雪佛龍 (CVX) 2004 Q2 法說會逐字稿

Good afternoon and welcome to Unocal's second quarter conference call.

Following today's presentation there will be a formal question and answer session.

At that time instructions will be given.

Until that time all lines will remain in a listen-only mode.

At the request of Unocal, today's teleconference will be recorded.

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

I would now like to turn the call over to your presenter, Vice President of Investor Relations, Mr. Robert Wright.

Sir, you may begin your call when you're ready.

Thank you, Anita.

Hello everyone and welcome to the second quarter call.

A replay of this audio broadcast will be available through our website and over the telephone.

Please call Investor Relations if you have any questions about the numbers.

There are also some slides available for your review, posted on our website, and you can view them at www.unocal.com.

As we progress through the call some of the slides will be referenced by number.

Some are provided for backup purposes only.

Our presentation today, including these slides, contains forward-looking statements and non-GAAP financial measures.

Please refer to slide 2 for a cautionary note regarding the forward-looking statements and the location of the reconciliation and other information regarding the non-GAAP financial measures.

Before I get into my portion of the call, I want to turn the floor over to our CEO, Mr. Chuck Williamson.

Thanks Robert and good afternoon everyone.

Welcome to our second quarter call.

I am going do make a few comments about our second quarter results, talk about our annual guidance and update you on some of our major programs.

As you have seen from the three press releases we've had in the past week, we've had, first of all, record earnings in the second quarter with a strong financial outlook for the remainder of the year.

We announced our intention to repurchase $150 million of common stock and up to $260 million of the Convertible Preferred, and to make an additional $100 million contribution to the pension fund.

Terry and Robert will elaborate on those in a few moments.

We also released an update on our Indonesian project, and the successful appraisal programs we've had there are making some good progress.

I'll comment on those as well.

And of course we included a revised production outlook for 2004 that reflects our weaker performance than expected at our West Seno project, and our asset sales and the PSC price revision.

Let me make a few comments about the production forecast.

Certainly we recognize our history has not been all that stellar in terms of meeting annual production targets.

With the new approach we've introduced and outlined in the release, I hope and am confident we'll certainly improve the accuracy of our production forecasts.

I have to say I'm as frustrated probably as many of you.

It's not that we haven't put a lot of effort into getting a better forecast, but we have now changed the methodology.

We are now using a forecast that I am confident we will exceed, and we are providing more information on a range of variances that we will see relative to the previous quarters' actuals.

Our legacy production operations are now performing in a more predictable band, with less of the Gulf of Mexico Shelf in there.

But we will continue to experience variances both positive and negative as we begin these major new projects over the next several years.

So our intent in putting the forecast and the methodology out is to revise the basis of our forecast, provide you more detail and keep you apprised of any material changes, particularly in the new projects.

Again I will emphasize that our legacy production operations are in a much more predictable place than they've been in the past.

Let me go ahead and talk briefly about Indonesia and then I will talk about some of the other areas.

Although the West Seno project certainly has not performed up to our expectations as we detailed in the release, I still need to remind everyone this is a significantly positive project with returns well in excess of 20 percent.

But we continue to struggle with production problems.

In June we averaged 24,000 BOE per day gross, up about 7,000 BOE per day gross from April but still well below what we expected, which is about 35,000 BOE per day.

We have completed about 20 wells, but we have several shut in right now for work-overs after a facility shut down.

We expect to have about 26 to 28 wells on line by year end, with an exit rate of 25 to 35,000 BOE per day gross.

Oil is about 17,000 BOE per day of that 25,000.

We've chosen, as we've said in the release, to delay Phase 2 of the project as we open up the bids.

The bids were unacceptably high for Phase 2 and we are now exploring other options.

I know there's been a lot of concern expressed about large reserve write-downs on West Seno because of our disappointing performance.

But have I to assure you all we've been quite conservative in our approach.

This was never fully booked.

And depending on how Phase 2 and future performance comes out, we still expect write-downs of less than 10 million barrels oil equivalent this year in West Seno.

In Indonesia we are moving ahead with the final engineering work on the Gendalo project.

That's a much better and certainly much easier reservoir to develop than West Seno.

It's been fully delineated and we are starting our engineering work in earnest right now.

We are designing for about 250 to 300 million cubic feet a day and will probably be on line in late 2007 using the subsea early development concept.

We will also be drilling more exploration wells in Indonesia this year.

We have some undrilled PSCs that are outboard of our existing discoveries in deepwater, and will be drilling there in the Popodi Block in the fourth quarter, along with a couple wells in the basin just to the north.

Though our exploration continues in Indonesia, certainly the gas projects are on a good trajectory, and we will continue to try to improve our performance there in West Seno.

Let me make a brief mention; we put out an announcement recently that we've hired a new COO and President, Joe Bryant, who comes to us from BP.

Joe is going to be a great addition for us.

He'll join us in early September.

He has been heading BP Angola and their deepwater development exploration effort there.

He was recently president of Amoco Canada and BP Canada, and just really has a great track record in terms of large business unit leadership, hands-on operations experience and very valuable domestic and international large project experience.

We will try to get Joe back to New York and Boston in early September to meet with as many of you as possible.

Now I'm going to take a few minutes to talk about some of the progress on the major projects that we have coming on line in 2005.

We've outlined the ranges for these in our production forecasts, or our guidance I should say, for 2005.

Let me begin with the Azerbaijan.

BP has made very good progress this past quarter on the offshore part of the project and the BTC pipeline.

The first Azeri platform is basically completed and work is well along on the second and third offshore platforms.

We expect first offshore oil production early in first quarter.

The BTC pipeline is more than 70-percent completed, and start up is scheduled for second quarter 2005, with the first Ceyhan lifting probably in the third quarter.

This will be a steady source of our growth for the next several years in Unocal, and again we think that BP is doing a fine job of keeping that project on track.

Turning now to Thailand.

I was in Thailand a few weeks ago, and they are making very good progress on next year's expansion of the oil project as well as gearing up for the third pipeline in 2006.

We installed this last quarter a new floating production vessel that will be part of our oil expansion.

It's expected to come on line in second quarter of next year.

The tie in and hook-up took a couple weeks longer than we expected.

So in the second quarter results, you see our production dropped a little bit further than we expected in Thailand.

But it's on line now and ready for the expansion project and back on stream.

Also in the second quarter, EGAT had built up fuel oil supply and was burning some of that off, so that also affected our performance in the second quarter.

Nevertheless, the gas market in Thailand continues to grow.

Power generation this year is up, I think, nearly 8 percent year-on-year.

And we are now preparing for increased gas sales in 2006 with the third pipeline.

Let me jump to Bangladesh.

We are pretty much on schedule for our production from the Moulavi Bazar field in the second quarter of next year, the massive flooding that has recently occurred, the worst in many, many years in Bangladesh.

And that says a lot, because of course it floods every year there.

We maintained the construction schedule for a fairly simple project.

We also expect some time in the third or fourth quarter to sign another gas sales agreement, for the Bibiyana field.

This is our largest field we've discovered in Bangladesh.

With our first production in early 2007, it will grow from about 200 million cubic feet per day for several years to all the way up to probably 500 million cubic feet per day.

So Bangladesh continues to be another part of our steady growth over the next few years, and those projects are on track.

We've actually had record production in the past quarter from our existing fields in Bangladesh as well.

Let me switch now to the Gulf of Mexico, particularly in the deepwater.

Next year we will get our first deepwater production from participation in the Mad Dog and K2 fields.

They will be on line in first half of '05.

In the Mad Dog project BP has done a good job of catching up.

They are scheduled to come on line early in the second quarter.

The top sides and spar are now set.

They are just about to begin commissioning and finishing up the well completions in the third and fourth quarter, and we expect production sometime early next year.

We had disappointment on the deep exploration well we were drilling with BP at Mad Dog to test the lower tertiary interval we drilled at St. Malo and Cascade.

But we had mechanical problems and suspended that well.

We are likely to return to that probably in early 2005.

We still think it's a very interesting prospect.

We also plan to drill an appraisal at Puma, where again BP is operator and we are an interest holder.

At St. Malo in the past quarter we had a very successful down dip appraisal well.

We put out a press release on that.

It significantly increased our oil-in-place estimates, and did not find water down dip.

We are currently analyzing the core and wireline information.

We really recovered a host of information there that will take a few months to evaluate, in order to try to assign a recovery factor and come up with a better idea what have kind of reserve estimates we may have.

We can expect to drill another well there probably early next year, after we’ve analyzed the information and pending our partners' approval.

So we remain quite excited about St. Malo.

We just had a lot of work to and got a great suite of information from the well.

We are currently drilling with the Spirit at a prospect called Sardinia, in Keathley Canyon, Block 681.

Operations are going very well there.

I would guess the well will TD some time within the next month.

This will be a very important test for the industry.

It's the first test of the St. Malo, if you will, equivalent interval in this area.

Of course this prospect is somewhere between the Perdido and Trident on the west, and the St. Malo discovery towards the east.

So this is a rank wildcat area and a very important tests for us and the industry.

Our partners there are Devon and Total and one other company.

There's also a lot of industry activity in the deepwater Gulf that bears heavily on the value of our portfolio.

BP is currently drilling a prospect right next to St. Malo, what we call La Jolla.

We don't have a working interest in that well, but we will be very interested in the results.

A Chevron well just to the southwest called Jack is also near TD, and we expect results on that shortly.

And then Exxon will be drilling, I think within a month will spud a prospect called Hadrian, west of Jack, that will try to extend the trend to the west of St. Malo.

So we will be watching those wells carefully.

After Sardinia, we will follow with a prospect called Sequoia.

This is a Miocene test, a deep Miocene test in Mississippi Canyon 947.

We have a shallow discovery there with BP called Mirage.

This is a BP operated prospect.

It will be farmed into by Total and we will drill and have 20- percent working interest at this point.

It's right near up near Mars and Ursa, Tubular Bells and Champlain.

We also had this quarter a small discovery at Tobago in the Perdido.

We found a much better reservoir than at Trident and then a very good location for the greater Perdido infrastructure.

And we are continuing to work with Shell on a co-development plan for the region in Perdido.

So that’s a quick review of some of the bigger ticket items for us in the deepwater Gulf.

Let me just make a comment or two on the legacy businesses.

I will say our producing businesses are performing well.

Our Gulf of Mexico Shelf and North American production is holding reasonably steady, minus some asset dispositions, with about $60 million of capital in the Shelf which is quite different than $150 million a couple of years ago.

We've drilled some deep development wells in the Gulf of Mexico Shelf, nothing huge but it's allowed to us keep a pretty steady production rate with a lot of success.

We are not drilling on a deep Shelf exploration program unless it's fourth quarter this year or early sometime next year, but we do expect to come back and drill a few wells probably next year in the deep Shelf program.

The Permian has been very active for us.

Our Pure Resources subsidiary is ramping up several exploitation programs that will show gradual production increases as the year progresses and on into 2005.

And in a conceptual way, the way I would look at our base is that we expect some declines in the Shelf certainly next year, but we do expect that to be offset largely by increases in the Permian.

So North America is in a much better place than it's been in a long time in terms of predictability, and again high prices are giving us some very good cash flows.

The only real significant problem for us in our legacy in the second quarter was Indonesia, where we had several unplanned shutdowns of facilities that led to some production decreases in the second quarter.

They are back on line and we should see a better third quarter in Indonesia.

These are mature businesses whose production is heavily affected certainly by our spend and by oil prices because of the PSC effect.

I'd say on our cost structure we are facing a lot of same cost pressures as the rest of the industry.

But we've been able to keep our total cash and non-cash costs at about $15 per BOE worldwide.

We will continue to try to hold that through the rest of the year.

On the portfolio cleanup, just a word or two.

We sold our remaining interest in Brazil to El Paso, at what we think was a very fair price; we put out a release on that last week.

We settled a very longstanding eight-year dispute in the Philippines on our geothermal operations, signed a new contract and received a cash payment from an escrow account there.

And we finalized the sale of our Pure Resources fee mineral acreage for about $190 million to Blackstone.

We continue to sell some small real estate holdings, particularly in California, and again clean up the portfolio.

So I'd say overall, despite the production revisions and some of the reactions we saw today, I still feel very confident about 2005, 2006.

The projects I went through, the big projects are all on track.

The only real hiccup for us has been West Sano.

And I'll have to say it's been disappointing.

We've struggled a lot with it.

We've had a lot trouble forecasting it.

We still have trouble forecasting it.

But we are taking a much more conservative view now and we want to be able to meet that production forecast.

I think next year you will see us try to dial down exploration a little bit as we have more and more development on the plate.

We haven't come up with those numbers yet, but we are working on it and the balance sheet is certainly in a good place to enter some of these major development projects.

So that's a quick run through.

I would like to turn it over now over to Terry Dallas, our CFO, to make a few comments about the cash balance and how we are addressing that, and then Robert will follow.

So Terry?

Thank you, Chuck.

As you know, we commented in the last two quarterly meetings and conference calls that we had with you that the Board was reviewing our options for using up some of the cash that has resulted from the very high commodity prices, in addition to our sales of assets.

It was announced on the 28th of July after the Board meeting that we would have a combination of several transactions to use that cash.

We said that we would buy $150 million of common stock, on a previously approved repurchase plan; that we would contribute $100 million to our qualified pension plan, and that we would repurchase or redeem about half of our Trust Convertible Preferred, which should be a cost to us of about $264 million.

I think the logic behind this in a discussion with the Board was that as far as the repurchase of common and preferred, this would reduce our total dilution share count by about 4 percent.

It's estimated that our EPS will improve by about 1.5 percent with the repurchase of the common, and that our total diluted EPS should increase and improve by about 3.5 percent.

In addition, the contribution to the pension plan was calculated and determined looking at what we could justify and get authorized for a tax deductible contribution.

We were not required to make this contribution this year.

But we did know that without a lot of changes, we would be making contributions to the pension plan in late 2006, into 2007.

So we took this opportunity with this cash and with the ability to make it tax deductible we made that contribution now.

We anticipate that with commodity prices where they are, we will continue to accumulate cash over the next two quarters.

We will look at our cash balances again toward the end of the year, and after setting aside an amount of cash to take into 2005 to insure that we can complete the very large capital program that we have planned for that year, we will be once again look at our options for the use of this excess cash.

So with that, I am going to turn it back over to Robert to finish the remarks on the quarter.

Thanks, Terry.

The major elements of the financial performance in the second quarter 2004 versus the prior quarter were furnished this morning via e-mail, fax, they're posted on our website and were furnished to the SEC on Form 8(K).

This information is repeated in the last seven slides of the slide presentation, which is slides 9 through 15.

Unless there are questions, I will not discuss those items in the call.

You may of course call Investor Relations for more information on the slides after the call.

I will discuss a few other second quarter items and the latest outlook.

As I draw your attention to slide 3, just to follow up on Terry's comment about the cash, slide 3 shows a pro forma net debt amount as of 12-3-02 which has conformed to the accounting rules.

We've made steady progress to reduce these obligations, and coupled with our current cash balance of $939 million, our net is down $1.3 billion to the end of the second quarter.

If you disregard the cash, we reduced our debt to total capitalization ratio by 12 percentage points over the last 18 months.

Worldwide production volumes in the second quarter were 404,000 BOEs per day, which was below the low end of the estimate we gave on the first quarter's call.

Production was below the midpoint of the April 28 outlook by 11,000 BOE per day for the following reasons: First was the effect of higher oil prices on PSC production, which impacted 3,000 BOE per day.

Second, lower than predicted performance at West Seno was 2,000 BOE per day.

Lower gas nominations for PTT in Thailand, down 2,000 BOE per day, and longer than anticipated construction related shutdowns in the Thailand oil project, in the amount of 2,000 BOE per day.

All other factors amounted to 2,000 BOE per day.

As mentioned in today's news release, full-year production is expected to exceed 400,000 BOE per day, which is below prior expectation.

Factors of lower production from last year were outlined in today's earnings news release, which also describes our new approach to future forecast disclosures.

Today's press release also stated our composite outlook for the third quarter.

You can review the major elements on slide 4.

Since commodity prices are such an important driver of results, I want to remind listeners that forward-looking price predictions are subject to significant change on a daily basis.

Analysts should look to the changes in the latest NYMEX contract prices for oil and natural gas, and adjust their earnings estimates accordingly during the remainder of the third quarter and the whole year.

As shown on slide 5, the outlook for non-E&P and Corporate segments suggested after-tax results in the third quarter and full year are as follows: The midstream marketing segment expectations are between $13 and $17 million, for the third quarter, after tax, and between $65 and $75 million for the full year.

Geothermal’s outlook is for earnings of between $16 and $18 million in the third quarter and between $65 and $70 million for the full year.

For total Corporate and Other, the expected range of after-tax costs is between $75 and $89 million for the third quarter, and between $295 and $313 million for the full year.

The breakdown of the individual Corporate and Other segments are shown on slide 5.

I will talk a little bit about Unocal's hedging program now.

As usual, it’s dynamic as the volumes of prices are subject to changes over the quarter and over the year.

In the second quarter the hedging program had the effect of decreasing overall revenues by $41 million; which resulted in 27-cent per unit of lower North America natural gas prices and $1.94 per barrel of lower worldwide liquid prices.

We put in place several future derivatives positions that have the effect of fixed price sales for natural gas and oil.

In the third quarter we have fixed a price of $5.66 for 280 million units of gas per day.

We also fixed the price at $35.38 for 26,000 barrels of liquids per day.

You can see the details of this on slide 6.

Hedge positions for the fourth quarter '04 and the first quarter '05 are shown on slides 7 and 8 respectively.

Analysts are encouraged to check the Investor Relations section of the Unocal website, where there's a worksheet that shows the most recent hedge volumes and prices.

That's available to everyone who is interested.

Okay Anita, we've now reached the Q&A section of the call, so please begin the process.

Thank you. [Caller instructions] Our first question comes from Steve Enger of Petrie Parkman.

Hi, guys.

A couple of questions.

Chuck, can you give us your best view now on the issues at West Seno and how solvable those may be in terms of improved completions?

What have you seen here over that last quarter couple of quarters relative to some of the earlier problems that you had?

Yes, Steve, I will give a short recap.

Since the last time I talked to you guys in the quarter, we’ve made some real significant performance improvements on our drilling time and that continues.

The drilling is actually going well.

As I said, we have 20 wells drilled.

We have probably the first 8 of the next 28 fast drilled.

So we are making good progress getting the wells on.

Where are problems have been - - and the facility has been on line, I don't know the percentage, Steve, but most of the time.

We had a shutdown here a few weeks ago.

And what happened on the shut down – and this is what's worrying us right now – is that some of the wells didn't coming back on line.

They had hydrates, temporary things that we need to remove with chemicals.

Our real issue right now is what's the productivity of the deep zone.

The shallow zones are performing very much as we thought.

But when we revised our peak forecast from what it was the beginning of the year -- from 45,000 down to 25,000-to-35,000 – that reflects what we've now seen from the productivity of these deeper zones.

The sands simply aren't as connected as we had hoped, and in some places we are getting a lot shallower intervals in the deep zones.

So that's a lot of the revision in the forecast.

The operational part, the facilities part I won't say we've solved every last nut.

We probably will have a shutdown in November that we put into the forecast for some other surface work.

But I think we are now of the view that we won't see the peak production rates that we thought because of the productivity of these deeper zones.

So, drilling is going well.

Operations are going reasonably well.

But the subsurface deep zones have been disappointing for us.

And that's the reason for the revision in the forecast largely.

Okay.

You have given an '04 exit rate and you are going to have most of the wells in Phase 1 drilled by the end of this year.

Do you think there's much upside then as you look ahead to '05 relative to that year-end '04 exit rate?

Or are you more likely to take a conservative view that you will maybe just be able to hold flat?

Yeah, realistically, I think we'll have an an annualized increase because obviously we are slow in ramp-up in this year.

So '05 compared to '04 will be up.

But I think we are taking as you said a conservative view that we will exit according to our forecast right now we will probably peak in February or something of next year, depending on when the wells are completed.

We have a couple of horizontal wells going in that I hope give us some upside there, but I'm not willing to forecast that.

I've been burned enough as you well know.

So we are taking a fairly conservative view and we would say that the peak will probably be in the first half of next year.

Okay.

And then your East Kal oil volumes used to run kind of 25,000 to 30,000.

In the second quarter you were down to 19,000.

Is that always all PSC effects, or are there some natural declines or other issues going on there?

I think you also mentioned some small facility issues?

Yeah.

It's a combination, Steve.

There were certain PSC price effects.

I don't remember the number.

We have natural decline on the Indonesian Shelf, not nearly as steep as in the Gulf of Mexico, but we had facility downtime here.

That was, it was probably off, I am going to guess 3 or 4,000 barrels a day because we shut down some facilities for some frankly unplanned refurbishments, and some safety issues and we just wanted to make sure we were operating safely.

You will see third quarter, I think in Indonesia, come back and recall that production.

But we don't forecast certainly anything above that for '05.

We think Indonesia Shelf will continue to decline.

And we are not as investing as much money in there as we used to.

Okay.

Last one, Chuck.

You guys have had a multi-year program now looking for big oil, deep oil in Indonesia.

You've had some modest success at Ranggas.

Is there any reason for optimism as you drill in some of these outboard PSCs or other prospects you had that there will be higher liquids content?

Yeah and that's a fair assessment Steve.

I think we've had modest success for oil there.

In the press release today we talked about the deep Ranggas test which we were quite hopeful for of finding some significant oil deep, and we did not.

We had a trap failure there.

The drilling in Popodi and Popalong we do think has oil potential, but it's a lot higher risk.

I need to be clear about it.

These are huge structures and there's not been a well drilled out there.

But this is out towards the center of the Rift Basin, if you will, and we think there's potentially an oil source there.

Quite honestly, we don't know if it's oil, gas or what.

But it is a different type of play than West Seno, Ranggas and Gehem, and that's why we are picked up the block.

We don't know right now, but stay tuned.

Thank you.

And our next question comes from Fred Lauffer of Bear Stearns.

Good afternoon, gentlemen.

I had a couple of questions.

First Chuck, you indicated that on West Seno peak production may occur in February.

What exactly would be the production profile from there?

How long can you hold peak?

Fred, I hate to hazard a guess.

The peak production I think we've said is 25,000 to 35,000 BOE per day.

But I will tell you, we are roughly, I don't know today, but we've been around 22,000, 24,000 BOE per day for some time.

And we will be adding these new wells, so we will see how the new wells deliver.

How long can we hold that peak, Fred?

I don't know.

We will be happy to hold it through next year.

That's about as far as I can see.

Okay.

The release talks about reasons for the production shortfall and, Robert, you ran through some of the variants.

But there's a category here just attributable to “other various factors” of 10,000 barrels of oil equivalent per day.

Can you give us the specific breakdown on that 10,000 barrels per day, how much of that is natural decline and other factors?

It's a lot of different factors, including the prospect of hurricane shut-ins, others below DCQ, consolidations and some of the other places; if I were to give you all the factors there would probably be 20 of them that add up to about half of the 10,000 thousand BOEs per day.

So it's not any one thing.

I would say that the places where we are susceptible to the kind of declines that you're referring to, it seems like the Gulf of Mexico is stabilized now.

There could be a little bit in Alaska and East Kalimantan, but it's not a significant part of that 10,000.

It's just basically part of our new approach.

Is some of it from that sale in the Far East?

Say it again, Fred.

Is gas nominations part of that, too?

Yes.

Can you break that part out?

No, it's just a lot of little things, Fred.

I think if you look at our guidance worksheet, you can see what the DCQ is and what our maximum production is.

Look at the past couple of quarters.

I think you can make a pretty accurate estimate of what the oil production for each of those countries could be using that as an aid.

Fred, this is Terry.

I would classify that 10,000, as just this is how we are going to be conservative.

We went through and said, what else could go wrong that we haven't anticipated?

And as Robert said, it's a lot of little things.

But it's nothing specific that we know about because it would have been in some of the other different categories.

We are going to beat this forecast.

That's what we've decided.

That's the 10,000, and some of the things are just anticipated ranges around what may happen.

Okay.

What quantity of proved reserves have been sold so far this year and what were the total proceeds?

I'm going to do have to this off the top of my head, Fred.

It's was about 8 million barrels for Brazil, which we got $68 million for.

And it was about 5 million barrels for the fee minerals properties, but you can't really say that was a reserve sale.

That was over an exploration property sale.

We got $178, million but that ratio would be out of whack.

But the 5 million, is what shows on your books?

That's right.

If you - - and I'll check that and, it's 5 to 7, I'll call you back if it's not right.

But if you look at the reserve table at the end of last year the affiliate reserves for Brazil are highlighted as an equity affiliate there.

And it's just those two sales so far this year, right?

There was a little bit of Gulf asset sales, and it would be miniscule.

Then the other assets that were not oil and gas; there was a geothermal project and pipelines and properties in California.

Okay.

Great.

Thanks, guys.

Thank you.

And our next question comes from Mark Gilman of Benchmark.

Guys, good afternoon.

I had a couple things.

Chuck, what did you have on the books for West Seno as of year end of last year?

Reserve-wise, Mark, we don't disclose project by project.

But what I said in the earlier remarks are that we had - - with our current estimate right now, we anticipate a write-down of less than 10 million BOE.

But obviously the production is about half of what we thought it would be at the very, very beginning of the project ,and reserves will reflect that.

You don't want to give me what the number was as of December 31, '03?

No.

Frankly, I don't know the exact number.

Okay.

Are there any conditions at this point that would allow for Phase 2 to proceed?

Yeah, let me elaborate on Phase 2.

This is kind of breaking news.

We thought, we thought Phase 2 was pretty well in hand, quite frankly, until we just opened these bids and the EMC prices as you may can guess throughout the industry have come up a lot, more than we could have ever imagined, including the same contractor that we had originally tendered to.

So we are scratching our heads right now, Mark.

We don't know the answer, except to say that we will explore some other options.

And one of the things we're looking at is, can we reach part of Phase 2 from Phase 1, without a lot of facilities?

We are considering a different kind tendering strategy and retendering.

We're doing a whole bunch of things right now.

I don't know the answer.

We haven't given up on Phase 2 by any means, but it will delayed and that was the intent of the disclosing.

So it's still conceivable at some point it might proceed even on the basis of the reduced reserve potential?

Yes, yes.

I mean, we had obviously, Mark, before we had tendered we recognized the reduced reserve potential and cooked that into our economics.

What surprised us was the high cost of the tender.

Let me just ask one or two others if I could.

It looked to me as if in the presumption guidance, the Mad Dog numbers net to you looked a little light.

Is that because of an extended ramp-up, or has something changed there?

No.

I was I will say it's a philosophical approach.

I just saw a thing yesterday from BP that actually had a little bit higher numbers in it.

There will be a ramp-up.

There are only four wells completed in Mad Dog, or will be completed, and we'll be drilling additional wells up to 18.

So there's a ramp-up on Mad Dog.

But I think we are trying to be very circumspect and be reasonable.

Those were the numbers BP was using last year.

I think they are a little more optimistic this year.

In terms of our working interest it's not a big shift for us.

Okay, one more if I could.

Vis-a-vis Gendalo, I know we've been over this issue a number of times in the past, but will you proceed without having a firm gas sales off-take agreement?

Yes.

That was a yes, Terry?

I didn't hear you, I'm sorry?

I said yes because we will have enough contractual gas sales on our own contracts to basically do the baseline economics of this project.

And then there would be a lot of upside production that will be available to sell, either into the spots or to back-up anybody else's production.

So, we will proceed with this because, quite frankly, we need the production for our own contracts.

And we are not going to go into the details of the project, but as it is designed, it's a very efficient project as far as cost per production.

Let me add.

I'll give you some color.

Looking at the scoping economics for Gendalo, these are wells, individual wells that will probably be 150 BCF wells or 70 or 80 million cubic feet per day wells.

They havea world class reservoir.

I always like to assure investors this is not West Seno, it's quite a different setting or we wouldn't be undertaking this kind of project at that water depth.

And the other thing we're seeing, Mark, as you're well aware, is Indonesia is scrambling to make sure that they have productivity capability to fulfill gas contracts that they have both from Bontang and backups to Tangu.

There's a lot of moving parts in Indonesia to ensure that they can fulfill their contracts.

So we anticipate we will have the full support of the government of Indonesia to develop this.

Can I just ask you the same question with respect to Gehem-Ranggas and the complex that you envision there?

Will you proceed without a firm off-take agreement?

I am not going to answer that as definitively.

I guess what I would say is that's a different one because there's a lot of liquid.

That's an oil project.

And we had designed a project that basically was economic just on the oil with only limited off-take, and we actually booked some reserves last year.

Then we found Gehem, which is right next door as you know, which has substantial amounts of liquid and a very efficient gas reservoir.

We have a team that actually is looking at these two projects together right now, so we will put in a plan of development some time before the end of this year.

But the way I would describe that project, it's going to be sitting there.

It will have extremely high capacity to deliver gas.

We will know a lot more before we have to commit to it.

It won't be a project we have to commit to until 2006.

I would anticipate that we will know what gas market that project goes to at that point, because we are in discussions about the fill-up packages for Bontang.

So I would anticipate and assume that we will have contracts at that time.

But if we don't, we will still make judgments about what the market is, and what is the total risk of proceeding in this project without them.

So that's a long-winded answer to say we may proceed without contracts, but we won't proceed today into any large investments without them.

Okay.

Thanks very much, guys.

Thank you. [Caller instructions].

Our next question comes from Albert Anton of Karl H. Fortine.

Yes, a couple questions on the Asian things.

In the Bontang area, how much gas are you certified versus Total and others?

And beyond that, of cours,e it doesn't pay to certify every last MCF of gas if you are going to have it sit around for a few years.

How much gas do you think you have available beyond that?

This is Terry again.

I'm going to talk in past tense, because we are not going to talk about how much we certify going forward.

It will end up being a competitive situation, or could end up being a competitive situation.

But the last public numbers which are reasonably recent, Total had 11 TCF.

That was certified.

Now they may have certified some more that we are not aware of.

But that's what they had recently.

We had something around 3 TCF that we had certified.

We have had other discoveries and there has been other certification work that's been going on.

So our number is somewhat larger than that.

And then VICO Partnership has about 1 TCF.

So that's the starting point for the fill-up packages, which as I said, are in negotiation with the various customers and will come on approximately 2010.

All those numbers could change.

I think they will probably all will move up somewhat from that play.

I thought you used the figure of 4 or 5 TCF for yourself in the past?

No, we never said anything other than what I just said for certified.

I think we believe we have multiple times that 3 TCF that we could certify.

But just as you pointed out yourself, it does cost money to do the delineation and appraisal work, so we will proceed on a fairly deliberate basis about what we need to certify over what period of time.

Most of that certified gas, the 3 BCF-plus that Terry has talked about, is in the Gendalo complex.

We really haven't chosen to certify a lot in Gehem and Ranggas and Gula, and ther discoveries we've had, for the reasons you just said.

You have talked about having 30 percent to 50 percent of the Bontang gas post-2010.

We think we have the bottom end of that already.

And then it's just an issue of how much we certified, or there could be other commercial arrangements that we come to where we don't all have to certify.

But those are issues that will be left for the Partnership to determine as we are filling up Bontang.

But we believe we are at the bottom end of that range already in terms of discovery volumes today.

Okay.

One question on Thailand.

There's bottlenecking going on in the pipeline, I wonder what effect that will have on you in the next year?

Yeah, we've been in discussions with PTT on the debottlenecking and working hard to get enough wells drilled in fact this year to make sure we can meet that additional capacity.

I'm trying to remember the numbers, Robert.

About 100 million cubic feet per day is what they told me in round numbers, that the debottlenecking will make additional capacity available, and we have the gas to deliver to that.

So we are anticipating producing additional gas into that.

We continue to have a policy of over-developing, and that's why we have a lot of PUDs there to make sure we can meet that capacity when they need it.

Okay.

Thanks very much.

Thank you.

And our next question comes from Don Textor of Dorset.

Chuck, my questions have been answered but thank you very much.

Thanks.

I never heard you not have a question, Don.

Okay.

I don't want to beat a dead horse, but the Gehem--Ranggas joint development plan that you referenced.

Taking that development in '05, is there any guidance as to size of project, in terms of production numbers gross?

Don, I won't tell you the production numbers because we are still working on what the development concept is.

But raw numbers, we say we have 2 to 3 TCF of gas and 75-150 million barrels of oil there - - or liquids there, primarily oil.

I will say this: there's some additional prospects that probably, ultimately we'll drill to add into that.

Between Gehem and Ranggas, it's a sizeable accumulation.

But I'm not ready to tell you what the production rates will be yet.

While I've got you I might as well ask one other question.

On Gula, your reserve range is sort of 1 TCF to 8 TCF.

I did notice that you drilled a successful stepout well 3.5 miles away.

Is there any way to narrow that range, or are you still going to wait on that?

We are going to wait, Don, as you you've heard me say before.

Gula is 10 or 12 kilometers long, the feature is.

We stepped out a few kilometers and got a decent well.

We will probably be drilling one more well – it won't be called Gula, but in effect it's an extension of Gula – later this year, and then we'll come back and probably revise what the numbers.

I've learned in my career that two wells do not make 8 TCF.

So we're going to be cautious until we drill another well out there.

It's a sizeable feature.

But it's one of the things in Terry's point – we’re not anxious to certify it, because we don't want to spend a lot more appraisal money on it yet.

But we know that post-2010, it will be part of that Bontang fill up package.

Thanks, Chuck.

Mr. Wright, at this time, I show no further questions.

I'd like to turn the meeting back over to you for any closing remarks or final comments.

Okay.

I just want to thank everybody for tuning into the call.

Again, if you have any questions for the Investor Relations staff, call me, Nancy or Lee, and we will be glad to help you.

This concludes the conference call.

Thank you.

I would like to thank everyone for participating in today's teleconference call and have a good day.