Transocean Ltd (RIG) 2003 Q2 法說會逐字稿

Good morning, ladies and gentlemen, and welcome to the second-quarter 2003 results conference call. At this time, all participants are in a listen-only mode. Following today's presentation, instructions will be given for the Q&A session. (CALLER INSTRUCTIONS). As a reminder, this conference is being recorded today, Tuesday, July 29, 2003. I would now like to turn the conference over to the Vice President of Investor Relations and Communications, Mr. Jeffrey Chastain.

Good morning, and welcome to the review of second-quarter 2003 results at Transocean. A press release covering the second quarter financial results is posted on the Company's website, located at deepwater.com. The release includes an income statement, balance sheet, cash flow statement, selected operating statistics and non-GAAP reconciliation schedules. Also issued this morning and available on the Company's web site is the monthly fleet update covering the current contract status of the Transocean Mobile Offshore Drilling Fleet at July 29. In addition, and beginning with the second quarter of 2003, we are providing a new schedule on the website covering cash operating costs (technical difficulty). Both the fleet update and cash operating cost schedule are posted in the investor relations segment of the website under financial reports.

This morning's call includes participation from the following Transocean senior managers -- Bob Long, President and Chief Executive Officer; Jean Cahuzac, Executive Vice President and Chief Operating Officer; Jan Rask, President and Chief Executive Officer of TODCO, the Company's Gulf of Mexico Shallow and Inland Water business segment; Greg Cauthen, Senior Vice President and Chief Financial Officer; Rob (indiscernible), Vice President of Marketing; and Brenda Masters, Vice President and Controller.

Bob Long will provide opening comments, followed by a Q&A period. Before I turn the call over to Bob, I must remind you that during the course of this conference call, participants may make certain forward-looking statements regarding various matters relating to our business and company that are not historical facts, including future financial performance, operating results, the prospects for the contract drilling business and certain matters related to the initial public offering of our shallow and inland water business segment. As you know, it is inherently difficult to make projections or other forward-looking statements in a cyclical industry, since the risks, assumptions and uncertainties involved in these forward-looking statements include the level of crude oil and natural gas prices, rig demand, and operational and other risks which are described in the Company's most recent Form 10-K, and other filings with the SEC. Should one or more of these risks and uncertainties materialize or underlying assumptions prove incorrect, actual results may vary materially from those indicated.

Also, please note that we will use various numerical measures in the call today which are or may be considered non-GAAP financial measures under Regulation G. You may find the required supplemental financial disclosure for these measures, including the most directly comparable GAAP measure and an associated reconciliation, on our website, at deepwater.com, under non-GAAP. And these are included in the press release for your convenience. That concludes the preliminary details of this call. Bob Long will continue with opening remarks.

Good morning, everyone. As you know from our press release and our announcement a few weeks ago, we had a very difficult quarter. We reported a 14 cent loss on revenues just under $604 million. Adjusting for some asset impairments, early retirement of debt and resolution of a tax liability, we lost $19.7 million, or six cents a share. Because of the losses, our effective tax rate for the year looks like it will come in at 38 percent, significantly higher than what we had previously estimated. I am going to comment on some of the factors that led to the disappointing results this quarter and then ask Greg to give you some information on our tax rate and what the drivers are there; after that, and before I open it up for questions, I will comment on our contract status and market opportunities in each of our six regions.

First, in looking at the results for the quarter, revenues were down about $12 million from Q1, despite having almost 300 more active rig days in Q2 versus Q1. Partly as a result of the higher activity, our costs were higher despite the lower revenue. The strike in Nigeria and the incident with the Enterprise riser cost us about $16 million in revenue, while causing almost $7 million of increased cost. In Brazil, we had the P1 lower spec deepwater drillship down for most of the quarter, repairing damaged cause by an electrical fire. This reduced revenue over $6 million from Q1 to Q2, and increased cost by about $2 million as we made the repairs. Also, in the Gulf of Mexico, we experienced over 90 days of idle time between contracts in the Cajun Express and Richardson combined. These are two of our deepwater rigs, and the revenue loss from Q1 to Q2 as a result of this idle time was about $11 million, while operating costs were reduced only about $1 million, due to requirement to keep the rigs ready to go to the next job.

We also experienced some problems at TODCO, our Shallow and Inland Water Gulf of Mexico business unit. We had a blowout on one of the barge rigs, rig 62, which cost us over $7 million. I think it's worthwhile at this point to note that as a result of having negotiated higher insurance deductibles in order to keep our insurance premiums down at a reasonable level, casualty losses in the quarter resulted in about an $8 million increase in cost over Q1, and that introduces a volatility factor in quarter-to-quarter earnings potentially going forward that we did not use to have when our deductible was down at $1 million.

Other factors which affected our cost comparison with Q1 were the impact of deferrals and amortization, which added a million or 2 dollars higher in Q2 than Q1, and consolidation of the Frontier, which we purchased from Conoco, also added $7 million in the quarter-to-quarter comparison. As (indiscernible) the foregoing, our costs came in at $426 million for the quarter, 16 million above the range of 400-410 that we had guided to.

Looking forward, I expect costs for Q3 to be back in the 400-410 range. We are still experiencing some additional costs in Nigeria as we continue to negotiate with the unions, and I expect that we will incur some additional costs related to riser inspections and replacement of some parts as we take a careful look at all of the risers we have out there in the fleet. We will also have another 2 or $3 million of additional costs from the Frontier due to consolidating for the full quarter in Q3.

Before I switch to commenting on the markets and our contract status in each region, I am going to ask Greg to give you a few comments on our effective tax rate.

As everyone's noticed, our effective tax rate in the second quarter was much higher than we had originally expected for the year. As a Cayman company, although there are a lot of tax benefits to being offshore, it does introduce a lot of volatility into our tax rate, and this volatility is especially pronounced in periods of low earnings. For example, at the beginning of the year, when the Street consensus was an annual EPS of $1.24 for 2003, we were estimating our effective tax rate would be approximately 15 percent. Now, with the Street consensus down around 36 cents for the full year 2003, we expect our annual normalized effective tax rate to be around 38 percent. There has really been no change in our tax situation, it is simply an effect of where our earnings are. In the future, as our earnings go back up, you will see our effective tax rate go back down. So earnings well over $1 will start approaching the 15 percent effective tax rate that we had last year and that we earlier expected this year.

To understand our effective tax rate in the quarter, you really have to understand the accounting principles on how we have to account for income taxes in quarterly periods. We are required each quarter to estimate our effective tax rate for the full year, based upon earnings before unusual items like asset impairments and debt retirements losses. So you actually have to exclude those items, project your earnings and then calculate your effective tax rate. Using that method, that is where we get our 38 percent. For the quarter, you have to catch up that effective tax rate. Since we use the 20 percent effective tax rate in the first quarter, we actually have to do a catch-up adjustment. So in the quarter, we have a 38 percent effective tax rate on our pre-tax earnings before unusual items, we have the catch-up adjustment of about $10 million, and then we have the tax benefit on the unusual items of about $28 million. So all of those combined produced the $20 million tax benefit you see in the quarter, 32 percent effective tax rate, but again, the normalized effective tax rate in the quarter and going forward is our 38 percent.

Now, I will try and give you a quick walk-through each one of our regions and tell you about the contract status. I will start with North America. Leaving the Richardson aside, which is one of our deepwater rigs currently getting ready to mobilize for a term contract in west Africa, we have three rigs coming off contract during the year. Two are cold stacked and likely to stay stacked for the rest of the year, and 8 rigs contracted into next year or beyond.

Looking at the rigs that are coming off contract, first, the Falcon 100, which is a midwater floater. It's currently operating (indiscernible) through August at a rate in the low 40s. We succeeded for quite a while in keeping that rig busy on the well to well (indiscernible) program to program basis, and currently expect to be able to continue to do so for the rest of the year. The Cajun Express is a fifth-generation (technical difficulty) rig working for BHP (ph) until September. We are discussing opportunities with several different operators for follow-on work. The current rate is low, around 90,000 a day, but we do have an opportunity to increase that rate through (indiscernible). Our follow-on opportunities tend to be in deeper water and at much more attractive rates. While we experienced some idle time in the second quarter on this rig, right now we are pretty optimistic that we are going to keep that rig working continuously for the rest of the year.

The other rig that is coming available is the Marianas (ph ), which is a deepwater rig that has been working on a long-term contract with Shell. It should finish its contract with Shell in August. We have got some follow-on work with Kerr McGee after Shell, and are discussing additional opportunities with several operators for the remainder of the year. We also see several term opportunities for the rig commencing early next year. Rates are going to be, however, lower than the current Shell contract rate.

We shift now to the Brazil market. We have 2 rigs in this market that may come off contract this year. First is (indiscernible) 1, which is down most of last quarter, as I mentioned. That may end its contract in the next few months. Petrobras (ph) has stated it intent to eliminate five of their lower spec deepwater rigs and shift to higher spec rigs in the future. The P1 may be one of those rigs that is dropped. We are discussing contract terms with Petrobras now and may keep the rig working until the end of the year, but it's future in Brazil is very uncertain at this point.

(indiscernible) is a third generation semi-submersible -- may have one more well to drill in Brazil and then will probably be released. At the present time, we have very few opportunities for the rig, and are considering a way to (indiscernible) the rig to stack it. On the positive side, the Frontier, which is a fifth-generation ultra-deep rig, is contracted through the end of the year, and we are optimistic about the prospects for continued work in Brazil at rates comparable to or better than its current rate. We are discussing a term extension with Petrobras and have another customer who would like to have the rig for a shorter program at rates substantially above the current rate. There is some risk, however, that we might have some idle time between contracts, while we are hopeful that we can keep it working continuously.

We also have the Seven Seas, which is a deepwater drillship idle in Brazil. It has been idle for some time now in the shipyard. We bid that rig into ONGC in India on a three-year term contract, and we are awaiting word now on whether or not we will be awarded that contract. At the present time, the award has not been made, but we are hopeful that we are able to win that contract and lock the Seven Seas up for three years.

Switching now to Africa, I will comment first on our jackup business. We have six jackups in west Africa, three of them are contracted essentially through the end of the year. One is preparing to mobilize to India for a three-year term contract, one is off contract and another is coming down probably in early fourth quarter. On the one that is off contract and the one that is coming down, we are having discussions with a number of operators, and are pretty optimistic that we will have both of those rigs back working in the fourth quarter of this year. In the midwater floater area, we have got three rigs in west Africa, the 700, 701 (indiscernible). They are all working, and while not firmly contracted through the year, we do expect to be able to keep all three of those rigs working for the current operators through the end of the year and into next year. The Sovereign Explorer is a 5000 foot rig that is idle in West Africa. That is stacked off the Ivory Coast. We will probably move that to Los Palmas and stack it for a longer-term. We do continue to see very positive results, though, in the deepwater market in West Africa. We have the (indiscernible), which we've recently moved over there for a term contract from the (indiscernible). We are in the process of getting ready to move the Richardson there for another term contract. And the Energy and Discovery, both ultra deepwater rigs, are contracted through the end of the year, and we have got a lot of prospect for those rigs going forward. In fact, we have identified over 30 exploratory projects and at least 10 long-term development projects in West Africa that we expect to start between now and the end of 2004. There is some risk that some of the development projects might get delayed, but there is still an awful lot of deepwater work that we see coming in West Africa.

Switching to the North Sea, this is primarily a midwater market, and the midwater market continues to be relatively poor. We do see continuing and accelerating interest in the independents, which bodes well, I think, for activity next summer. But the outlook for the rest of this year is not good. Two rigs in Norway and the Lloyd are all contracted through the year and into next year, but the other 8 active rigs that we have in the region all end their current contracts in the third or fourth quarter of this year.

Looking first at the higher-capability rigs, we are bidding the Base (ph) to work outside the North Sea, and also looking for opportunities for the Leader, whose contract probably ends in November or December. The McLean, Shaw and 712 have pretty good prospects for continued work, and we hope to keep them contracted through the end of the year. The 704 and 706 are likely to be stacked in Q3 and remain so for the rest of the year, while the 711 and 714 are likely to see some idle time in Q4. Let's put all that together, I would say it is likely that you will see at least four of our currently active rigs in the North Sea being idle in the fourth quarter of this year, and there is the possibility it could be more than four.

I shift now to the Middle East and India region. We have 12 jackups in that region, 10 of them are working and 2 our idle. Of the 2 idle ones, one, the Trident 20, is actually on a standby rate up until October or November, I think it is. 8 of the other rigs are contracted well into next year, and 2 of the rigs -- both in Egypt -- are contracted through October, and we have commenced discussions with the operator for extensions of at least one year. Both of those rigs have been in Egypt for, I think, about 15 years on kind of evergreen contracts that get renegotiated ever year. So we are pretty optimistic that those rigs will continue to work.

We also have 2 floaters in the Mediterranean. One is the Itinia (ph), a third-generation rig which is stacked in Malta. We see a few opportunities in the Mediterranean, but at very low rates, and I would say there is a high probability that rig will remain stacked for the rest of the year. The other is the Cunningham, currently working for IEOC (ph) up until next month. We are very close to signing a follow-on contract with another operator, which should keep the rig busy for the rest of the year and maybe into next year.

The last market I will comment on is Asia/Australia. In that market, we have 8 jackups, 5 of which are contracted into or beyond next year and 1 of which has a firm letter of intent, which will keep the rig busy into the middle of next year. The other 2 have been awarded three-year contracts in India, and we'll be commencing to mobilize those to India probably in the next 60 days or so. So the jackup market out there continues to be very good.

The midwater floater market continues to be disappointing. We've got 5 midwater floaters there, 4 of which are currently stacked, one that's working -- the 703 -- and it's contracted up until August, September. We are confident that we will be able to keep that rig working for the rest of the year, and we are also bringing the 601 out for some work that should keep it busy for the rest of the year. However, the other three midwater floaters are likely to remain idle for the remainder of this year. The other rig we have out there is the 534, our deepwater drillship working for Murphy in Malaysia. We have one more well to drill for Murphy and then they have two options. We are also talking to 3 other operators in the Far East and India for follow-on work, so we are pretty optimistic about the outlook for the 534 (technical difficulty) the deepwater in that area.

With that, I will ask Jan to give you a few comments on the shallow water market before we open it up to questions.

I am going to briefly comment on the two large segments in TODCO -- that is the jackups in the Gulf of Mexico and our inland barges. Starting with the jackups. Demand has stayed between 80-100 units in the last 12 months in the US Gulf of Mexico. That is down from 146 at the peak in 2001. In the meantime, supply has come down, from 156 two years ago to 121 rigs. Out of those 121 jackups, 15 are (indiscernible) stacked or not marketed. In other words, we have 106 marketed jackups in the US Gulf of Mexico. 89 of those are working today, which gives us 84 percent utilization. Then, we know that in the next several months, 4-5 more jackups from the Gulf are going to Mexico, two of which are our rigs.

The supply by the fourth quarter should be just above 100 jackups, and ten of these jackups are so-called work over units. Currently, we are marketing 15 out of 25 offshore rigs, and we are working 14. Our current dayrate is averaging $19,800 per day, and the leading-edge rate are now 22-$24,000 per day. We have 200 (indiscernible) cantilevered units going to Mexico in the fourth quarter to work for Pemex for two and three years, respectively. The day rates are approximately $40,000 per day on those 2 rigs.

On the inland barge segment, we still see a very poor market. We have 48 drilling barges in that barge segment, and demand has been between 50 and 60 percent most of the time in the last year. We currently are marketing 14 out of our 29 barges, and 14 are working. So all of the marketed units are working currently. The average dayrate is $17,700 per day. We expect to see demand of a couple of units for Pemex later this year, and those could be long-term contracts.

So so far, we have not seen any demand improvement in the TODCO business, shallow water business. We have only seen supply contracting, because of Mexico and the strong international market in general.

Thanks Jan. With that, I think we are ready to open it up for questions.

(CALLER INSTRUCTIONS). Scott Gil with Simons and Company.

Bob, could you care to give us some earnings guidance -- specific earnings guidance, with respect to the third quarter here?

No, I don't. With all of the uncertainty in terms of the timing for rig contracts ending in the North Sea and what might happen to the P1 and the driller, and the contract situations with the other rigs in terms of the ones that have some availability here, there is just too much potential variability to give you any meaningful guidance. I would have to give you a range that was so broad that it would not help you much.

As we look to the deepwater market, I think, Bob, you talked about you are encouraged for prospects for the 534 in the Asia-Pacific area. Could you talk a little bit about your expectations for dayrates for that unit in the back half of the year when it's through with Murphy? And also, presuming that you are successfully awarded a contract for the Seven Seas in India, what type of dayrate expectation are you looking at for that unit?

The 534 rate currently, I think, is 135,000 a day, and I would guess -- our expectations are that the rates would be in that range, more likely to be a little but lower then a little bit higher. So I would say somewhere in the 125-135 range. As far as the Seven Seas goes, I think that our rate expectation there -- it's a little bit difficult to give you a crisp answer because of the nature of the contract and the additional services we have to provide and the contract exposures that we have there -- but I think that on the low end of the range that I just mentioned is where you would probably benchmark the Seven Seas on a comparable basis to where the 534 is.

On deepwater, the Cajun Express -- it's on an incentive-based contract. Can you just kind of update us on where you stand with any type of realization of incentive on the current project?

Jean, do you know the answer to that?

It varies on the well-to-well basis, but we have been able to achieve equivalent rates of 120-$170,000 with the present rate -- the present basic rate.

How long does this contract continue?

(indiscernible) contract -- the contract is short-term, and as Bob mentioned before, we have a couple of prospects in the deeper water there, which should allow us to keep the (indiscernible) the end of the year. Present rates -- base rate is $90,000 a day. We expect to get slightly higher rates from deeper waters in the 120, and a bit higher than that in the ultra deep water.

Aaron (indiscernible) with Credit Suisse First Boston.

The first question is on the tax rate for 2004. The Street consensus is about 94 cents for 2004. If that's correct, what kind of tax rate would you estimate for next year?

Somewhere between the 15 percent tax rate we had last year on much higher earnings, and the 38 percent we are seeing this year. So it's not precise. It depends on our mix of earnings and what's happening to interest expense. It certainly should be closer to the 15 percent than the 38 percent with that kind of Street earnings, but (multiple speakers) to be precise.

So somewhere in the 20 percent range would be a good estimate?

That would be a reasonable estimate.

Secondly, on operating cost -- obviously had some unusual items during the quarter. What's your expectations, perhaps, for the third quarter or the back half of the year?

The guidance I mentioned of 400-410 is kind of where we hope that Q3 will come out, assuming that activity levels stay around where we expect them to be. I haven't really talked much about guidance for Q4, in terms of costs, at this point, but absent some significant change in activity, there shouldn't be a lot of change in the cost range there.

In West Africa, are there any near-term opportunities like the Richardson out there right now?

There are a lot of opportunities coming up in West Africa for (indiscernible) jobs. When you say near-term --

Like in 2003?

There's no development jobs that I can think of in West Africa that we start in 2003, no. There are a number of them; in fact, all 10 of the ones that I mentioned are theoretically going to start some time in 2004, most of them probably in the second half of 2004. But nothing in 2003.

Mike Urban (ph) with Deutsche Banks.

I wanted to follow up on the costs a little bit more. You have obviously given some specific guidance for the near-term. A lot of moving parts in the most recent quarter, and I was wondering if there was -- if in the future, as these things start to iron themselves out, could you get back to the kind of, roughly, 3.75 range you were running at the last, prior three-quarters? Or should we assume something will happen -- be it a higher insurance deductible or costs that creep up somewhere? In other words, was there anything -- was it just kind of unusually smooth sailing during that period, or has there been a cost creep of some sort otherwise?

It's hard to give a crisp answer to that, because I don't think that there's been a cost creep; in fact, if there's a cost movement anywhere, I think it's slightly down, in terms of a systemic move. But the mix of rigs that are operating and startups and shutdowns and major maintenance -- there's a lot of maintenance that happens on the rigs that comes in big chunks. We have a relatively expensive maintenance procedure that you have to do, and is done periodically. And if a number of those fall in a quarter, then you happen to have more costs than otherwise. I think that if anything, we would hope that the fourth quarter cost will be trending back down closer to that range of 3.75 or so -- I think to where we were coming in before -- than staying in the 400-410. But I don't want to give any specific guidance at this point, because I have not looked carefully at exactly what we think the contract mix will be and what not. And it will be a function of which rigs are operating and where they are operating, and what major maintenance that we see scheduled in that period.

With respect to the maintenance, you started to break out those costs a little more clearly, which is great, and we thank you for that. What are your plans for shipyard projects and/or maintenance costs over the next quarter or two?

jean, do you have specific lists? I know (indiscernible) we're going to have (indiscernible) barge out in the Far East, which is operating in a nice contract. It's scheduled to go in for 30 days special survey. I think that's late third quarter.

We have an ongoing shipyard with the Trident 17. We have a 3 week shipyard on the (indiscernible), which has been awarded a contract with ONGC. So we have a 3 week shipyard prior to start the ONGC contract. We have another shipyard, another jackup, the Tappmeyer. And the last possible shipyard that we have is the Seven Seas, but that will be subject to the contract award by ONGC. We have some (indiscernible) on the expedition in Brazil, which also require it to shut down the rig for 3, 4 weeks in sheltered water. That's the main projects through the end of the year.

Kind of in aggregate, do you have a sense for what, roughly, that line item might be -- shipyard cost or project cost?

It's a bit difficult to estimate. One of the major components of the shipyard cost is the personnel cost. And depending upon the exact timing of the release of the rig and the startup of the contract, that can vary a bit.

Also, you need to be careful. Because of accounting conventions, some of those costs -- and in many cases most of the costs -- are not recognized in the quarter that they are incurred, because they are deferred and amortized along with any mobilization revenue that we get over the term of the contract. So the rigs that Jean mentioned that are preparing for contracts -- if the Seven Seas gets the ONGC contract, the Tappmeyer, the Yost -- a lot of those costs will be referred and amortized over the 3 year contract period. We have included on our website the detailed reconciliation of our cash operating costs by rig type that we (indiscernible) the same type of reconciliation we presented in May up in New York. So you'll find that on our website.

We have seen that. I was just trying to get a sense of directionally or if it's (indiscernible) similar kind of number here, just to even -- if we could even ballpark it?

I don't think so.

Wes Mont (ph) with Fulcrum.

Could we get some dayrate guidance? If you were to keep it working in the second half of 2003, what kind of range you're looking at?

I think the (indiscernible) we anticipate keeping it going at about the same rate it is at now. Right Jean?

(indiscernible) still working probably with an operator in Nigeria, the rate would be similar to what we have seen (indiscernible) depending upon the water depth -- in the 80-120 range, depending upon the water depth.

But no guidance as to which end of that you're looking at? 80-120 is a pretty wide range.

Unfortunately we don't have a (indiscernible) drilling (indiscernible) for the client, and even the water depth can vary.

In terms of the casting, you've got the Triton 20 that is coming up in October. What is the outlook for work and what is the outlook for the dayrate?

We (indiscernible) tender documents from an operator in (indiscernible), which is a 270-day contract with options, and we are presently in negotiation and discussions with this client. And as a consequence, I would not wish to give any guidance on the dayrate, because the negotiation has not been finalized and we have (indiscernible).

You're looking at what, 120, 125 right now, on this current contract?

Yes. That is the dayrate that the rig had when she was operating in Azerbaijan (ph). We are on a standby rate with (indiscernible) if I recall, at $55,000 a day. But our costs have been reduced accordingly.

Could you give us any guidance, Jean, about whether it's likely to be down from the 120, 125?

Again, for the region -- as I mentioned before -- we are in a very (indiscernible) negotiation, and we have 1 of our (indiscernible) coming from Iraq (indiscernible). So I really would not like to disclose any indication of rates at this stage. We expect a decision to be taken in the coming weeks, so we should be able to provide you with more information pretty soon.

In terms of the rigs -- you've got the Cunningham over in Egypt. What's the dayrate outlook for that?

I think the Cunningham is presently working in the mid to high 50s, and the follow-on rate, we think, is going to be in the 60s.

Greg, can I get 2 items (indiscernible) your best guess on a a third-quarter DD&A expense, and interest expense?

Interest expense for the third-quarter is going to be a little under 50 million gross interest expense, and maybe 4 million of interest income. So it will come down from this quarter due to all of the debt retirement in the quarter. Depreciation should be around $130 million a quarter.

So it's going to be up a little bit?

Just up a little bit as we continue -- just from the minor capital. We had $50 million of CapEx in the first half of the year, so just depreciation on that CapEx is driving it up a little bit -- as well as -- I guess the other thing that drives it up is we -- in the third-quarter, we will start -- we will bring the Frontier onto our balance sheet. Under the new accounting pronouncement FIN 46, the Frontier was financed by an operating lease. So even though we bought out Conoco's joint venture in the second quarter, the asset still stays off the balance sheet. In the third-quarter book the asset and the debt will come onto the balance sheet, and that will increase depreciation, as well.

CapEx for the year -- what is your best guidance?

For the rest of the year, it will be up a little bit versus the first half, maybe 80-$100 million over the second half of the year, a lot driven by some of the contracts that had been awarded, like the Pemex contracts and other contracts that will require some CapEx.

Bob, could I get you to address the share buyback? Your stock is trading at $18.95 right now; it's down pretty sharply in the last 90 days. I know that the focus of Transocean has been to pay down debt, but you have got what appears to be a pretty low stock price compared to its last couple of years. Your thoughts on that?

While it is tempting, we have pretty well committed to not contemplating a share buyback program until we get our debt down into the range that we have targeted. So we have a ways to go before we will start thinking about a share repurchase program.

Jeff Kybertz (ph) with Smith Barney.

The first question is, you took some impairments in the quarter -- is it your current view that that is it, or are there any other possibilities?

Currently, that is it. If we had identified anything else that should be impaired, then we would have taken the impairments. At the present time, I cannot think of anything that we have on our radar screen that could potentially come up to be considered to be impaired. So I think that that is it for the foreseeable future.

I am making the presumption that impairment or not is somewhat a function of market conditions, and I just wanted to get a sense if -- because you are not making particularly bullish comments about any of the market outlooks, where there is anything that is still borderline?

Well that was on the assets side. You have to take a very long-term view in terms of trying to keep determine whether it is an impairment. I think one thing we probably should mention is that we do have the goodwill impairment test that we do every October, and stock price is an indicator there of whether or not there may be an impairment. With our current stock price at 19 or under, you would have to think that there is at least a chance that there would be an additional goodwill impairment on October 1; but there is no guarantee, so we will just have to analyze that at the time.

One thing to make clear on the asset impairments, those are driven not so much by current market conditions, because as Bob indicated you take a very long-term view of that. But it was driven by our decision to retire the assets, the five jackups and the semi in the tinder (ph), from drilling service. So we are not going to use -- bring those rigs out as drilling rigs. So that was an impairment indicator that caused the impairment. So one would expect future market condition changes to lead to impairment, it would have to be a decision to retire a rig. So if we retire a rig in the future you may have an impairment. But we do not have any current plans to do that.

What can you say about your current thoughts regarding the TODCO IPO?

We are continuing to be prepared to do the IPO when we think that the market conditions and valuations are right. I think that we have to refresh our filing though. Greg, what is the status of that?

MR. GREGORY CAUTHEN We will refresh our filing for June numbers sometime in late August or early September, and then we will again be ready to go as market conditions warrant. We have continued to be disappointed with the response from the demand side in the market. As Jean indicated, despite pretty healthy commodity prices here, we still have not seen much of a movement in the demand side. On the supply side, we are seeing some very nice developments, and as Jean indicated, dayrates on the jackup side of the business have started to move up a little bit. The barges still kind of remain flat. We have not seen any improvement, and may even seen a slight degradation in the rates on the barges. So we are going to continue to monitor that market, and when we feel it is right, we will be ready to go.

Given what was said earlier in regard to the shallow water and inland barge market, it does not seem like it would be a crazy conclusion to think that this is something that might not happen until 2004.

I am not going to try to give you a particular timeframe. We were hopeful that we could get it off sooner rather than later, but I do not think that you should be surprised if it does not happen until 2004.

If that is the case, you have mentioned earlier about the debt reduction targets -- what are your thoughts there, in terms of being able to reach those targets?

I do not think we ever gave any specific timeframe to meet the targets, but we do continue to generate a fair amount of cash here; so we will continue to pay down debt with or without the TODCO IPO. Obviously, if we are successful in getting the IPO done, we will be able to pay down the debt a little bit sooner. But even then, it depends on the size of the IPO, which is still up in the air, so I do not think that the TODCO IPO has a big impact on our debt pay down in the near term.

I just wanted to come back on the comment considering the Cajun Express. I thought I heard you say that the realization was in the 120-$130,000 a day, but the base dayrate was 90,000? Did I hear that correctly?

That's for the existing operation. We are expecting to go (indiscernible) higher in deeper water, and (indiscernible) deep water it could reach 115. So it is going to be something between the 120 and 150, depending upon the water there.

Terry Darling (ph) with Goldman Sachs.

Bob, on your thought process with TODCO here. I am wondering if the delay and uncertainty on timing here increases your interest in another alternative for monetizing the asset, and whether the time slip slide here results in you also taking your price expectations down at all?

I don't want to comments much on our price expectations, so I would say that has not changed much over the last year or so. In terms of other alternatives, I guess we have not really changed our position there, either. We have always stated that we would consider any alternative that would enhance shareholder value. So if somebody had another alternative that we thought would create a lot more value than the IPO, then we would certainly look at it. So far, we have not seen any alternatives that come close to what we expect for values from the IPO.

First, and maybe this is a question for Greg -- the field operating expense as described in the press release for the TODCO business, assuming that that includes depreciation? Is that correct?

That does not include depreciation.

Question for Jan. Jan, can you comment on where the bid activity for the jackup business has been here over the last several weeks or so for us? And then also I think there was an indication that the barge rates had declined of late, but it looked like the demand overall was either static or just off a little bit. Is there something unusual that is driving that rate softness in the barge market there?

No. It would start with the jackup side. We have lately had between 15 and the low 20s, in terms of that bid activity per month. So it's maybe about 1 bid per day, and that has continued in June and July. So not any trend really, one way or the other. On the inland barge activity level when it comes to bids, it is slightly down. It used to be in April/May 10-15 bids per month; it is down now to 8, or thereabouts. And why? I really don't know why. We have seen a development where we have much more development really, and very little exploratory drilling. And I think in order to see utilization come up, we need to see exploratory drilling. Out of the 14 barges we have working right now, we have one of working on a very deep well, 22,000 feet; we have three more working (indiscernible) just about 15,000 feet; and the balance are very shallow water wells. About a year ago, we had over 10 rigs working beyond 15,000 feet. So there is a slight change right there.

Is that a lack of drilling success?

I don't think you can say that, because when we talk to our customers, they still have plans to drill deeper. And we have talked to some of the guys that are active drilling deeper wells, and they have plans to drill three or four wells the balance of this year, quite deep, and into next year as well.

On the jackup market dayrate outlook later this year -- as you described, there is more supply leaving the market. Do you believe that that will be enough to push rates higher, or do you think we need to see a demand pickup as well?

If demand stays where it's been lately, around 90 units, and we're down to 100 or -- between 100-102, we would have utilization over and above 85 percent, where I think that normally you have the cut off. Above 85 percent marketed utilization, you start to see dayrate pressure. So I expect to see dayrates improve slightly, even without demand improvement.

Greg, on the tax rate. In past, companies with the tax situation you have had have been able to suggest that people -- a tax rate based on a percentage of revenues, at least for the international business. For those of us who are modeling your company on a rig by rig basis, obviously, we (indiscernible) to discern what is international, what's domestic. Do you have the ability to help us on that front here, so that we can make some of our own interpretations on where the tax rate goes as the earnings move around on us?

It's very complicated. Our structure is very complicated because of our mergers over the years. So although some rigs are working internationally, they are not necessarily owned internationally. They may be owned by a US company because of mergers. So frankly, we would have to get into so much detail that -- we are not willing to get into that detail. But in general, the driver, what's driven our rate up is the revenue-based taxes, (indiscernible) profit taxes or withholding taxes or low tax jurisdictions. So our marginal rate is very low because of those revenue-based taxes. So when profits fall, that dries our rate up. In addition, one thing you can model is the interest expense we have, we get no tax benefit for. So over the years, as we pay off debt and as our interest expense declines, that will also drive our rate back down. So you can make some general assumptions on revenues, revenue-based taxes, but it's very difficult for us to model it, and we are just not willing to share that detail.

Mark (indiscernible), Merrill Lynch.

Bob, you made a comment about the Marianas finishing up with Shell on its long-term contract, and you indicated they had several term opportunities going forward. Would those be in the Gulf or elsewhere?

That's in the Gulf of Mexico next year.

In 2004?

Right.

A little bit more clarification on the West Africa opportunities. You indicated as many as 30 exploratory wells and the 10 long-term developments. How many of those wells, if they were all drilled next year, could be met by rigs that are currently in the region, versus other rigs that would have to be brought in from elsewhere; i.e., like the Richardson? In other words, how much incremental rig demand could you see next year?

I'm not sure I can give you a crisp answer to that. First, to clarify -- the 30 exploratory programs, some of them are more than one well. So they probably average 60-120 days for those programs. I think that -- my sense is, though I won't swear that this is a fact, is that there are going to be a requirement for more DP rigs in West Africa. A number of these projects, we think, are going to require, or the operator is going to prefer, DP rigs. So I would not be surprised that you might see a requirement to move a couple more DP rigs into West Africa over the next 18 months or so. But I really don't have a precise breakdown of which rigs we think are good candidates for each one of these programs, so that we have a precise estimate of how many more rigs we would need to commit.

The requirement for DP is the same issue as in Brazil, where they are working around existing fields and they don't want to interfere with the infrastructure?

I'm not sure that that is the driver in West Africa. Jean, you want to comment on that?

It's not so much the existing infrastructure, but it is the duration of the well. West Africa wells are usually deepwater, but (indiscernible) shallow well, not very long wells moving from (indiscernible) location; a lot of moves in terms of locations. And a combination of logistic costs in West Africa. Some of these -- the supply boat cost can be very high in West Africa compared with the Gulf of Mexico or the top of the world. (indiscernible) an economic reason, as well as technical reason -- it is not the existing infrastructure. We haven't seen yet the deep development in West Africa that you have seen in Brazil. That will come, and will reinforce even more the need of the DP rig in the long-term future.

Pierre Connor with Hibernia Southcoast Capital.

Just a simple follow-up. Jan, on the rigs going to Pemex, could you expand upon the start dates, any expected shipyard time and any incremental cost potentially with upgrading?

Yes. When it comes to the 2 jackups, we have one that starts working under a 2 year contract in end of October. It will go in the shipyard early in September, and we expect to spend approximately $6 million on that rig, upgrading it for the Pemex contract. Then, the other rig starts early in December. We have a similar upgrade on that one, but we have obviously much more time. And the contracts are two and three years, respectively. Dayrates are just shy of 40,000 on the 2 year contracts and a little over 42,000 on the 3 year contract. The upgrade is amortized in the dayrates, and operating expenses are expected to be $20,000 per day, including local G&A.

Jan, I'm sorry -- did you say that the rate on the 3 year contract was slightly above 40 or 42?

42.

The amount of time in the shipyard for the contract for the rig (indiscernible) in December would be approximately the same amount of time. So I guess my question, obviously, is -- it continues to work up until such time as you need to take it to the shipyard?

Yes. Both of these rigs are working under contract now, and we have worked out substitution rights should our customers want to continue to hold on to the rigs. So I expect that we will take them out of service in -- early in September and early in October, respectively.

So expand upon that a little bit, Jan, then -- if you would potentially replace with existing equipment, would there be costs associated with getting other equipment ready? As you say -- these are active rigs.

You mean to replace these two in the US Gulf of Mexico and bring our marketed supply back to 15?

Yes.

Yes. We would have expenses for those rigs. I have not look at that recently, but I think that the expense is -- the upgrades would be somewhere between 1 and 2 million.

And whether or not we actually bring out additional rigs to substitute for those will be a function of the market at the time. If we can substitute with an existing active rig, then that is what we do. So we will be evaluating the market, and whether or not we want to spend the money to bring out and go back up to 50 and market the rigs in the Gulf.

My assumption on the market on the current rates, plus the expectation for slight incrementals in rates -- that the rate would be an acceptable to the market. Then it would only be a question of backlog, of expected work. Is that fair?

That's probably right. COMPANY SPEAKER: CAHUZAC: That's probably correct. And I expect that as we see more rigs leave the US Gulf of Mexico, our customers will start to talk about term contracts again, like they started to do in May.

Jan, on the barges -- and since you have written down these 5 rigs on the jackup side, are there some rigs on the barge side that did not -- of the 29 -- that did not work in the last cycle, that are of such cost to put back in service that you don't expect them to work again?

We used to say we have 31 barges, and we have taken one out of service that (indiscernible) impairment, because it was already so low in our books. And then because of the accidents on Rig 62, we're down to 29. And I don't expect any further adjustment of that number.

So the 29 is still a good number. I appreciate the information.

Andrew O'Connor with Strong Capital.

Bob, I wanted to know for the North Sea market, and in light of how you have characterized current conditions there -- do we have any read yet, or is it too soon to have a reader for the period of seasonal softness that we'll be coming into. Do you think it will be typical or more than typical, relative to history?

I'm not sure what -- typical has not been particularly good, and we're facing a situation here where it is not going to be particularly good. As we indicated, we will have at least four of our rigs, we think, see idle time, and it could be more than that. So I think that the seasonal downturn is going to be pretty much like it has always been there. We are encouraged, in terms of the future upturn next spring and summer, because of the significant influx of the independents. And in fact, we are targeting those independents as a real potential opportunity for us, given our size, the number of rigs we have got there and a significant well service group capability that we have in the North Sea. A lot of these independents don't have the infrastructure that the majors have, and being able to provide them more of a full-service contract is a potential advantage. In fact, we already have captured one opportunity, which gives us a lot of flexibility by giving them a full-service type of agreement. We are actually able to have some flexibility on which rig we use and what start date we pick. So those are the types of things that we are going to be trying to target as the independents move in their next year.

David Snow with Energy Equities.

As you look at the US and the world picture, do you see -- in your own minds, or in talking to your clients and end-users -- whether the main reason for the malaise is a lack of drillable prospects, or a lack of confidence in the price structure? Or do you have any reasons for this kind of disconnect between prices and activity?

I don't think we have got a very good answer for that, but I will tell you -- when we talk to our customers about that, a lot of them push back pretty hard, in terms of the suggestion that they are not spending very much money; in fact, most of them are spending as much money as they have ever spent. And it is just a question of a different mix. You look at the dollars that they spend for some of these deepwater programs and the deepwater developments -- it takes a lot of dollars, and compared to the number of smaller rigs they could drill with those dollars in the past, there is a difference, in terms of the number of units drilling. But I think, if you look around the world in different areas, the customers are still spending a lot of money, and there is a lot of new money coming in because of the activity of the NOC's. The pickup in activity in India and the pickup of activity in Mexico are real significant enhancements here. So I do not have a very good answer at all for why there isn't more activity in the Gulf of Mexico, which is gas-driven -- the shallow water Gulf of Mexico -- given gas prices. And when Jan goes and talks to his customers, I think we get a mixed reaction. Some say lack of prospectivity, most don't; some say lack of availability of capital, either on their part or their partner's part; so there's a lot of different answers that we get, none of them are particularly convincing or persuasive. So I don't think that we can give you a very crisp answer.

When you took the decision to take some of the units out of service, did that kind of reflect a view that this market was going to stay horizontal in its profile? Or was that not part of the decision to retire units?

I think it was more a function of what we saw as the likelihood of getting up to significantly higher activity than we saw at the last peak. The last peak a couple of years ago, we had 25 jackups and 25 barges working. It's difficult for us to see that the market is going to get so buoyant that we would have more than that number of rigs working at the end in any kind of a near-term way. And the rigs that we retired would take a significant mount of money to (indiscernible). So the market would not only have to get extremely good, but it would have to be good enough to have term contracts, so we would spend a lot of capital to reactivate the rigs. We frankly just don't see the likelihood of the market getting that good near-term, which is why we have decided it would be best to retire the rigs.

(CALLER INSTRUCTIONS). Mr. Chastain, there are no further questions at this time. Please continue.

I don't think that we have anything more. I hope we have answered all your questions, and we thank you for joining us. We will talk to you again next quarter.

Ladies and gentlemen, this concludes the second-quarter 2003 results conference call. If you would like to listen to a replay of today's conference, please dial 303-590-3000, and use passcode 544-298. (CALLER INSTRUCTIONS). You may now disconnect, and thank you for using AT&T Teleconferencing.

(CONFERENCE CALL CONCLUDED)