Connecticut headquarters office between now and the end of the second quarter of '04.

And we expect to incur, in total, roughly $15 million in costs to do so.

In accordance with the current accounting rules, we are recognizing those costs as they are incurred.

And our fourth quarter charge was 5.7 million.

We also made a $10 million adjustment to our environmental remediation reserve during the quarter for the environment remediation litigation costs associated with the closed facilities.

Hartford Blue Island Refineries and the formally-owned terminal facilities.

Discontinued operations relates to our expenses associated with the Clark Retail Enterprise bankruptcy, which we've mentioned in the past.

And Clark completed their store auction, and most of their store site leases have now been assumed by third parties.

We remain continuedly liable on the assigned leases.

And a few other remaining unassigned leases could ultimately be rejected.

Our exposure, in this regard, cannot currently be estimated.

The environmental indemnification that we gave, CRE, at the time of the 1999 sale, did not transfer to the assignees of the CRE leases.

As the bankruptcy resolves, we will review our reserves, and -- of roughly 21 million, with possible adjustments downward.

Starting capital expenditures and turnaround, 2003 total spending was approximately $260 million, and excluding the Memphis acquisition, which totaled approximately $476 million with inventories.

Included in the 261 million total is 31 million for turnaround expenditures.

Our total tier two low sulfur fuels expenditures estimates remain at roughly $640 million.

As of December 31st, '03, we have spent $202 million of this total.

We expect 2004 cap ex and turnarounds expenditures to total around $540 million, including spending for tier two low sulfur fuel, Port Arthur expansion project and capitalized interest.

Hank Kuchta will get into more details on our capital expenditures program '04 in a minute.

The December 31st, year-end balance sheet is strong.

Our debt to capitalization ratio was 55.9% as compared to 56.8% at December 31st, '02.

We will continue to work it down to a combination of retained earnings, debt retirement and balanced financing of any future acquisition activity.

Cash at December 31st, '03 was $433 million, plus restricted cash of $67 million for pack bond debt service, for a total of $499 million.

That puts our net debt-to-cap at 5.4 million -- or 45.4%, with continuing improvement on that front as well.

Backed by a strong cash position and expanded credit facility, we are confident we can fund our capital plan through '06, including our $200 million Port Arthur expansion with our earnings capabilities and existing liquidity.

Our current capital plan calls for spending to top out this year at approximately $540 million and then decline to '05 and '06 before returning to normalized levels in '07.

Finally, for modeling purposes, our share count holds at 74.1 million, common shares outstanding with our diluted share base increase of roughly 5 to 2 million shares.

I will now turn it over to Hank Kuchta for a brief review of operations and our capital program.

Hank.

Thanks, Bill.

I will now comment on both the marketplace that existed during the quarter, and how our refineries operated within the markets they reside.

As the third quarter came to a close, the Asian crude demand was just beginning to show signs of life.

As we now know, the Asian economies picked up a full head of steam most notably (indiscernible) causing flat price of crude oil to move up and grade differentials to strengthen.

This trend continued through the end of the quarter as crude rose from $29 to 32.50 a barrel.

As you might expect, the strong demand for water-born crudes and products tightened the freight market considerably.

In fact, the market has reached a red-hot stage here, (indiscernible) scale 300 during the fourth quarter, and is currently hovering in the world scale 400 territory.

As you would expect, dated differentials to WPI, widen out to minus 2 to minus $4 because of the higher freight rates.

But in the end, North Sea crude to our landing in the Gulf Coast, at significant premiums to WTI, at times, this premium exceeded a dollar a barrel.

Consequently, the differentials on some of our staple domestic, such as LLS, ranged from a plus 15 cents to a high of plus 60 cents.

This crude price is increased through the quarter, crack spread did not follow.

WTI cracks started in reasonable territory in October, with the Gulf Coast 2.11 above $4.

But by November and December, the 2.11 had dropped into the 3 to 3.50 range.

Chicago 3.21 crack similarly were very good on average in October at 6.75, but dropped $3.00 a barrel to the mid-$3.00 range in November and December.

Unfortunately, the actual cracks at the refinery were at least 75 cents to a dollar a barrel worse due to sweet crudes arriving in the Gulf well above WTI due to the high freight rates.

The Mia TI spread was the only consistent positive performer for the quarter.

It started the quarter at 5.74, and then that spread widened out to 8 and a quarter by the end of the year.

In fact, the spread has now been averaging in January above $9.

Light and sour crudes stayed in the minus 2.60 range early in the quarter, but then strengthened to roughly minus a $1.90 by December.

On average, the Mia TI spread was wider by a dollar a barrel versus the third quarter, which is worth about $18 million to us.

Considering our clean earnings were 18 cents a share, or about $13 million, this was very significant.

On average for the quarter, we effectively ran a fully hedged position on crude oil and products; however, we did not incur the embedded backwardation cost of about 25 cents a month due to a discipline risk management plan.

Natural gas averaged just over 4.90 a million BTUs in the fourth quarter, which was pretty close to the same number in the third quarter, which on a relative basis, we definitely welcome considering the volatility of this commodity.

During the quarter, the prices ranged from 4.50 to as high as 7 and a quarter per MM.

Naturally, this is still well above anything that we had budgeted, which was in the $3.00 a million BTU category, which at this point, we certainly don't expect to see any time in the near or distant future.

Before I comment on refinery operations, I'd like to make a few general points about our operating philosophy.

We plan and direct our operations by continuously examining flat price, individual product cracks, market structure, and petroleum inventories.

In general, we want to produce enough to meet our product demand, but we have little interest in forcing barrels into markets that neither have the demand nor provide any incentive to store the product.

Furthermore, we aggressively look to replace crude with feed stocks wherever and whenever possible.

Our intent is to maximize the bottom line, while at the same time, minimizing any unwanted products.

Maximizing crude runs is not a principal objective.

At Port Arthur, we average a total input of 240,000 barrels per day. 228 of crude and about 12,000 barrels per day of feed stocks.

Mia crude was maximized at about 185,000 barrels per day, limited only by hydrotreating capacity, which is a function of hydrogen availability.

We were able to purchase economic feed stocks to back out lower margin medium sours.

The reformer turnaround originally scheduled for December was delayed until January to offset unscheduled downtime in Memphis.

Both Memphis and Lima started the quarter at high crude rates.

Memphis was at 165,000 barrels a day, and Lima at 155,000 barrels per day; however, as cracks dropped and crude grade premiums expanded, the plan rates were reduced to minimum.

Incremental distillate production had negative margins, therefore the plan was to keep the cap plants full, but nothing more.

As it happened, neither plant was able to run at maximum rates anyway due to the unplanned maintenance.

Now Memphis, the FCC has been planned for a January shut down to replace the steam generator and to make further tier two tie-ins; however it became apparent that the unit would not make it to January.

Therefore, we advanced the turnaround and completed it in December, while as it turned out, cracks were at their lowest for the quarter.

And furthermore, they were the lowest at the point of in month, and this month we have very high crack spreads in comparison.

So it never hurts to be lucky.

The FCC is now back in the mid 60,000 barrel-a-day range and is performing well.

In Lima, we had to repair a fractionation tower that had suffered trade damage after the restart of the isocracker, which had a planned maintenance turnaround in November.

Once again, cracks were below break-even at Lima during the period.

So the economic impact, which was less severe than it could have been.

I would also like to comment quickly on expenses.

We finished the year virtually right on budget for the fixed expenses.

We were within 1% of our $300 million full-year budget.

This is obviously an excellent performance by the refineries.

Our variable expenses were approximately 50 million above th budget for the year, which is attributed to the dramatic rise in natural gas prices.

We did mitigate approximately 10-15 million in additional natural gas costs by burning alternative fuels and optimizing our operations.

As for turnaround activity in the first quarter, the reformer turnaround at Port Arthur will be completed in the first week of February.

The expected first quarter run rates at Port Arthur will be in the 230 to 235,000 barrel-a-day range.

In March, we have a full refinery turnaround scheduled at Lima.

The whole refinery will be down for the full month.

Consequently, first quarter input rates will be approximately 100,000 barrels per day.

Lastly, we have nothing scheduled for Memphis in the first quarter, and therefore, we would expect it to run in the 150, 155,000 barrel-a-day range.

Finally, I'd like to make a few comments on our capital program. 2004, we expect to spend approximately $540 million, as Bill mentioned.

A rough breakdown of this total can be summarized as the following: Refinery projects, about 380 million, corporate and terminals, around 10 million, turnarounds, 120 million and capitalized interests approximately 30 million.

And the refinery projects, we can further break down the total to tier two gasoline, 100 million dollars, ultra low sulfur diesel, 80 million, other environmental safety and mandatory projects, 120 million and the Port Arthur expansion, approximately 80 million.

One further comment to make at Port Arthur, we are, at this point (indiscernible) gasoline, and we are making a premium in the market (indiscernible) in the second quarter, doing the same thing at Memphis.

Now I'd like to turn the call over to Tom O'Malley.

Thank you, Bill and Hank.

That was 20 minutes of very extensive information.

I hope everybody absorbed it.

It will be available for replay.

I'm going to limit my remarks to my view of the future of refining markets for the balance of this year, and also for the more distant years.

I believe that the price set we used in our 2004 budget, which appears on our website, will be conservative.

The harsh winter that we're experienced will put pressure on refiners to continue to produce middle distillates at higher rates than normal, and thus impact the timing, the switchover to maximum gasoline production.

Clearly, the imposition of new quality standards, affecting gasoline in the northeast will tend to restrict imports, which will, we believe, lead to somewhat higher margins.

The economy appears to be recovering, as my colleagues said, and albeit at a somewhat slower rate than perhaps President Bush would like.

But any recovery will, and is leading to increased consumption, and there is really not extra capacity to provide additional clean transportation fuels.

I stated in the investment presentation that Premcor made at our Delaware City Refinery Investa Conference at the Plaza Hotel recently that I believe we are entering a period of enhanced margins for the balance of this decade.

I strongly feel this is the case.

And on that note, will be pleased to answer any of your questions.

Operator, you can open it up for questions.

At this time if you would like to ask a question, you may press star then one on your touch-tone phone.

Questions are taken in the order that they are received.

Again, to ask a question, press star, then one now.

Your first question comes from Nicky Decker.

Good morning, everybody.

Good morning.

My question has to do with the maintenance activity.

The numbers that were given would imply, if I match them against the presentation last week, it would imply that there will be further maintenance activity at Port Arthur in the second through fourth quarters; is that right?

That is accurate.

And the -- we're planning to take down the Coking installation in October.

That will be the first turn-around of that installation.

But again, in the numbers that we gave, on market indicators and throughput rates, that has been calculated in there.

So Port Arthur will be running near capacity in the second and third quarters?

It should be running at full capacity in the second and third quarters.

Is the activity, the maintenance activity, or the work in October related to clean fuels?

Or is that part of the Coker process?

All of our projects today are related to clean fuels, because we take the opportunity whenever we take one of these units down, to tie in.

But this is really a pretty standard clean independent turnaround of our Coking installation.

Hank, you have anything to add to that?

That's accurate, Tom.

As you said, we will be doing some clean fuels, particularly on the low sulfur diesel during the October turnaround.

Hank, any idea what your gasoline production might look like when you complete the -- all of the clean fuels projects?

I suspect you're asking how much lower will the production be?

Is that what you're getting at?

Well, yeah, in a round-about way, I guess that's it.

Yeah.

Well, we would expect to see, you know, somewhere from 2-5% in certain facilities.

And is that in, you know, your conventional or premium grade gasoline?

You are going to see it mostly in premium, because the octane levels are going to be down.

So the hydrotreating of the high sulfur strengths.

Hi.

I think, by the way, that's one of the reasons that, in our evaluation of the marketplace, we have a perhaps a somewhat more bullish view than others.

Really, our experience is not unusual, we -- we are doing to produce clean gasoline and clean diesel, unfortunately has the impact of somewhat lowering production, particularly in the gasoline pool.

And the octane pool, above all else.

Will there be any capacity expansions other than at Port Arthur in conjunction with your clean fuels activity?

In -- within Premcor; are you talking?

Yes.

Hank, answer that, please.

No.

We don't have any expansion plans at the moment.

Very good.

Thank you.

Thank you.

Your next question comes from [Chi Cho].

Yeah.

Good morning.

Yeah. [Chi Cho]. bergman.

Bill, what were the diluted shares again for the fourth quarter?

The fourth quarter?

If I can whip out my program here.

Average for the fourth quarter was 74.1.

That's basic or was that diluted?

Basic.

What were the diluted shares?

Diluted is 75.226, rounded.

Okay.

Great.

Thanks.

Also, at Lima, the D&A rate looks like it went up for the quarter, I'm assuming due to the turnaround activity.

Is that a good number in the fourth quarter going forward for Lima?

Yes, it is.

Okay.

And finally, Tom, we notice that the EPA is considering allowing New Hampshire to opt out of the federal RFG program.

Do you have any thoughts on the likelihood of that happening, given that New York and California have been denied a waiver and the impact and indication on the gasoline market if it does go through?

I can only think that the primary campaign must have generated this potential opt out.

I would find it difficult to believe that we could have turned down two major states in the union and then decide that New Hampshire can do it.

New Hampshire is not a particularly large consumer of gasoline, so from a macro point of view, I don't think it is a significant issue.

It is kind of strange on the timing, I agree with you.

Yeah.

It just, it seems strange, and my own personal opinion, of course, is, has been, and I believe will in the future be, that the addition of oxygenate to gasolines, is a relatively useless exercise that complicates the making of gasoline and simply makes it more expensive for the American consumer.

But I believe those who want to win the votes of the farm state will see to it that farm states -- will see to it that the oxygenate requirement will not be removed any time soon.

Okay.

Thanks for your thoughts.

Thank you.

The next question comes from Greg Haas.

Good morning, gentlemen.

I will let you address this how you see fit, but a question regarding the natural gas prices.

I'm sure along with natural gas prices, you know, the concomitant costs of making or even purchasing hydrogen has gone up at the refineries.

Do you actually purchase the hydrogen from outside, or do you make it with some of that 29 gas that you purchase on a yearly basis?

Hank, you want to answer that, please?

Hello?

Hello?

Yeah, did we lose Greenwich?

Tom O'Malley, you mean?

No.

I'm on.

O'Malley is on.

We were -- it seems you dropped our Greenwich group off the phone.

So I will go on and answer the question on hydrogen.

You see -- is Greenwich on?

They have disconnected.

We will try to reconnect them.

Would you reconnect them.

In the meantime, I will answer the question, showing why I get paid more money than the other guys.

We do buy some hydrogen.

It is all natural gas-based and, of course, we make hydrogen in the plants ourselves.

I don't know if that answers your question.

Right.

I guess what I -- what I guess I'm getting at is the incremental costs that we're seeing this year are also in part based upon the incremental expense probably of --

But buying hydrogen through third parties to make -- buying natural gas through third parties to make hydrogen for us, yes, they are.

Yeah.

That's right.

Okay.

Any way to -- perhaps we can continue this offline.

Well, I think it's interesting, it's a good question for the general group.

We're probably, with our current installations, where we will be in terms of purchasing natural gas.

It's very, very hard to drive the volume metric purchase down to a lower level at this point in time without significant investment.

I will say that prospectively going forward, one of the very, very interesting parts about the plant in Delaware City that we're acquiring from Motiva is it essentially doesn't buy any natural gas.

It makes natural gas by converting the Coke into natural gas.

And thus, we don't have any exposure there to this surge in natural gas prices.

In fact, it may offer a significant advantage down the road.

Yeah.

So no incremental there; that's great.

As you bring up Motiva, I have a question.

You know, this week, we heard about Luke Oil's plans to buy some considerable number of retail gas stations in the U.S. northeast, and actually begin importing finished Russian motor gasolines, and presumably other transport fuels into the northeast U.S. import terminal from Russia.

And does that, in any way, figure into your plans at Motiva, or does it change it in any way?

What's your view on the northeast --

Well, there is no change.

Luke Oil had acquired the Getty Petroleum Company retail assets, I believe, about two years ago.

We've been importing Russian gasoline and components into the east coast, I think, for the better part of three or four years now.

Certainly, Luke Oil has been involved in doing so.

A lot of the Russian gasoline and components will not meet quality specs, but let no one be confused, we absolutely must import very significant quantities of gasoline to the U.S. east coast because we don't come close to making enough on the east coast, and indeed, we don't come close to making enough in the United States.

Gasoline imports are an essential.

They are not an option within the marketplace.

Excuse me, Tom, we got cut off for a moment.

I just want to let you know we're back.

Okay.

Thank you very much.

All right.

I think that answers my questions.

Thank you, all.

Okay.

Next question?

Thank you.

The next question comes from [John Zeroinga].

Sure, thank you very much.

The first question for you is regarding your revolver.

What was the status of the revolver at the end of the year?

Bill?

Total availability, I assume.

Availability, you know, our revolver is really an LC facility providing access to purchasing crudes.

It runs between -- the utilization runs between 450 and $650 million in any given time period in crude price.

We're happy with it.

It's certainly adequate for our needs.

Okay.

I forgot to ask on your Delaware City call whether you're anticipating upsizing the credit facility as a result of that acquisition.

What are your thoughts along those lines?

Bill?

Yes.

We are looking at several options, one of them is upsizing the facility.

One is creating an environment like we have in Memphis where we have repurchased the port from other people, payables, so either one of those is a viable option.

Also under our credit facility, we can actually buy inventory for cash if it is an acquisition.

So we are looking at all three of those options.

I should point out that the structure of a good part of the supply coming into Delaware City will, in essence, provide positive cash flow, ie, it is probable that we will be paying for the crude -- a good part of the crude that we run there, either concurrently or slightly after the point where we collect the money for the products we produce.

You're effectively going to be getting vendor financing?

Yes, and you know, that's not so unusual within the oil industry.

Generally, payment terms for crude oil are 30 days from bill of lading date.

And payment terms at their -- at their widest on the product side are really 10 days from delivery at the refinery, if you have a short transit time, which we expect to have, for the supply to the Delaware City Refinery, then we're -- we're in a pretty good position there.

Okay.

And any developments regarding the Delaware guaranteed or the Delaware Industrial Revenue Bond financing that --

Nothing that we haven't already announced.

Okay.

I guess the final question would be, regarding your cash flow from operations for -- with and without noncash -- working capital charges.

Bill?

The working capital change in the fourth quarter is about 77 million positive.

It's primarily from the shift in -- shifting more towards domestic crude, which gives us -- gave us an average of about $3.00 a barrel in the quarter.

If you hadn't done that, you obviously wouldn't have that flow.

The leverage comes out of the fact that crude -- even though crude went up, our payables go up and exceed our product receivables.

And the total cash coming from operations?

The cash flow from ops?

Excluding the noncash working cap.

Cash flow from ops for the quarter was 34.9.

And for the year, it was 358.7.

Thank you very much.

You're welcome.

Thank you.

At this time I show no further questions.

Again, if you would like to ask a question, please press star, then one.

Operator, there being no further questions, Bill Hantke and I want to thank everybody for attending this conference call.

We appreciate your interest in Premcor and we look forward to delivering enhanced value for our shareholders.

Thank you very much.

Thank you.

This concludes today's presentation.

You may disconnect at this time.