雪佛龍 (CVX) 2003 Q4 法說會逐字稿

I’d like to welcome everyone to Unocal’s fourth quarter conference call.

At the request of Unocal, today’s conference call is being recorded for instant replay and transcription purposes.

Any objections, you may disconnect at any time.

Also as a reminder, following today’s presentation there will be a question and answer session, and during that time instructions will be given if anyone has any questions.

I’d like to introduce our first presenter, Mr. Charles Williamson, CEO.

Sir, you may begin when ready.

Thank you.

Thank you all for joining this afternoon.

Last week, I think most of you know, that we suffered a very tragic loss with the sudden death of Tim Ling, our president and COO.

Needless to say, it’s been a difficult week.

Tim was an extraordinary person in many different ways and a vital part of our executive team.

Many of you knew Tim and it is difficult to accept that Tim is gone at the age of 46.

He left behind a beautiful family and three young sons.

He was involved in numerous community and industry activities and his loss has been felt by the many, many people he interacted with.

Tim’s life was celebrated on Sunday with an extraordinary service for an extraordinary guy.

We’ll certainly miss Tim’s energy and his passion for Unocal’s success.

I also want everyone to understand that we can take solace in the strength of the leadership team that Tim was part of building.

We’ve got a motivated and qualified team here at Unocal that will deliver the performance that we’ve been trying to achieve, so I am confident that we will continue to do so.

Before Robert reviews the financial results, I want to take a few moments and just update you on some results from 2003, but more importantly, on what we have ahead in 2004.

I’ll reference the slides that have been posted on the Internet and accompany the call.

Slides 2 and 3 I think are a summary of 2003, I won’t spend a lot of time on that.

I’ll simply say that we had an exceptional year operationally and financially, it’s summarized on those two slides.

I think we delivered on most of our forecasts.

We have good momentum, certainly, going into 2004.

We repaid a lot of our debt, restructured the Gulf of Mexico and had very good success with the drill bit in the deep water particularly, and more importantly, probably than anything, we’ve made major progress on some of the large projects that we’ve been talking about the last few years.

On Monday we released our finding and development costs and reserve replacement, that’s covered in the press release.

Terry will talk about that in a little more detail a little bit later in the call.

I just want to say up front, I know there is a lot of angst in this industry about reserves, but I am very confident, certainly in our process.

We’ve had a very good process in place for several years now, and the ledger is in a very good place, I think, and Terry will detail some of that.

We have a process that has accountability all the way up to the CEO, and I think it’s been a well-tested process.

I’d also like to emphasis in our finding and development costs last year, we had an exceptionally good year, I think, in international with F&D of less than $5, and of course that’s a large part of our growth in the next five to 10 years.

I’d like to now switch to 2004, and there’s a slide that just summarizes, slide 4, what we have ahead – that’s detailed also in our earnings release, I won’t belabor that – but it’s an important year for our major projects.

As you see, like Azerbaijan, Mad Dog in the Gulf of Mexico, Bangladesh, expansion in Thailand, et cetera.

So we have a lot of things going on this year.

I am going to just touch on a few of the first quarter and second quarter events particularly and update you on some of our, particularly our appraisal and exploration drilling.

I want to emphasis again, I think that we have a much more stable North American base than we’ve had in the past, with a smaller Gulf of Mexico component, and we’ll talk about that program as well.

Let me just hit a couple highlights for the first and second quarter on the drilling program, and then Robert will give you some more of the financial details that come with it.

Let’s start in the deep water Gulf of Mexico, where we had a lot of success last year and in the fourth quarter with the BP Puma discovery we participated in.

We finished the year with I think a really solid program in deep water.

We are currently drilling in deep water in the Gulf on a prospect called Myrtle Beach in Green Canyon, the southwest part of Green Canyon.

That’s a deep well all the way down to just below 30,000 feet.

We should reach TD, the well is going fine, we should reach TD probably late in the first quarter sometime and expect to have some pretty interesting results there.

This is a really important well in terms of turning on a lot of other prospect inventory surrounding Myrtle Beach and south Green Canyon there.

If you look at the trend line on a map there with Mad Dog and Puma, Myrtle Beach, we have several other prospects in a line right along that, so we will be watching Myrtle Beach closely.

Also in the deep water we are currently participating in a Mad Dog deep test.

As you remember, we had the St. Malo discovery last year in the lower tertiary, and [easine].

The Mad Dog deep is a test of the lower tertiary and [easine] beneath the Mad Dog field.

That spudded, I don’t remember exactly when, within the last week or two weeks.

It’ll probably early in the second quarter that we would receive results on the Mad Dog deep test.

And of course, that’s a test different than Myrtle Beach, it’s the deeper section on a lower tertiary.

We have appraisal coming up later in the year, my guess is second to third quarter we are still working that on St. Malo.

We don’t have a lot more news to tell you about St. Malo other than we are trying now to plan the appraisal well and we hope to have a well drilled in [Lahoya] probably sometime mid-year or later, but those plans are not finalized yet.

We also will probably go back over to Alaminos Canyon with a prospect called Tobago, following the Myrtle Beach well that we are currently on, and that’s in the Perdido Fold Belt, near Great White and Trident.

So the message in terms of what we’re doing in deep water Gulf is we have a full program this year.

The front part of the year we have a pretty good line of sight on, the second part of the year we have a lot of choices on, and some of it will be dependant on partnership, some will be depending on results from the first part of the year’s drilling.

But we have lots of good choices and the deep water Gulf for us is becoming a lot more of an exciting area certainly than it was a couple years ago.

I’ll mention the deep shelf part of the Gulf of Mexico.

Last year we had a very large program in terms of nearly $70m or so of capital being spent in the deep shelf program.

We had some early success, certainly at the Harvest prospect and Red Pepper, then we had four key wells at year end, which we won’t disclose all of the specific results other than to say, three of the four wells are down, we’ve had some success in the shallow horizons on a couple of them, but the deep zones, with the exception of one well we have not finished yet did not turn up good commercial accumulations, so we had some disappointment, in my mind, in the tail end of the deep shelf program, and so accordingly we’re going to scale that program back for 2004 and as we said in the press release, probably spend a little bit less than half of the capital that we had anticipated, and we’ll see how that goes as the year goes on.

But we will – we are not exiting the deep shelf, but we’ll certainly be more selective in a scaled-back program.

And again, we have one key well that’s just about at objective right now.

We’ve had some mechanical problems, but we should be down here in the next two weeks that I hope give us a little more joy.

So that’s the deep shelf program.

I’d like to mention at the same time we’ve made some management changes.

We now have combined the deep water Gulf of Mexico exploration and appraisal program under the leadership of Mike Bell, with the deep shelf program.

So Mike Bell is in charge of exploration now throughout the Gulf of Mexico, and that’s important for us in order for us to frankly, to optimize our portfolio and make the choices on capital between the deep shelf and deep water we need to.

Mike’s done a great job for us in deep water and I’m sure will do the same with the shelf.

I’d like to also add we’ve added a new member to the staff, our SVP for exploration, we’re very pleased to have attracted James Painter, who many of you know, used to be the VP of exploration of Ocean Energy before that and then lately Devon Energy.

He will be in charge of our worldwide exploration program, and is joining us officially next week.

Just delighted to have James on board, it will be a great addition for our portfolio.

Deep water in Indonesia, I’ll just touch lightly on this, we can cover more in Q&A.

We’re currently drilling still on the Gehem 2 well.

Remember, Gehem was a discovery we had last year in deep water Indonesia, a gas discovery.

This well is a deeper test as well as an appraisal test of the gas.

We cannot – we are not ready to the results of it, and I will tell you it is certainly a successful appraisal well.

We are still on the well, we have partners and confidentiality issues.

We’ll put a release out probably within the next two weeks to give you more details about the well, but we are proceeding certainly with our fast-track plan for development of the Gehem field.

We’ll go to [Gola] next which is a huge anticline just to the south of Gehem.

We drilled a shallower well there about a year, almost – in fact more than a year, a couple years ago, and had some mechanical problems, could never get the well deep enough.

That’ll be an exciting test for us.

That will be right after Gehem 2.

The rest of the Indonesian program for the year, just conceptually we’ll test our new PSCs that we’ve had no wells drilled in outboard of the discoveries we’ve had, and then we have a deep Ranggas test that tests for deeper oil that we had found potential in from some of our earlier tests.

So we’ve got a full program in Indonesia and we can detail more of that as the year goes on, but I just wanted to emphasis between the deep water Gulf of Mexico and deep water Indonesia, we have some very important big wells over the next six months that we’ll be talking about.

So there’s no shortage of things to talk about, we can – the major projects that will be our large production jump in 2005, we can update you on in the Q&A if you like, but Azerbaijan is going well, our Thai oil project is well along, Bangladesh, all of them are progressing well and so we still feel very confident about, particularly 2005 and beyond.

So I am going to stop there, turn it back over to Robert who will give you a little bit more summary on the quarter and some of the things ahead.

Thanks, Charles.

First a few housekeeping matters.

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

Please call the investor relations team in either El Segundo or Sugar Land if you have any questions.

As Charles mentioned, there are some slides available for you to view to supplement what we are saying on the call.

There are quite a number of slides this time, and we are going to be going back and forth so we will call the slides by number when we want to refer you to those.

And there will be some that we do not refer to that are just back up.

Our remarks today will include certain projections and estimates, which are obviously forward-looking statements.

We will also mention some non-GAAP measures of financial performance.

Please review our statements and reconciliations on those matters in today’s press release, in the quarterly fact book or on page 56 through 68 of the Unocal 2002 SEC Form 10-K.

The major elements of financial performance in the fourth quarter versus the third quarter of 2003 were furnished earlier today via email, fax, are posted on our website and were furnished on the Form 8-K with the SEC.

If you missed the earnings variance information you can view them on the last eight slides, slides 19 to 26.

But unless there are questions, I will not discuss the variance factors or special items on this call.

You may of course call investor relations for more information after the call ends.

Worldwide production volumes in the fourth quarter were about 420,000 boe/d, which is 10,000 boe/d below the low end of our estimate on the third quarter call.

While there were several pluses and minuses, production at the West Seno field in Indonesia was the largest factor responsible for being below expectations.

West Seno oil production averaged 93,000 bpd in the fourth quarter, with a year index rate of 18,500 boe/d.

Premature equipment failures on the floating production unit and emulsion treating problems have continued to affect us over the fourth quarter, but started improving by year end.

Development drilling continues on the tension leg platform.

Eight wells were completed at year end, including a high rate horizontal well which exited 2003 at 46,000 barrels of oil per day.

An FPN shutdown occurred from January 12th through February 1st to correct those construction deficiencies.

A ninth well has been completed and will be perforated soon.

The remaining construction and commissioning activities are expected to continue through at least the first quarter of 2004.

The resolution of these top side problems at West Seno is anticipated now that the shut down is behind us.

Completion of 20 additional development wells are planned by the end of 2004.

The ramp up of West Seno is the most important element in our plan to grow our consolidated company-wide production back to the full year levels of 2003 of around 450,000 boe/d.

If you conform 2003 from the 7.8 percent of production we sold during the year, production would have come in at about 415,000 boe/d.

Just as we were able to add back production in most of the reserves sold in 2003 through total reserve additions, we expect growth from new sources such as West Seno to replace production sold in 2003.

Of course the effects of cost recovery, volume fluctuations and foreign production sharing contracts due to commodity price changes, changes in gas denominations in Thailand and other factors could influence our first quarter and full year production estimate as well.

Timing of exploration and production costs in the fourth quarter obscured the company’s cost reduction progress.

G&G purchases in the fourth quarter were around $15m above the prior quarter, or about 40 cents per worldwide BOE.

Special well repair, timing in the lower 48 business added another 22 cents to lower 48 operating costs for BOE.

And timing of litigation costs in the lower 48 added around 53 cents to unit costs for other E&P expenses.

For 2004, Unocal expects non-dry hole exploration expenses to be flat to down 10 percent from full year 2003 levels.

The total 2004 exploration drilling program will be comparable to 2003, dry hole expense should be comparable as well, depending of course on our success rate.

Worldwide unit operating expenses in 2004 are expected to be flat to 10 percent lower than full year 2003.

Worldwide unit DD&A and other E&P expenses in 2004 are expected to be mostly flat with 2003’s.

Today’s press release stated our consolidated outlook for the first quarter.

You can review the major elements of that yourself on slide 12.

Since price is such an important driver of results, I want to remind you that forward-looking price assumptions are subject to significant change on a daily basis, and analysts should look to the changes in the latest NYMEX contract prices for oil and natural gas to adjust their earnings estimates accordingly during the remainder of the first quarter, and the whole year for that matter.

As shown on slide 13, the outlook for non-E&P and corporate after-tax results in the first quarter and the full year are as follows.

The trade segment expectations between breakeven and plus $1m for the first quarter, and between zero and $4m for the full year.

The outlook for the midstream segment is between $20m and $25m in Q1 and $65m and $75m for the full year.

Geothermal outlook for earnings is between $12m and $18m in the first quarter, and between $50m and $65m for the full year.

For total corporate and other, the expected range of after-tax costs are between $76m and $93m for the first quarter, and between $288m and $319m for the full year.

The breakdown of the individual corporate and other segments is shown on slide 13.

We’ve also put in place several derivative positions that have the effect of fixed price sales for natural gas and oil in 2004.

In the first quarter, we have fixed the price at $6.25 for 448m units of gas per day.

We also fixed the price at $30.14 for 30,000 barrels of liquids per day.

See the details on slide 14.

For the full year 2004, we have fixed the price of gas at $5.80 for 211m units per day.

For liquids, we’ve fixed the price at $30.40 for 14,000 bpd.

See slide 18 for the full year and slides 15 through 17 for quarters two through four of 2004.

Our hedging program is dynamic, and analysts are encouraged to request the latest spreadsheet of hedge volumes and prices from investor relations as we move through 2004.

Now for a perspective on yesterday’s reserves news release and our processes for reserves, I’ll turn the discussion over to Terry Dallas, our CFO.

Thank you, Robert.

I would direct your attention to slides 7 through 11.

We released yesterday on our 2003 finding costs and reserve replacement.

As Charles mentioned earlier, we did have a very good year.

The major reserve accumulations that we booked in 2003 were we booked the Ranggas discovery, the oil discovery in Indonesia.

We booked a lot of extension reserves and the results of exploration drilling in Thailand, and then we booked Merah Besar in Bangladesh with the signing of a new gas sales agreement with the government utility.

We were very happy with our international finding and development, and actually we were happy with the U.S. finding and development outside of the Gulf of Mexico shelf and deep water program.

As Charles mentioned, we have stated throughout the year that the Gulf program on the shelf was going to meet our goal of $8 F&D or we were going to adjust that program until we had the size that was appropriate for that investment, and we have cut that program back.

We will continue doing drilling there, but we released a lot of information on the back of that press release to show you some of the detailed finding cost by region.

I think you would note that Canada, Alaska and Pure, which is listed as other lower 48 all had very respectable F&D and reserve discovery rates, and we acknowledge that we still have to work on the shelf to get it into our goal of $8.

I would ask you to move to slide 8.

Unocal has historically had relatively high PUDs compared to our competition, proved undeveloped reserves.

Our explanation of that is annotated on this slide.

We have about, of the 880m barrels of PUD reserves, about 40 percent of that are in named projects that are in construction today.

We would expect those PUDs to be moved to developed reserves over the next three to four years, depending on which projects we’re talking about.

Of the remainder of the PUDs, the largest portion of that is Thailand.

I would ask you to go to slide 9.

That’s an explanation of, for those of you who don’t follow us as closely about what we do in Thailand, many of you are aware that Thailand is currently in construction for a third pipeline.

The kingdom is now at gas capacity with the infrastructure that they have, and they are actually burning fuel oil in their power plants.

Unocal is in negotiation, which started in November to increase our contractual gas supply to the government utility by almost 50 percent over the next four years.

In order to do that, we had to demonstrate that we had proved reserves to meet that additional capacity.

I think one of the statistics that we would note for you is that today Thailand has about a 5 R to P ratio, when you compare that to our current contractual quantities with our current proved developed reserves, and we have about a 13 year R to P when you take that same ratio to all proved reserves, both developed and undeveloped.

When the new contract is signed and executed, as I said our daily quantities, delivery quantities will go up by almost 50 percent and we would expect those ratios, with the PUDs and proved developed that we have today to be an R to P of roughly eight to 10 years.

We actually, our target there is to ensure that we have proved ratios over about 10 years, given that Unocal has historically been the swing producer in Thailand and we consider it important that when our customer calls for gas, that we can produce.

I would ask you to turn to slide 10, this is an outline of our reserve quality assurance process.

As Charles mentioned, this has been in place for a number of years now.

This whole process reports to me and I take it very seriously, since I have to certify all of our financial statements, as does Charles.

I would ask you to close by looking at slide 11, and this is just a summary for the year 2003.

The level of reviews that were given to various reserve issues, we have a policy that we look at about 50 percent of the reserves every year and all of the major changes, and that 50 percent is on a rotating basis, so we get through the whole reserve ledger about once every three years, and of course we see any changes, any adds and any major revisions in the year that we book.

I will close with that and turn it back over to Robert.

Thank you very much.

Okay, Jason, we’ve reached the Q&A section of the call, if you will start that process please.

(Operator instructions) Our first question comes from Argen Merty of Goldman Sachs.

Thank you.

I guess first of all I want to express my condolences to certainly everyone at Unocal, but most of all to Tim Ling’s family regarding the very shocking loss of Tim last week, I was certainly very saddened to hear that news.

Charles, could you provide any comments on predrilled reserve estimates regarding some of the deep water Gulf of Mexico prospects you talked about, like Myrtle Beach, Mad Dog Deep, Lahoya, maybe Tobago?

Argen, first of all, thank you for the condolences.

You know, as you know, I think we have chosen not to talk about predrilled resource estimates on any of these deep water plays.

It goes without saying that we are looking at things that are a couple hundred million barrel size or bigger, or we wouldn’t be drilling at that depth and that cost.

You know I think Argen that we’ve learned from the past that I can give you a wide range of predrill estimates, I’m not sure it means a whole lot other than we are looking at things that are more than a few hundred barrels in size.

Okay, that makes sense.

The other I guess follow-up question is I believe your first quarter production estimate is plus or minus 410,000 boe’s a day with a full year average still at 450.

Could you just highlight some of the things that are coming on over the course of the year?

I know West Seno ramps up, but anything else that contributes to getting to the full year average?

Thank you.

Argen, you’re right.

The main driver, let’s be clear, is West Seno ramping up, and there are some other things I’ll mention here.

But let me just add a little more color on West Seno because that has really been our production disappointment, if you will, of all the properties we have, and it’s only a disappointment from the standpoint of timing.

I think we have a lot of startup issues that we’ve talked about.

As Robert said, we actually now have 10 wells drilled, we are coming back on line after a two-week shutdown, we are up to seven wells this morning, so the ramp up of that will determine how successful we are in getting to the annual average of 450.

We expect that to be, rough numbers Argen, 10 wells have produced about 20,000 BOE per day on a gross basis.

When we have 28 wells drilled, you can do the math, but we should be up over 40,000 BOE/d by the end of the year with all of the development wells drilled, and that will be the single biggest increment in the production change.

Other things we have, there is no single major project.

I will say in Thailand there have been some operational issues to the north of us there, so we’ve been making pretty good production in Thailand, better than we expected.

So we may get some uplift out of Thailand that may not be in everybody’s forecast as well.

We have the capacity to deliver it, that’s a market determined process, and as Terry said earlier, we’re the swing producer there.

I’ll say the same in Bangladesh.

We’re actually becoming, we are the swing producer in Bangladesh and the demand there seems to continually outstrip what we had expected, so you’ll probably see some uplift from Bangladesh gas through the year as well, and we certainly have the capacity for that as well.

I’ll ask Robert or Terry if they have any others to add, but those are the main things.

There is no big single project, that’s 2005 and beyond.

It’s mostly West Seno.

That’s terrific.

Thank you very much.

Thank you.

Our next question comes from Steve Enger of Petrie Parkman.

Thanks.

Charles, a little more follow up on that if I may.

On West Seno, can you split out, I think you talked about getting to 40 mboe/d gross by the end of this year.

Can you split gas and oil, roughly, and what’s your net take of the oil I think it’s around 75 percent, is that –?

The cost recovery there is more like around 90 percent, I think, if you want a round number.

So of the gross, most of it is ours.

Oil versus gas, let me tell you where we were at the end of the year.

We were producing roughly 14,000 bpd of oil, and the rest gas, and 13,000 something like that.

And about, I think 35mcf/d or 40 mcf/d of gas.

As we go forward, we’re not sure – I don’t think the mix will change appreciably.

So when I say 40,000 I hope it’s 45,000, but it will be on the order of 40,000 to 45,000 when the wells come in.

And I don’t have in front of me, Steve, we can get back to you what the gas/oil split is, I just don’t remember it.

At one point we said we’d be at about 100mcf/d of gas, I don’t know if we’ll be there by the end of the year or not.

Real clarification on gas, Charles, is that for the most part isn’t that replacement of gas that had been produced elsewhere, rather than a new increment of sales?

Yes, that’s right.

We’re banking that gas, essentially, into the existing contracts we have.

And your expectations on peak rate, is that any different now, only delayed in time?

No, I’m sorry, I didn’t address that.

The peak rate – we have two phases, right?

This is phase 1.

We still think the peak rates for phase 1 will be around, I think it was 45,000 is the number we had out there, boe/d.

We don’t see that any differently.

You know, quite honestly the wells have been better than we expected in terms of the reservoir, you know we’ve encountered the pay sections, et cetera.

We’re always getting surprised on gas versus oil, so I’m not as willing to hang my hat on what that split will look like, Steve, but we found some pretty good oil sands.

The horizontal wells, as I think Robert mentioned, is a good example.

We are now thinking about putting a couple more horizontal wells into the oil sands, to accelerate some of the oil production.

So peak rate is the same, it’s been delayed because of the start up issues.

Peak rate, when you add phase 2 will be more like above 60,000 boe/d.

When we designed the phase 1 and 2, and this is still, we still think the same, we designed to keep the peak longer rather than have a higher peak between the two phases, and that would be around 60,000 plus boe/d.

I don’t think that’s changed.

Okay, thanks for that.

And a second question related to the Gulf Coast operations.

In September you outlined a plan for production that essentially would hold output flat from the lower 48.

With the reduced capital spending that you plan now for the deep shelf program, is that still realistic?

Can you talk about what role the peer program may play and then an add on to that, the unit cost trend is certainly continuing to head the wrong way.

I know Robert made a couple of comments specific to the fourth quarter, but over a multi-quarter period now those unit costs continue to rise.

If in fact production is down, how do you deal with that?

Thank you.

As you said, in September our goal had been, if we could, to hold production flat particularly from North America.

We talked about 180,000 bpd to 200,000 bpd out of North America.

And really, the only thing that’s changed, I think, is just what you’ve said, is our lack of deep shelf success.

Let me just give you the math.

We had in 2003 in the Gulf of Mexico shelf, we had about roughly 6,000 boe/d of production from the deep shelf existing discoveries.

You know, in the forecasts going forward for 2004 that you are talking about in September, I don’t know the exact number, Steve, but we are on the order of another 3,000 to 4,000 bpd assuming some deep shelf success.

So what’s at risk, not having had that success to date at least, is probably 3,000 to 4,000 boe/d in the Gulf.

And that may decline, if frankly if we don’t have any other deep shelf success, then we would lose some barrels there.

We probably will reallocate some of the capital that we talked about into, as you said, the Permian or somewhere else where we can get some quicker production turnaround and a decent margin.

So I won’t sit here and hold my hand over my heart and say that the Gulf is going to be 62,000 bpd or 60,000 bpd, whatever we had in the forecast, but it won’t be very far off, Steve, even without deep shelf success.

And we may reallocate some of that capital where we can claw it back from the Permian.

But we’ll kind of see how we go as we go forward.

I want to mention, in the deep shelf we also have, we still are intending – and Steve, you asked last time, to step out on Harvest, probably in the second quarter sometime, because we still think there is some running room which would change our attitude about our production going forward.

So I haven’t given up, but I’m not depending on it.

I would only add one thing, that I mean – remember on the deep shelf we will be spending some money in the deep shelf, and these still are the kinds of prospects that you can put on very, very quickly if they are successful.

They really, they are almost all close to infrastructure, so I mean, the answer is, that’s what as Charles described it, that’s what’s in the forecasts.

I think we will be behind that forecast just because of timing, but we still have a substantial amount of money that’s budgeted for the deep shelf.

Okay, and with the high-end inherent production declines, any further comments on unit cost trends?

We expect 2004 to be just as we said, lower than 2003, and as Robert says, most of the things as we analyzed it, they were about a one quarter timing phenomenon, and that’s what our budget is and we expect people to meet their budget, so I think the risk is, as you point out, if the volumes somehow decline quicker then it will be very difficult to watch those unit costs, and we will have to adjust that.

But we are not planning for that at this moment.

You know, Steve, I want to add that we are spending, in round numbers, about $80m in capital on the – not on exploration in the shelf, but on development capital, moving PUDs over to proven developed and keeping our production up.

So we are investing in the steep decline, we are just trying to do it in a more capital-efficient way.

And we have some opportunities.

We start off the year there above 60,000, we are about I think 62,000 bpd coming into the year in the Gulf of Mexico.

So you know, we are starting in a good place, but you know, later in the year I’d like to add a deep shelf success somewhere to keep the production flowing.

But you know, the Gulf shelf now represents less than 15 percent of our total production in the world, and I think that we recognized that was going to happen in a success case or in any other case, and you know, we will invest and continue to try to invest at a level that makes sense, and there may be some declines.

Great.

Thanks for all the detail, guys.

Thank you.

Our next question comes from Fred Leuffer of Bear Stearns.

Hi, guys, how are you doing?

Good, Fred.

Charles, just three questions.

The first, on West Seno when will you complete phase 2, and how long can it hold peak at 60,000 a day?

Fred, I’m going to do this from memory, and that might not be quite as good.

Phase 2 is scheduled to come online in – help me guys – late ’05.

Yes, I don’t remember which quarter but it’s late ’05, and we are working on phase 2, as you can imagine, right now.

The peak – and this is from memory, so I can always deny it – but the peak we have is about six years, between phase 1 and phase 2.

We still think that’s very, very viable.

Secondly, can you talk a little bit about spot gas sales around Bontang, I think they’ve been picking up a little bit.

Maybe you can quantify what you are doing there and tell us what you see as opportunities.

Well I think what we’re really trying to do in Bontang now is get the production capacity to make sure that we can fulfill any contract needs first, because Bontang hasn’t been producing enough to fulfill all of the contract requirements that are there.

I think people are anticipating spot sales into the future, but there really haven’t been a lot up to this point.

Unocal, a lot of our investment over the next year-and-a-half, two years, will be both Gehem to fulfill our contract requirements, but also to have a little bit of extra capacity to ensure that the plant will remain full.

There certainly are spot sales opportunities, but to Terry’s point, right now we are focusing on fulfilling the existing contract.

And just lastly, Terry, have all the asset sale transactions closed, or do you still expect to receive additional proceeds?

There’s one that’s out there that we’ve already announced, which is we sold one of our geothermal exploration concessions to [Perdamina] and the proceeds will be roughly $60m.

The documents have all been signed, we will anticipate closure sometime in the next few months, but that timing is not certain yet.

There’s some minor things out there, but it is pretty small and then there may, actually there’s a few other things that we may think of later on, but we are probably not ready to talk about those.

Okay, but it sounds like the debt pay down objective, which I see has been met, is now pretty much behind us?

Yes.

And no intention to extend debt repayment targets?

We are satisfied with our balance sheet at this time.

Terrific.

Thank you.

Thank you.

Our next question comes from Don Textor of Dorset Asset Management.

Good afternoon, everybody.

Hi, Don.

Charles, you mentioned a few weeks ago about potentially getting more than spot sales out of East Kalimantan in terms of trying to get maybe more formalized contracts.

Is there anything more on that?

No, Don, Terry may – he is following more closely, but the answer is no.

Things are going to move a little bit slower there.

What we are doing is just what Terry said, that we recognize that there will be other opportunities beyond fulfilling existing contracts.

As some of the old contracts step down, as spot sales occur, et cetera, and for substitution of our own, so we are preparing to submit a plan of development and get it approved that would allow us to go ahead and sell into that market, and that is really what we are doing right now.

Terry, you want to add anything?

No, and that will be the discussion.

I think it’s in the best interests of the country and everyone there to ensure that the plant stays full, and we have a lot of potential developments and we will be prepared to go forward with those under the right circumstances.

I think the way the market is lined up so far that there definitely would have been and there will continue to be opportunities to sell that gas if it is developed.

Could you give us any guidance as to what sort of quantities that you might be looking at?

We’re not prepared to do that right at this time.

I think the shortfalls over the last 12 months have been several hundred million cubic feet a day.

That’s the best case, Don, that’s all we can say.

Thanks very much.

Sure.

Thank you.

Our next question comes from John Herrlin of Merrill Lynch.

Good afternoon.

A couple of quick ones.

Charles, with the deep shelf, can you give us any sense on a post-mortem basis of what the problems were in terms of recognizing the traps?

You know, clearly you are disappointed in the results, but can you give us an idea of why things didn’t work?

Yes, John, and this is from a CEO’s perspective, not from a geologist’s perspective.

I think the thing we learned most is first of all, there was better reservoir quality, a lot of times, than I had expected.

There were very good structures and good closures and traps, but I think there was a lot of questions about the integrity of the trap seal for the size of accumulations we were looking at.

And we found gas in most of our deep shelf walls.

But how much column can they contain, given that pressure regime, I think is still an open question.

So trap geometry and field integrity I would say are two of the issues our guys are most concerned about, that’s about all I can say.

That’s great.

One other one, Canada.

Many of your peers are bottling back a little bit given a lower U.S. dollar.

It’s kind of a steady-state operation for you from a volume metric basis, but your DD&A is creeping up.

Are you going to continue, are you spending, or are you going to back off a little?

Right now our plans for ’04, John, are pretty much comparable to ’03 in terms of Canadian investment.

Again, Terry said it earlier, you know we’ve got – fair enough, the DD&A has been higher on the Canadian operation, but we have pretty good planning and development costs there, I think they are very competitive with the rest of the Canadian sector.

And frankly, you know, at today’s prices we are making a fair amount of cash flow out of that business unit, so unless prices take a turn on us we probably will invest at comparable levels.

Great, that’s it for me.

Thank you.

Sure.

Thank you.

Our next question comes from Phil Pace of Credit Suisse First Boston.

Hi, Charles.

Could you comment on capital spend in Azerbaijan in 2003 and the outlook for ’04, and just give us an update on the volume growth in that project?

Phil, while Robert looks for the real numbers I’ll tell you, my round number for Azerbaijan I think is about $300m this year.

Help me out Robert, but I think that’s pretty close for ’04.

$295m.

See?

There we go, confirmation.

You know, mind Phil that the BTC, you know we are also in the pipeline, is being project-financed and that’s not included in that number, just our bottom finance piece is included in there, so it’s mostly the offshore development piece, which by the way, the offshore derry field is about 80 percent, 85 percent completed.

They are moving along very, very well on that part.

The pipeline is doing well, so despite what you may read in the press, BP are pretty adamant that they still intend to be producing oil early in ’05 from that next phase.

Now it will take a while to pack the line and get the oil to the tanker, probably four or five months, but the project is remarkably on schedule given all the difficulties.

Of course, the financing closed yesterday or the day before, and that was another big milestone, both for just getting the financing and also for having a lot of partners and multi-laterals involved.

You know, Phil, I don’t have ’05 in front of us, perhaps we can come back to you.

Obviously it will tail off somewhat, I don’t know how much.

I just don’t remember the numbers.

The numbers I saw last summer called for about 250 a year until about 2006 and then it starts dropping off, because we’d be going into phase 3 pretty soon as well.

And the volume profile still looks for something pushing a million bpd over the next five years?

Yes, that hasn’t changed from my knowledge.

Thanks, guys.

Thanks, Phil.

Thanks, Phil.

Thank you.

Our next question comes from Fidel Guy of Oppenheimer & Co.

Good afternoon.

A couple questions on your balance sheet, free cash flow, financial flexibility.

What would you say your priority is going forward as to what [inaudible] free cash flow?

Well, our first priority is to get these developments on stream, and we have a lot of them for the next two years, so we don’t forecast a lot of free cash flow in 2004, in almost any circumstance.

It could happen if commodity prices stayed at very high levels in 2005, when AIOC starts kicking in.

I mean, all I have said so far and all we have ever publicly said is that we are content with our debt levels, so I don’t think that we would be reducing our debt, and then of course there are a lot of options to use that cash other than that, and we’ve never commented beyond that.

Okay, now the flip side of the coin, if prices collapse, would you be flexible enough to cut your capital spending, or are you going to borrow more, or do what?

Yes, we would do both of those.

Whatever it would take to keep those projects on stream, because as you know, most of these are either oil or oil-denominated foreign projects that look very good under pretty low oil prices, so –

So of your $219b forecast projected capital spending next year, what leeway do you have in this?

I don’t know the answer to that specifically, we haven’t looked at it, but I know in other years that I have looked at it you should assume that once you enter into the year that there is probably only somewhere around 20 percent to 30 percent of that that is flexible after the first quarter.

If I may, which area would you say that it is cast in concrete and you really cannot cut –

That’s going to be the major projects.

If you look at page 6 –

The $950m.

Yes.

So $950m is the bare minimum.

That’s – yes, and then there will be commitments that have actually been entered into the other E&P and exploration, but if you said, what is our priority, it’s always going to be the major projects.

Okay, thanks.

You’re welcome.

Jason, this is Robert Wright.

I think we’re going to call an end to the questions now.

I want to thank everyone for participating in the call.

We appreciate your questions, and if you have any further questions that you didn’t get answered, please give myself or Lee Alstrum or Nancy Marachani a call, you have our numbers.

Thank you very much, and good bye.

Thank you for attending today’s Unocal fourth quarter conference call.

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