雪佛龍 (CVX) 2005 Q2 法說會逐字稿

Good afternoon, ladies and gentlemen, and welcome to your Chevron second quarter earnings conference call. [OPERATOR INSTRUCTIONS] It is now my pleasure to turn the call over to your host, Steve Crowe, CFO of Chevron Corporation.

Sir, the floor is yours.

Thanks, Ashley.

Welcome to Chevron's second quarter earnings conference call.

I am Steve Crowe the CFO of Chevron.

Today on the call, I am joined by Randy Richards, Manager of Investor Relations.

Our focus is on financial and operating results in second quarter.

We appreciate that there is a lot of interest in our merger agreement to acquire Unocal as we approach the August 10th vote by Unocal stockholders.

A great deal of information about the Unocal transaction is available in public filings and I'm sure you can understand there is little we can add at this time.

Today, we will review Chevron's quarterly performance, and then take your questions.

I will refer to the slides that were e-mailed to you this morning and are available on the web.

Before we get started I'll remind you that our presentation today contains estimates, projections and other forward-looking statements.

Please review the Safe Harbor statement on slide two.

Slide three begins with an update of our strategic process in upstream.

In Venezuela, we announced a discovery at our first exploratory well in Plataforma Deltana, Block 3.

Chevron has a 100 % interest in the block subject to a 35% back-in option by PdVSA.

Natural gas was encountered in six shallow sand intervals.

The well is relatively close to, and on trend with previously announced Loran discoveries in Block 2 and Manatee discovery in Trinidad and Tobago waters.

Together these discoveries boost Chevron's plans to evaluate an LNG project in Venezuela.

Moving across the world to Australia, Chevron acquired exploration rights at four deep water blocks west of the greater Gorgon area.

Chevron holds a 50% interest and will be the operator in these blocks.

The area is referred to as the Exmouth Plateau which is a deepwater frontier basin, which includes the North West shelf and Greater Gorgon resources.

The proposed initial three year work program includes acquisition of 2-D and 3-D seismic and the drilling of two exploration wells.

Moving to slide four, the partners in the North West Shelf venture sanctioned a major expansion of onshore facilities including a fifth LNG train.

Train five will add 4.2 million metric tons per year of LNG capacity, bringing the project’s total capacity to about 16 million tons per year.

Train five start-up is planned in 2008.

We recently announced our decision to move our Australian Greater Gorgon gas development project into the front-end engineering and design phase for a two train LNG facility and domestic gas plant on Barrow Island.

Two major contracts were awarded in connection with this effort.

In the shipping arena we placed an order for two LNG carriers with a capacity of approximately 155,000 cubic meters each to support our planned growth in the Company's LNG business and complement the development of the company's LNG export and import facilities worldwide.

Turning to the downstream we announced plans to increase the capacity of our Pascagoula, Mississippi refinery’s fluid catalytic cracking unit by about 25% from its current capacity of about 60,000 barrels per day, thereby enabling the refinery to increase production of gasoline and other like products.

Slide five provides an overview of our financial performance.

The company had a strong second quarter with earnings of $3.7 billion.

The results were driven by higher prices for crude oil and natural gas and healthy downstream margins.

There were no special items in the second quarter.

And if we exclude the special item gain identified in the year ago period, it was a record earnings quarter for Chevron.

Return on capital employed over the trailing four quarters was a very healthy 24%.

Our balance sheet continues to demonstrate tremendous financial strength and flexibility.

The debt -to-capital ratio ended the quarter at 19% with a net debt below zero.

Cash and marketable securities totaled $13.5 billion at the end of June.

Stock buybacks in the second quarter exceeded $800 million.

Since our buyback program was put into effect last year, the company has repurchased $3.6 billion of its common shares as part of a $5 billion repurchase program.

Randy will now take us through the quarterly comparisons.

Randy?

Thanks, Steve.

Slide six shows second quarter net income per diluted share was $1.76.

Net favorable foreign currency effects totalled $0.03 per share.

My remarks on the variance slides will be comparing second quarter 2005 to the first quarter of 2005.

Keep in mind that our earnings press release compared second quarter 2005 to the same quarter a year ago.

Slide seven shows net income increased just over $1 billion compared to the previous quarter.

The increase was driven mainly by higher crude oil prices in the upstream and an improvement in both industry margins and the company's realized margins in the downstream.

Starting with the left hand side of the chart, foreign exchange effects resulted in a book gain in the second quarter as compared to a loss in the first quarter.

Higher crude oil and natural gas prices added over $350 million to net income.

Stronger downstream margins in both the refining and marketing sectors contributed $560 million to the variance.

The impact on earnings attributable to volume changes was positive quarter-to-quarter, largely due to increases in refinery inputs and the production of high value products.

And earnings from chemicals declined on softer ethylene and benzine margins.

Slide eight shows U.S. upstream earnings which increased more that $200 million to over $970 million.

Higher liquids realizations boosted earnings $140 million.

Quarterly average prices for West Texas Intermediate crude increased $3.26 per barrel and San Joaquin valley heavy crude rose $4.73 per barrel.

Chevron's realizations rose about $5.40 per barrel.

This larger increase in realizations was driven by effects of pricing lags in the Gulf of Mexico which had depressed first quarter realizations relative to spot prices, and by the improved mix of light to heavy volumes as light oil production in the Gulf of Mexico recovered from storm related downtime.

Higher natural gas realizations had a $50 million profit effect.

Our average realizations increased $0.55 per thousand cubic feet which was a bit more than the increase in bid-week prices.

Approximately 20% of our volumes are sold on a spot basis rather than at bid week prices, and a strong run up of spot prices in June aided our realizations.

Higher volumes increased earnings $55 million, primarily reflecting the return of production previously shut in due to the effects of Hurricane Ivan, as well as one extra producing day in the second quarterly.

The variance in the other bar reflects higher fuel and steam costs and lower net gains on small property sales.

International upstream earnings increased $188 million as shown on slide nine.

Foreign exchange effects were positive in the second quarter compared to a negative impact in the first quarter.

Second quarter gains reflected strengthening of the U.S. dollar against both the U.K. pound and the Canadian dollar.

Higher realizations provided a gain of $165 million.

Liquids realizations increased nearly $4.80 per barrel, slightly higher than the average of spot Brent prices.

The negative variance shown by the volume bar reflects swings in actual sales volumes, based on cargo shipments.

Although underlying production was off only slightly, the volume effect was driven mainly by timing of shipments in Kazakhstan and Australia.

Slide ten summarizes the change in worldwide oil and gas production, including other produced volumes.

Volumes increased by 10,000 oil equivalent barrels per day between quarters.

U.S. production increased 21,000 oil equivalent barrels per day, as the restoration of volume shut in due to Hurricane Ivan and production from new wells brought online were partially offset by normal field decline and operational factors.

The volume still shut in in the second quarter totaled about 15,000 barrels per day, compared to a first quarter impact of about 37,000 barrels per day

Outside the U.S., oil and gas production decreased 11,000 oil equivalent barrels per day between quarters.

Net production was lower in Kazakhstan due to planned turnaround work at Tengiz.

In comparing the second quarter versus the same quarter last year, the impact of asset sales was 42,000 oil equivalent barrels per day in the United States and 38,000 oil equivalent barrels per day outside of the U.S.

Excluding asset sales and storm effects, U.S. production fell about 8% due to normal field declines partially offset by new or increased production in certain fields.

Outside the U.S. production increased about 2%, if we exclude the effect of asset sales and reduced volumes connected with cost-oil recovery.

With the increases coming from China, Train four at Australia's North West shelf, the Karachaganak Field in Kazakhstan and Venezuela partially offset by the effects of scheduled maintenance at Tengiz.

On slide 11, U.S. downstream net income rose $340 million as industry margins and the Company's realized margins improved.

Motor gasoline marketing margins improved in both the east and the west — the Los Angeles gasoline marketing indicator recovered to more than $5.50 per barrel from near zero in the previous quarter.

West Coast industry refining margins strengthened 10% and upgrading units in our West Coast refineries ran well, improving our product mix.

In addition, a swing in the impact of final pricing adjustments for long-haul crudes contributed 40 million to the positive margin variance and that effect was negative 30 in the first quarter and positive 10 in the second quarter.

Refinery input volumes increased after first quarter downtime as did the production of high value light products.

Total refined product sales were up mainly due to an increase commercial gasoil and diesel sales at the onset of the agricultural season.

Branded motor gasoline sales increased slightly.

These volume improvements added $60 million to after-tax earnings.

As an aside, I would note that the branded Mogas sales were up 6 % second quarter this year versus second quarter of last year.

The negative variance in the “Other” bar reflects higher refinery fuel costs, higher transportation expense and the absence of a first quarter gain on the sale of a pipeline asset.

Turning to slide 12, second quarter international downstream earnings of $578 million were up 227 million compared to the first quarter.

Higher refining and marketing margins accounted for most of the improvement with margins up in all regions -- Asia, Europe, Canada and Latin America.

The benchmark refining margin in North West Europe improved about $3.00 per barrel recovering to almost $2.00 per barrel after recording a negative average level in the first quarter.

Net refinery input was down 7,000 barrels a day for the quarter, largely driven by the effects of planned downtime in Korea and Australia.

The volume bar on the chart is positive, however, as increases in refinery inputs and production of high value products elsewhere in the segment gave rise to an overall positive earnings effect.

Slide 13 shows chemical results were $84 million in the second quarter, down $53 million from the first quarter.

The lower results reflect a decline in the earnings of Chevron Phillips Chemical Company, our 50% owned equity affiliate.

The decrease was primarily driven by softer Benzene and Ethylene margins.

All other is covered on slide fourteen.

The P&L businesses in all other include Dynegy, Power, and P&M Coal.

Most of the positive variance reflects a swing between quarters in our equity share of Dynegy's earnings which included non-operational items in both periods.

The “Other” bar primarily reflects the aggregation of minor variances for tax and other corporate charges.

Our guidance for all Other calls for net quarterly charges in the range of 160 to $200 million and that is excluding Dynegy.

Second quarter results were right in the middle of this range.

That completes our brief analysis of the quarter and now I will turn it back to Steve.

Thanks, Randy.

That concludes our prepared materials.

We will now take your questions.

We will trying to answer all your questions but, as I indicated at the start, we would like to keep our focus on Chevron's results and strategies.

We plan to wrap it up at or before the top of the hour.

Ashley, please open the lines for questions.

Thank you.

Certainly.

The floor is now open for questions. [OPERATOR INSTRUCTIONS].

Your first question is coming from Bruce Lanni from A.G. Edwards.

Please go ahead.

Yes, thank you, Good morning, Steve and Randy, and congratulations on a great quarter.

Just a couple questions that related on the downstream I am trying to get a handle on.

One about the energy bill and any potential impact you can see, since it excludes the MTBE liability provision.

That would be the first one.

And then, if you could give us some color on the timing and the cost for increasing the FCC unit in Pascagoula, that would be helpful, too.

Sure, Well, let’s deal with the second one first, Bruce.

As I mentioned in my remarks, the expansion of the Pascagoula fluid cat cracker should increase the capacity of that unit, which is about 63,000 barrels a day to be specific, by about 25%.

And, we are thinking that that expansion will be completed in late 2006.

That will provide both increased gasoline production as well as light product production.

With respect to the energy bill and the MTBE question, I am not at a point yet to comment specifically about that.

Okay.

Then Steve, one other question.

As far as the cost associated with Pascagoula is it going to be – is the primary cost going to be in '06, or will part of it be in '05?

And then, will that be reflected in your spending -- will increase your spending for each year?

Let me ask it that way.

Fair enough, Bruce.

It is probably going to be on the order of $150 million.

Then, it will be split between the two years.

Okay, so pretty insignificant in that sense.

Thanks, Bruce.

Thank you.

Your next question is coming from Mark Flannery of Credit Suisse First Boston.

Please, go ahead.

Thank you, yes.

My question is on the downstream as well.

Specifically, with any continuing effect of unplanned downtime.

I am thinking about the U.S., particularly, but also of Pembroke.

I remember in the first quarter we were encouraged to think of that impact as somewhat small and feels a little bigger than that in the results today.

Wonder if you could just comment, with some specificity, on what is going on there.

Sure.

Well, we did have some unplanned downtime in the second quarter, specifically at our Pascagoula, Mississippi refinery.

It was the crude unit and hydrogen units there.

And, Mark, as you may recall in our conference call for first quarter earnings I alluded to the fact there was some continued downtime flowing over from the first quarter into the first part of the second.

And, by the time it got into the middle of the second quarter, the unplanned downtime has been largely eliminated.

What you did see as you compare the second quarter to the first quarter is significantly less downtime in our two West Coast refineries.

And, this coincided with a period when industry marketing margins and industry refining margins were improving on the west coast, where we have such a significant presence.

So, that was a big driver, as Randy had shown on the variance charts, for U.S. downstream for the sizable improvement.

It was a good time to be -- a good area to be in the R&M business when you are up and running and we had a pretty good run here in the second quarter.

We don't expect, as we come into the third quarter, to have material planned downtime and I am not aware of significant unplanned downtime as we speak.

And just a quick word on Pembroke?

Pembroke did have a bit of downtime in the second quarter that was unplanned and, again I think the problems that we have there are behind us.

Thank you very much.

Thank you.

Thank you.

Your next question is coming from Doug Leggate from Smith Barney.

Please go ahead.

Good morning, Steve and Randy.

Your production guidance for the balance of this year -- is flat still good guidance versus last year, and I wonder if you could give us some idea as to what you expect out of Kazakhstan once maintenance is over in the second half?

I didn't catch the first part of your question.

The production guidance for 2005 -- I think you had led us to believe it was going to be flat versus last year.

I am just keen to know if that guidance still valid, and what you expect Kazakhstan to look like in the second half.

Well, the guidance we had given you going all the way back to our December analyst's meeting in New York was that we expected 2005 to be the low point in the Corporation's overall production profile reflecting in large measure, the asset sales that had occurred during late 2003 and during the course of 2004.

So far, Doug, as I look at the pattern in the fourth quarter of last year and the first two quarters of this year -- the overall enterprise's production volumes have been quite flat at just a bit over 2.4 million OEG barrels per day.

We are still expecting as we move into 2006 and beyond, the pattern of increased earnings as we have shown you back in December and that still is our expectation.

And maybe I can give you some specifics, Doug, on year to date versus year to date.

The impact of asset sales overall is 86,000 barrels a day OEG.

The impact of storms, the lingering effects of Ivan particularly -- 26,000 barrels per day.

And, the impact of higher prices on cost recovery oil and royalties was 32,000 barrels a day.

When we talk about flat, of course, we are excluding those kinds of factors.

So we were, in fact, within about 1% of the flat guidance so far.

Doug, as we move into 2006 we will see the start-up of Benguela Belize, which actually we may see a cargo here at the end of this year and then the next phase of Tengiz.

Then as we move out forward into the 2008 time frame, we will see Agbami come on and thenTahiti.

And so, the large projects that we have talked to you folks about are on track and coming on as planned.

On Kazakhstan, is it possible to give us some guidance as to what with -- I assume the maintenance is over now and you would basically be looking for that to ramp back up in the second half.

Yes, Doug.

The maintenance extended into July just very briefly so it is over now.

I am looking for the impact here.

We will get back to you, Doug, with the specifics on the volume.

Let me just and grab one more on the downstream real quick.

Can you quantify the opportunity cost of the downtime in the second quarter?

It is a bit of an analytical exercise, as we have talked before.

Again you get different effects for planed versus unplanned downtime and you re-adjust your feed stocks and you also readjust how you go about acquiring product to meet marketing and logistic requirements.

In a very kind of gross sort of way, encompassing both the planned and unplanned downtime system wide, worldwide, it is probably on the order of between 150 to 200 million.

Depends on how you go about measuring it and why there's such a wide range in that calculation.

Thank you very much.

You are very welcome.

Thank you.

The next question from Paul Chang of Lehman Brothers.

Please go ahead.

Hi, good morning.

Good morning, Paul.

Steve and Randy --Venezuela, I think that there is some news talking about your offices having some visit by the authority over there.

What is the situation there and is that in any way that have make you rethink your investment over there.

I think at one point you had thinking about expand or that get into a new heavy oil upgrading project.

Is that being on hold, or are you pursuing on that?

Thanks, Paul.

It is a bit in a state of flux in Venezuela and people read a lot of things about that in the press which may or may not be the correct characterization.

We have been informed by the government that they would, perhaps like to see our Boscan and LL-652 agreements converted to structures consistent with the hydrocarbon law.

We don't have any specific on details on that conversion and I must emphasize that each arrangement in Venezuela is unique.

For example, our gas activities in Plataforma Deltana,is in a contract that is consistent with what is called the gaseous hydrocarbon law and our Hamaca project is governed by a separate agreement that is also not subject to any change.

The one you alluded to, Paul, the new Orinoco project, will be created under the hydrocarbon law, and we have previously stated we are willing to form a new venture under those conditions.

You may recall that near the end of the first quarter we signed a letter of intent with Repsol to pursue a joint development activities in the Orinoco Belt with production transportation and the upgrading of extra heavy Baja crude.

So the PdVSA and the Venezuelan government were attending that signing ceremony and the activities will be aligned with Venezuela's current hydrocarbon law and framed under the new energy policy.

I think it would be fair to say there is more to will follow as things progress in Venezuela and the outcome is still under negotiation.

And Steve, I know the news not necessarily will be accurate as long as news falling out from Venezuela - at one point that it seems to suggest that they may even want to change the heavy oil project, the tax rate from the 34% to 50%.

Is that a true statement or have you guys been contact or that is just a (inaudible) from the news.

Well, the hydrocarbon law that was passed in 2000 does contemplate a tax rate of 50% if you have a joint stock company.

But as I said, Paul, each of these specific arrangements -- and certainly the ones that we have in Venezuela are each unique and to themselves -- and it is very hard to generalize across the board what the outcome will be.

So you have not been contact by the government on Hamaca.

As I said, the Hamaca project is governed by a separate agreement and is not subject to change.

Just one final question, on same store sales in your U.S. operation, can you give us a same store sales figure versus a year ago for those that who have opened for more than a year?

Paul, that is one I will have to pursue after the call from our marketing people.

I don't have that right at my fingertips.

Thank you.

That would be appreciated.

Thanks, Paul.

Thank you.

Your next question is coming from Mark Gilman of Benchmark Company.

Randy, Steve, Good morning.

I wonder if I could go to the refinery downtime issue for a moment but in a third quarter context.

It seems that there has been downtime at Pascagoula, slow restart after a hurricane.

Also, the recent problems at El Segundo.

Could you talk a little bit about where we stand with respect to both those facilities and the amount of downtime to date?

Well, I can't speak to the downtime in terms of -- you would have to look at it unit-by-unit but in Pascagoula, you are correct.

We did have both planned downtime, particularly in the first quarter and some unplanned downtime that was mostly in the second quarter.

As I mentioned, it is my understanding that the issues in the second quarter connected with hydrogen and the crude unit are largely behind us so I wouldn't expect a continuation into the third quarter.

As far as El Segundo is concerned, what we are seeing there was mainly unplanned downtime in the first quarter of the year.

Some of it did carry into the early part but, again that is largely behind us and didn't have a significant effect in the second quarter, Mark.

Steve, I am talking about the third quarter.

At the third quarter, there is no planned maintenance in the third quarter and we are not expecting any -- we are not seeing, at this juncture, any unplanned downtime that will have a significant effect.

You have got a fire at El Segundo, don't you?

Not that I am aware of.

And you didn't have problems restarting Pascagoula after the hurricanes came through?

We did, and that affected the -- part of the second quarter.

But, we are not seeing any problems at this juncture that I am aware of.

If you are talking about Cindy and Dennis, Mark, we had some preventative unit shutdowns into a warm shutdown stage.

Those were brought on in a phased manner, safely and efficiently.

I don't think, when you look at the third quarter as a whole, that is going to be a big issue .

Okay, just one more if I could.

On the international side upstream, I am trying to get a handle on the extent to which the significant overlift, if I could term it that, that occurred in the first quarter was made up by an underlift in the second quarter.

And maybe you might be able to comment as to where we stand on that issue as of mid-year, so that we have input regarding third quarter and second half.

Well, lifting is relative to production in the second quarter world wide.

There wasn't a lot of difference between the two.

As often the case, it is all in the mix of where we lifted.

And so, we had a negative volume effect in international upstream in the second quarter because of reduced shipments in certain places, chiefly Kazakhstan and Australia.

But bottom line, around the world liftings were not out of line with production and I wouldn't expect that to imply anything significant for the third quarter.

Okay, thank you.

Thank you.

Your next question is coming from Neil McMahon of Bernstein.

Please go ahead.

Hi, just really a question on (how) the demand for petroleum products and chemical products is going in Far East Asia, And also, it seems you have got pretty strong demand in the second quarter in the U.S. for Mogas sales.

And also, if you could give us a bit of guidance for where you are seeing demand going at the start of the third quarter.

And, I have got a follow-up question as well.

Well, we are certainly seeing some improvement as I look at the Dubai margins in the pattern of refining margins.

If I look at it, say, through the first half of July, it is on the order of $5.60 a barrel.

That would be in contrast to, say, in June of $4.80.

So, we are seeing a bit of an uptick in the refining margins in our Asia Pacific market.

Similarly, in northwest Europe we have seen an increase in the refining margins on a Brent refining basis, but they were from fairly depressed levels certainly in the first quarter -- some improvement in the second quarter and it looks to be, with July, a little bit above what we had seen in June.

I'd say, Neil, that volumetrically your characterization is accurate.

We are seeing pretty strong demand in both of those markets.

Really, our system is organized around optimizing the whole value chain.

So, we are trying to sell what we produce and are not out there trying to buy and resell an extraordinary amount.

But to the extent that we look at demand in the face of high prices, it seems quite firm.

Great.

And that sort of goes with most of our competitors have been saying as well.

And, just another question.

I don't know if this one has going over.

You mentioned that at the end of the second quarter if I heard you right, 15,000 oil a day or barrels of oil-equivalent, were are still shut in the Gulf of Mexico after Ivan last year.

Any idea if they are going to at all going to come back or that is, basically, they cost too much to bring back onstream?

That was the average for the second quarter, and my last information on that -- there were some volumes considerably smaller than that that were uneconomic to bring back.

Are we talking like single digits?

I believe it is.

I think we were at 15,000 barrels a day that was still out in the second quarter.

I would guess half or maybe slightly less.

And, that is not going to come back, so what you have got up running now is pretty much -- it is all production versus what it used to be.

That's correct, Neil.

Great, thank you.

Thank you.

Thank you.

Your next question is coming from Paul Sankey of Deutsche Bank.

Please go ahead.

Good morning, guys.

Steve, we have seen the press releases but we haven't had, if you like, a live comment about the increase that you made to your bid for Unocal.

Could you just remind us of the rationale behind the fact that you added to your original bid?

Sure, Paul.

As you recall, or for those of you on the phone, it was last week we increased the bid really under competitive pressures and changed the structure of the consideration that we made.

You will find more specifics if you go to our website but, generally speaking, a couple of things.

First the deal economics are still very favorable in our opinion. and will add value to Chevron.

The financial metrics that arise from the transaction as currently structured are also favorable.

We're now looking based upon first call estimates of an earnings per share accretion in the neighborhood of 2% and a continued cash flow accretion per share in the neighborhood of 6 to 7% and the impact of bringing Unocal into the Chevron balance sheet with purchase accounting probably drops the ROCE in the neighborhood of around 1.5%.

All of these metrics are more favorable than when we talked about it when the deal was first announced in early April.

We have done our own measures in-house and what I just described to you which was using first call numbers and adjusting for synergies and purchase accounting is consistent and a little more conservative I might add than what we see ourselves.

But the deal itself adds value on an economic return basis and we are pleased with it.

For those of you who aren't familiar with the specifics, it is a 60% tax free exchange on the equity portion with an exchange ratio of 1.03 for each Unocal share, and 40% is in cash at $69 per share.

Overall, the transaction will be valued at around $17 billion in cash and stock and we'll go from there.

Does that help you?

It does greatly.

Thank you.

It sounds as if against the original bid, actually, in many respects the metrics have improved, if you like, with the increased bid.

Does that mean there's still a bit more head room from your point of view?

I think the deal is still quite attractive to us.

Part of the deal metrics reflects the change in consideration using more cash than Chevron equity.

One thing I would point out, Paul, while you asked the question.

In early April when we announced the deal, we did mention that post-close that we would consider a significantly expanded share repurchase program in order in part to mitigate any dilutive effects.

As I mentioned with the changed structure of the deal and the fact that Unocal is not dilutive to Chevron, any share repurchase program or changes that we make in the future will be governed as we have in the past looking at it as a way of helping to structure our capital structure and a way of returning value to the shareholders.

But, having an expanded program in and of itself to mitigate dilution does not appear to be a requirement at this juncture.

Steve, I appreciate your answering the questions.

Thanks very much.

Thanks, Paul.

Thank you.

Your next question is coming from John Herrlin of Merrill Lynch.

Some quick ones.

With Plataforma Deltana, what is your LNG threshold?

Can you elaborate on the question?

How much gas do you need to have for it to be viable LNG project?

I think the answer is somewhere in kind of between 5 to 10 trillion cubic feet -- probably 7, 8 trillion cubic feet.

Obviously, right now we're dealing with resource estimates and it's way too early to be talking about those resource estimates.

Okay, that's fine.

With Australia and the new deep water leases that you've got, how quickly will you shoot seismic?

Let me see here on that.

A three year work program with 2-D and 3-D seismic as well as two exploration wells so it is somewhere over the course of the next three years.

Okay.

And obviously looking for oil but what happens if you find gas out there?

We'll be very happy if we find gas out there to include it along with the northwest shelf and the greater Gorgon area resources.

So it's not that distant, okay -- to plumb it in, is what I was wondering.

No, it is due west of Gorgon.

It's not that distant.

Thank you.

Last one from me you mentioned the building of two LNG vessels.

What is the timing on that in terms of when they will be completed?

We've ordered two LNG carriers and planned delivery for them is in 2009.

And the cost?

I don't have a specific cost estimate with me, John.

Thanks.

That's it for me.

Thank you very much.

Good questions.

Thank you.

We'll take one last question and it comes from William Ferer of W.H.

Reeves and Company.

Please go ahead.

I can't believe you didn't screen your calls better than this.

Bill, I don't know how you got in.

I don't know.

You've obviously lowered the standards.

Speaking of deals, my question relates to an older deal that I know, Steve, you're very familiar with and that is the Pittsburgh and Midway Coal Company.

Could you suggest to us what either the quarterly or annual bubble of earnings might be and given the improvement in coal profitability these days and why wouldn't that be an asset that you're studying carefully for possible disposition as you monetize your noncore assets over time.

Bill, Good question.

You don't mean that.

Stop it.

In the broader sense, we've looked at all the assets we've had looked with Chevron and Texaco and during the period when we were not selling assets in order to avoid problems with pooling, we identified those assets which we characterized as core or strategic and those which were noncore.

Noncore assets don't necessarily mean they'll be disposed it just means that they'll draw less capital than the strategic assets and P&M Coal is in that category as being a noncore asset.

When taking a look at choices of either disposing or selling of P&M or continuing it as an asset in our portfolio, the economics drive us to keep it within the portfolio as an earnings component and generating cash.

Its contribution to the bottom line is fairly modest at this stage of the game but we're happy to have P&M Coal as part of the family and as you know from a segment point of view it's tucked into the “Other” category.

That's what I was trying if find out what it contributes.

You tuck that thing away, I don't know if it's a big deal or no deal.

In 2004 the number was I don't recall the exact number but on the order of $20 million.

It's not running quite that high so far this year and we'll have to see how the year turns out.

Okay.

Thank you, boys.

Thanks, Bill.

Thank you.

At this time I'd like to turn the floor back over to Randy Richards and Steve Crowe for closing remarks.

Well, thank you, Ashley.

In closing let me say that we appreciate everyone's participation in today's call.

I especially want to thank each of the analysts on behalf of all the participants for their question during this morning's session.

Second quarter was a really excellent quarter for us.

As you know if you strip out the special items from earlier periods this was a record quarter for us and we are looking for strong results as we come into the third quarter as well.

With that, Ashley, I'll turn it back to you and thank you all for calling in and wish you a good day.

Thank you.

That does conclude today's teleconference.

You may disconnect your lines at this time and have a wonderful day.