Transocean Ltd (RIG) 2005 Q2 法說會逐字稿

Good morning, ladies and gentlemen, and welcome to the Transocean second quarter 2005 results conference call. At this time all participants are in a listen-only mode. Following today's presentation, instructions will be given for the question-and-answer session. If if not needs assistance at any time during the conference, please press the star followed by the zero. As a reminder, this conference is being recorded Tuesday, August 2, 2005. I would now like to turn the conference over to Mr. Jeffrey Chastain, Vice President of Investor Relations. Please go ahead, sir.

Thank you, Jeff. Good morning and welcome to the review of Transocean's second quarter 2005 results. A copy of the press release covering second quarter results along with the supporting statements and schedules is posted on the Company's website, which is deepwater.com. You'll also find on the Company's website, the fleet update report covering the current contract status of the Transocean mobile offshore drilling sheet as of August 2, 2005. The report is posted in the investor relations segment of the website under financial reports.

This morning we have participants from the senior management team, Bob Long, President and Chief Executive Officer; Jean Cahuzac, Executive Vice President and Chief Operating Officer; Greg Cauthen, Senior Vice President and Chief Financial Officer; Rob Saltiel, Vice President of Marketing and Corporate Planning; and Dave Tonnel, Vice President and Controller. Bob Long will provide opening comments, Greg Cauthen will discuss some of the financial detail pertaining to the quarter, and Rob Saltiel will provide comments on market outlook. We will then take your questions.

But before I turn the call over to Bob, I'll remind you once again 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 and the prospects for the contract drilling business. 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 others risks, which are described in the Company's most recent form 10-K and other filings with the U.S. Securities and Exchange Commission. 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 would find the required supplemental financial disclosure for these measures, including the most directly comparable GAAP measure and an associated reconciliation on our website for your convenience. That concludes today's comments. I'll now turn the call over to Bob Long.

Thanks, Jeff. And good morning, everyone. We'll have the same format for the call as we had for the last several calls. I am going to give some general overall comments in what we see going on in the business, and then I'll ask Greg to comment on the numbers and Rob will give a more detailed overview of what's going on in the market before we open it up for questions.

Obviously, business continues to be very good across all market segments. Earnings improved from $0.24 cents in the first quarter to $0.38 in the second quarter after adjusting for the sale of the Jupiter Land Rig 34 and our final stake in TODCO. Demand for all types of rigs in most geographic markets is strong. In fact in the Gulf of Mexico, there's more demand for High-Specification Floaters than there are rigs available. You saw from our press release that we've developed a very significant revenue backlog and over 70 percent of that backlog relates to our 32 High-Specification floaters. Most of the demand for those these High-Spec floaters has been for one to two year periods beginning in 2005 or 2006. We've been working hard to interest operators in longer term commitments but up until recently, have had little success. In the past couple of months we've seen a sudden interest on the part of many operators in contracts which start several years out and extend past 2010. Much of this interest is generated by concern that rigs will not be available for programs starting in two years or so. We have a number of rigs which we think can be upgraded within that period to meet the potential requirements and are in discussions regarding possible term contracts to support such upgrades. If we're successful in developing one or more of this opportunities it will represent a nice increment to our backlog past 2008.

While I've emphasized the nice backlog we have, I don't think want you to think we don't have any remaining upside in the near term. Looking at our 32 High-Specification floaters, 13 will be available for new contracts or extensions in 2006 and 10 in 2007 including all three Enterprise class rigs. If the market remains as strong as it currently is, we should see nice rate increases on most if not all of these rigs. I would caution you, though, on that on one of the Enterprise class rigs there is an option which caps the upside on the day rate at 15 percent increment.

Another interesting point I'd like to call to your attention, which illustrates how good the market is for High-Specification floaters, is the number of rigs which we have with dayrates over $200,000. I know $200,000 a day sounds like a low rate today, but that was the high end of the rates for Deepwater new bills that came out five years ago. Today we have only five rigs operating with dayrates over $200,000 but January we should have eight rigs over 200,000 and by this time next year, 20 assuming the letters of intent we have evolve into firm contracts and four of those 20 will be over $300,000 a day.

Our other floater business has continued to improve, and we've seen now a commitment for a $200,000 day rate on one of these rigs. We have a lot of availability on these rigs in 2006 with only 48 percent of our fleet days committed. A significant part of the available time was represented by the seven stack units that we have including four in the North Sea and we're seeing more and more interest expressed with operators on some of these rigs. We're evaluating the possibility of reactivating one or more unit to meet specific contract opportunities, but again, I caution you, if we're successful here, it's unlikely any would be reactivated in time to have a significant positive impact on our 2005 results. Our Jackup business continues to be very good and demand seems to be increasing in a number of areas.

Despite all the good news on the marketing front, we do have a number of challenges facing us and facing the industry. The first is people. Our people really are our most important asset. It doesn't matter how good the iron is if, you don't have good people to operate it, and there's tremendous pressure on us regarding people. With additional capacity being added in the form of upgrades and new bills, together there's some major efforts to increase staff by some of our customers and our suppliers, we have a real issue regarding recruiting and retention. We're committed to keeping our good people and will be competitive with respect to our compensation packages. This will challenge our continuing efforts to control costs. We're going to see increases in our cost structure due to wage increases and due to the higher cost of equipment and supplies. Greg will comment more on our expectations for costs in a minute.

Finally, I know the question on everybody's mind is what are you going to with all the cash? As I indicated earlier, I hope we will have some reinvestment opportunities for some of it with upgrades. However, it does appear that we will generate significantly more cash than we'll need for reinvestment. With a debt now comfortably in the 1 to $2 billion range that we've been targeting for sometime, we're starting to consider alternatives for returning cash to shareholders. With that, Greg, why don't you give some details on the numbers and then turn it over to Rob for some marketing comments?

Thanks, Bob. And good morning to everyone. In the second quarter of 2005, we had adjusted net income of 127.7 million or $0.38 per share. This excludes the impact of $165 million gain from the sale of our remaining interest in TODCO and a $9.1 million after-tax gain from the sale of of the Transocean Jupiter and Land Rig 34. Then prudent from the adjusted EPS of $0.24 in the first quarter 2005 relating primarily to increases in dayrate and activity partially offset by higher shipyard and maintenance costs. As I noted last quarter, our results this year no longer include TODCO's results and revenue and operating income following the December 2004 deconsolidation of TODCO. With the sale of our remaining interest in TODCO in the second quarter, our equity in earnings in affiliates will decline significantly going forward. For comparison to 2004, you should continue to look to the Transocean drilling segment results.

Although we no longer own an interest in TODCO, we still have a tax sharing agreement with TODCO that requires them to pay us for more than $300 million of tax benefits as they are utilized. These tax benefits relate to net operating losses and similar carry-forwards that TODCO retained as part of their separation from Transocean. The ultimate allocation of tax benefits between us and TODCO will not be finalized until we file our tax return in the third quarter so the final amount will vary from this estimate. We expect to recognize approximately $8.5 million of other income in the third quarter when TODCO files its 2004 tax returns related to this tax sharing agreement. In future years, we will recognize this tax benefit amount as other income in the quarter that TODCO files its federal and state tax returns with the amount based on the cash in lieu of taxes they paid us related to that year's tax benefits utilized. In effect, we are recognizing the tax benefit on a one-year delayed basis due to contingent nature. Now the utilization and the payment by TODCO of the entire amount of tax benefits is not assured, and thus, the timing is impossible to estimate as it is contingent on many factors including the amount of taxable income that TODCO generates each year.

Moving on to operations, let me first discuss our revenue. An increase in dayrates and activity led to a net $97 million increase in revenue. This increase includes the impact of the reactivation of the M.G. Hulme, Amirante, and the Falcon 100 and the return to work following shipyards and our mobilizations of the Rather, the Sedco 712 and the Sedco Express. [INDISCERNIBLE] the higher efficiency across this fleet and improvement in higher integrated revenue and higher revenue from client reimbursables also contributed to the increase. Some of this increase in activity in client reimbursables has a direct offset in increased costs that I will describe shortly. We expect the current level of integrated services activities, which relates primarily to the Sedco 712 and the Seven Seas, to fall next quarter but return to second quarter levels in the fourth quarter with a similar pattern in cost reflecting the relatively small margins related to this activity.

Operating and maintenance costs in the quarter increased by more than $50 million. This includes almost 22 million related to the increases in activity in integrated services, higher personnel costs, and an increase in client reimbursables which offsets some of the increased revenue I mentioned earlier. Approximately $20 million of the increase in costs related to higher shipyard costs on the Rather, the Legend , and the Sedco Express. The remaining cost increases were primarily related to an increase in the number and costs of relatively small maintenance projects across the fleet, including projects that were originally planned in the first quarter but were delayed as well as the cumulative impact of Bender price increases.

Shipyard activity will continue to be the driving factor for keeping third quarter operating and maintenance costs roughly in line with the second quarter. The third quarter will see the start of a shipyard on the Navigator, the reactivation of the Peregrine 1, and continued shipyard cost impact from the Legend with this commencement of work in late July. We expect that we will experience a drop in the amortization and deferred contract preparation mobilization costs as well as a drop in the number of maintenance projects in the last quarter of the year, thus, fourth quarter operating maintenance costs should be somewhat lower than the level seen in the second quarter and expected in the third quarter, although significantly higher than the first quarter due to increased activity levels. However, I would caution you that the predictability of the labor costs, maintenance costs, and the amount and timing of maintenance and shipyard projects is very uncertain, and depends on, among other things, continued pressure on labor and vendor costs, major downtime events, contract preparations, and reactivations during the year. Thus, our cost expectations for the third and fourth quarter could vary as much as 5 percent up or down as should be clear from the rest of the comments this morning and the fleet status report. Readying costs should continue to increase and more than offset these cost trends.

Net debt decreased to approximately 1.3 billion benefiting from cash flow from operations, the proceeds from the sale of our remaining interest in TODCO, and the proceeds from option exercises. Following the third quarter retirement of 76 percent of our 6 5/8 note due 2011, our total debt has declined to 1.6 billion and is now close to the midpoint of our guidance range of $1 to 2 billion. With this latest debt reduction, our interest expense, net of interest income for the remainder of the year, should decline to around $20 million a quarter. Finally, our adjusted effective tax rate for the year increased slightly to approximately 17 percent from almost 16 percent in the first quarter. For the remainder of 2005, we estimate the effective tax rate will continue to be approximately 17 percent. However, even at similar levels of income, our effective tax rate can be volatile both due to discrete items such as changes in estimates, as well as due to changes in the geographic mix of our income. So, our actual tax rate for 2005 is likely to vary from this estimate and to vary from quarter to quarter as well. With that, I'll turn it over to Rob to discuss the market outlook.

Thanks, Greg. And good morning to all of you on the call. I'm happy to report that we continue to see strong and growing demand worldwide for our offshore drilling services, especially in our Floater segments. Dayrates for the Highest-Specification rigs in our industry are now in the $400,000 range while we're seeing mid-water rates reaching the level $200,000 level. Visible demand for 2006, 2007 and beyond continues to grow as new programs and extensions of existing programs materialize. With the level of inquiries we receive across all of our asset classes, we expect that our backlog is likely to increase further from its record dollar level between now and year-end. Consistent with our usual practice, I will now give the market update on each of our asset segments.

Transition to Other Floater segments, which including rigs capable of operating in water depths up to 4500 feet,, continues to benefit from increasing demand and rate levels. We now have 17 of our 24 rigs in this segment working, up one from our last conference call as the Transition Legend has recently commenced work in Falkland. Since our last call, we had 6 contract signings on five North Sea rigs for approximately 5.5 rig years in total. We achieved dayrates ranging from $140,000 on the low end to a new high day rate of $200,000 on the Sedco 714. Seven of our eight rigs operating in the North Sea are now under contract until at least midyear 2006 and four of these are expected to work into 2007. We anticipate that the upward trend in North Sea dayrates will continue in the near term as competition for suitable rigs grows. As Bob indicated with North Sea rig supply being this tight, the possibility exists that we may reactivate one or more of our four idle rigs in the coming months. However, we would require a suitable term contract plus an expectation of continuing strong demand to justify such reactivations.

The remainder of the other Floater regional markets where we operate are also seeing generally increasing activity and dayrates. In Brazil, we have agreed to a four-year deal with Petroleo Brasileiro on the driller that will keep that rig busy there until late 2010. The Sedco 601 in Indonesia has been fixed for nearly a year that will extend into late 2006, and the Falcon 100 has increased its rate to $145,000 in the Gulf of Mexico on a one well fixture for early 2006. And we anticipate further upside on mid-water rates in the Gulf going forward.

Our international Jackup segment continues to perform well with all 25 of our rigs currently busy. Since the last call we've had a few signings, including three option exercises, and we continue to see strong demand for Jackups in the regional markets where we operate as we head toward 2006. One recent bright spot for Transocean, in particular, is the strengthening of rates in the Gulf of Suez, where three of our Lower-Spec Jackups operate. We concluded a seven-month deal on the Mercury that will keep that rig busy into 2006 at a rate of $50,000 a day, which is nearly 50 percent higher than its current date. While the Interocean III inked a one-year deal at $52,000 a day up from it's current rate of $38,000. We are continuing to see a number of inquiries for multi-year Jackup programs with clients, some of which may provide an opportunity to upgrade our recapabilities under full pay back scenarios.

Turning now to the High-Specification segment, which includes our Deepwater and Harsh Environment assets, we continue to be very bullish. We are seeing strong demand chasing a limited supply of rigs through 2006 and into 2007. Industry dayrates have hit progressively new highs, and we expect there may be further room for them to run higher still in the coming months. Currently, we have 30 of our 32 High-Specification rigs working and we have returned the Sedco Express and the M.G. Hulme to work since our last conference call. Peregrine 1 is currently preparing it's reactivation for a three-year contract with Petrobras, which is expected to start in the fourth quarter. While the navigator is undergoing maintenance work prior to starting its contract with Shell.

In the Gulf of Mexico, we signed one very significant deal that illustrates the continued upward rate momentum in this region. The Deepwater Millenium extended its contract term into mid-2007 by blending a six-month fixed rate, 12 months of capped options, and an additional six-month day rate of 350,000 per day into a single rate and contract period. Recall that our previous fixed rate for DP in the Gulf of Mexico was a $270,000 per day for the Spirit in February, which now seems like a long time ago in terms of this upcycle. We understand that one of our competitors has a fixture in excess of $300,000 for a rate that is comparable to the Marianas, and we hope this level will set a floor for similar fourth generation future fixtures. We are seeing a significant amount of interest in new programs and program extensions requiring Deepwater rigs, some of which will not begin into the 2007 timeframe. With the exception of the Nautilus, our Gulf of Mexico Deepwater fleet is sold out throughout 2006, but we will look at relocating rigs to this region if the economics are warranted.

Our South America High-Spec rate backlog is greatly increased with the previously-announced awards by Petrobras for four of our Deepwater rigs. The Navigator, the Sedco 707, the Sedco 710, and the Peregrine I, for a combined total of 15 rig years. These fixtures solidify our role as a key Deepwater contractor to Petrobras and ensure that we maintain a significant presence in Brazil through the end of this decade.

In the North Sea, strong demand for High-Spec rigs in both the U.K. and Norway sectors continues to offer excellent opportunities for future work. The Rather has just agreed to a one-year deal in the Western Setlands area, and we expect that our other rig in this area, the Paul B. Lloyd, will be well-positioned to take advantage of similar work opportunities. On the Norway side, we are looking at possible term extensions on all three of our High-Spec rigs there, the Arctic, the Pioneer, and the Leader to meet the needs of longer term programs in Norway. In West Africa, we recently signed the Deepwater Discovery for development of a Total's Akpo project in Nigeria scheduled to start in mid to late 2006. This fixture is currently the highest in the Transocean fleet with an average rate exceeding 360,000 per day over two years. Additionally, we've agreed to move the Deepwater Expedition from Brazil to work in Egypt and Morocco after it completes its current project with Petrobras later this year. And, finally, we agreed to a minimum eight month program that returned the M.G. Hulme to service in May after it had been idle since late last year.

Going forward, we are seeing numerous exploration and development projects materializing in Nigeria, Angola and Congo that will drive future demand and likely account for a High-Spec Floater market that is tight at least through 2007. Finally, turning to Asia, we have increased our longer term Deepwater presence in India with a recent two-year agreement on the Deepwater Frontier, a 10,000 foot drillship currently working in Brazil. Looking to the future, we see additional term opportunities for High-Spec rigs in India, Malaysia, Indonesia and Australia coupled with spot opportunities in less mature areas like Pakistan and China that will likely support further Deepwater rigs beyond the current fleet. That concludes my market roundup, and with that, I'll turn it back to you, Bob.

Thanks, Rob. With that, we're prepared to take any questions you might have.

Thank you sir, ladies and gentlemen at this time we will begin the question-and-answer session. [OPERATOR INSTRUCTIONS] The first question comes from Robin Shoemaker. Please state your company name followed by your question.

Yes, Bob, how are you? Robin Shoemaker. Bear Stearns.

Hi, Robin.

I was wondering if you could elaborate a little more on the potential reactivation of rigs. We can see from your fleet status report which ones are idle, three in the North Sea, second generation rigs and another in the Gulf of Mexico. And could you give us a sense of the cost of reactivating these rigs and what your criteria would be in terms of a contract length for proceeding along that line?

Well, Robin, I guess in terms of the likely prospects, I'd say right now we have operators who are very interested in two of the rigs, one in Norway and one in the U.K.. We've had some other potential opportunities for one of the rigs in the Gulf of Mexico, but I see that as a little bit less likely that we would meet our criteria. Our criteria is not set in stone here. I can't give you very specifics. But we're looking at only reactivating rigs where we will cover all of the cost of reactivating, which could be significant.

The cost of reactivating some of the rigs in the North Sea could run from the 15 to $20 million range up to as much as potentially $40 million depending on the program that it would go on. And we would be looking for contracts that would be term in nature and would give us full payback for the upgrade costs and significant return beyond that.

Okay. And could that work be done in the region where the rigs are in the North Sea region, or would the rigs need to move somewhere else?

The reactivation of these rigs would take place where they are.

Okay. Thanks a lot:

Thank you. Our next questions comes from John Dowd. Please state your company name followed by your question. Mr. Dowd?

Good morning. It's John Dowd calling from Sanford Bernstein. Nice quarter.

Thank you.

I was wondering how you were thinking about the upside in dayrates for the different rigs. I'm trying to sort of balance the idea that oil prices have doubled since 2001 with the idea that returns on capital for the E&P industry really haven't changed, looking at returns for some of the offshore focused E&P companies, they're actually flat since 2001. So, does that mean the E&P companies can pay a lot more or does that mean the reserve targets are smaller so there's not as much upside to the Deepwater rig rates? I guess what do you think the E&P companies can pay for these Deepwater rigs without curtailing their drilling economics?

Well, I'm not sure that we're in a very good position to answer that question. Obviously, if you look at the results that are being reported by the major E&P companies with the price of oil and gas these days, they're generating an awful lot of cash. I just can't comment on the specific economics of any project, but I would say that in terms of rate sensitivity, particularly on the High-Specification Floaters but it's even starting to flow over, I think, into some of the other Floaters for the near term, and by "near term" I mean the next couple of years, operators seem to be fairly rate insensitive when it comes to a question of getting availability of rigs in the timeframe they want. So, I'm not sure that I would hazard a guess as to what the upside of rates could be, because as I've demonstrated, I think, in the last two conference calls here, every time I say I don't think rates will go higher than X, it only takes about a week or two before they bust that limit. I don't think I can really give you much guidance there.

Okay. Thank you very much. That was helpful.

Thank you. Your next question comes from Scott Gill. Please state your company name followed by your question.

Scott Gill with Simmons & Company.

Good morning, Scott

Bob, I just want to follow up on Robin's questions regarding these reactivations. How many of those could you possibly manage at one time? Can you do as many as three?

That's a good question and something that's on our mind. I think that if the three were in different geographic areas, we could potentially do one in the Gulf of Mexico, one in the North Sea, U.K. sector and one in Norway with some overlap of those. But I will grant you, it would stretch us, and I don't anticipate that the timing would be such that we would have three reactivations going at one. It's not impossible that we might not see two reactivations going at once.

Okay. Bob, with all this heightened interest in these ultra Deepwater assets and you've seen some of your competitors starting to build new assets, are you far enough in these discussions to contemplate building new assets for Transocean?

At the present time our discussions that we're having are most centered around upgrades of existing rigs primarily because we can deliver an upgrade much quicker than we could deliver a new build . We haven't seen any indications -- I shouldn't say any. There's been one or two operators who have started to talk a little bit about the possibility of contracting for a new build, and we'd certainly be interested in those discussions when they get serious, but right now there are no operators in serious discussions about a new build, and we're certainly not going to contemplate any new builds on speculations.

Last question has to do with Norway. Last year a lot of turmoil in the labor market. It's about that time of year. Are you seeing any indications of potential labor disruptions this year in Norway?

Not at the present time, but as you indicated, things can get difficult in Norway easily. But, right now we haven't seen any indications it's going to be an issue.

Thank you.

Thank you. Our next question comes from Roger Read. Please state your company name followed by your question.

Roger Read from Natexis Bleichroeder. Good morning. Kind of following along with your comments on a new build versus an upgrade, what would be your general specifications of the type of contract you would need to do an upgrade versus a new build? I means in terms of number of years, not so much day rate because obviously it would depend on rigs, you know you talked about payback plus a return on these reactivations. I'd just like to get an idea of what you'd look for in an upgrade versus a new build or similarities there.

That's actually probably a more complex question than you realize because to some extent, it depends on the capability of the upgrade. If the upgrade that we talked about is going to be a unit that will be a good unit, but not fully competitive following it's initial contract with some of the equipment that's already out there, then we'd be more interested in a longer term contract. We generally have a criteria that would say we want 80 to 100 percent simple payback over a term that is no greater than five years. So if we can get that kind of return in three years, we'd be delighted. If we get that in a five-year contract, we'd probably be happy. The requirement for a new build is probably not going to be too dissimilar, although it would depend somewhat on exactly what the specifications on a new build would be.

Okay. And follow along with that, in the press release you commented on for the High-Spec fleet rates ranges from 200 on up and contracts from 6 months to 4 years. Is there anything that says you're at the higher end of that range with 4 years, or is it kind of closer to the 200 for 4 years? I'm just trying to get an idea of is there enough appetite right now say a 4 or 5 year contract for a new build at this point?

Well, to answer your first question specifically, the terms really range throughout the spectrum there. As I indicated, most of the interest has been in the 1 to 2 year period. Terms much longer than that have been rarer. And we really don't see a lot of specific interest in discussions from any operators today about new builds. There's been one or two that have mentioned that they are considering the possibility of a new build, but I wouldn't characterize the indications as being very far along. There's been no specific discussions in terms of what the rig might look like or when they might need it delivered or any of that.

Okay. And, Greg, one question for you. Tax rate, as you look into '06, any ideas there?

With the kind of earnings levels that we expect in '06, we would estimate the tax rate is at or below 15 percent for '06.

Okay. Thank you.

Thank you. Our next questions comes from Geoff Kieburtz. Please state your company name followed by your question.

It's Smith Barney. A couple of questions. On the upgrade and reactivation just to be clear here, if you were reactivating a rig, it would be an upgrade? Or is there other rigs that you were considering that are already active in the fleet that might be candidates for upgrade investment?

No. Geoff, the reactivations that we talked about is specifically just reactivations to bring a stack grid back in basically the same capabilities, maybe a few slight enhancements depending on the contract. Basically it's reactivating one of the stacked rigs. The upgrades we talked about are completely different. Obviously, the capital requirements are significantly more, and we've identified a number of rigs in our fleet. Some of them idle and some of them operating that could be candidates for a Deepwater upgrade to meet some of the specific requirements we're talking to customers about.

Okay, and kind of coming back on a question that was asked earlier, how many upgrade projects could you manager simultaneously?

That's a little bit tougher. I'm not sure that I could give you a crisp answer to that today. We're comfortable that we could do one of these major upgrades. Two would tax the organization pretty significantly I would think, but I wouldn't say that we couldn't do two at the same time.

All right. Okay. And just so -- I kind of calibrate what you're saying in regards to the change of tone in your customer base. If I recall correctly last quarter, you only were really having serious dialogue with two customers about contract lengths of more than two years. Has that changed?

Well, there hasn't been a lot of change in respect of a comment last quarter was in regards to our existing High-Specification fleet, particularly the fifth generation units. Tremendous demand and very little availability over the next couple of years, and we were trying to interest and continue to try to interest operators in contracting longer term past 2008, 2009. We continue to see a bit of resistance, in fact, a lot of resistance in that, and that's one reason I think you don't see much conversation from the operators about new builds.

The discussions about upgrades I think is being generated more by the fact that operators see that they can't get an existing rig anytime in the next couple years, and they're looking for ways to get access to drilling capacity that can start as soon as possible. So, some of these upgrades that we might be able to do in 20 to 24 months would actually potentially give them access to a rig before they could get an existing rig. And then we're looking at terms that are generally two years, maybe three to four in some instances, but again most of them are a couple of year drilling terms once the contract would start.

And these discussions are being had with with a wider variety of customers than three or six months ago?

We have four or five different operators who are expressing interest in these particular upgrades. Most of them are for specific opportunities that they have where they need drilling capacity and are concerned about being able to get an existing rig.

Great. Thanks very much.

Thank you. Your next question comes from Mark Urness, please go ahead and state your company name followed by your question.

Good morning. Merrill Lynch.

Good morning.

Bob, I wanted to ask a follow-up on Geoff's question there. With the upgrades that you're contemplating with some of these different operators, some of those rigs currently operating or even the other Floaters, the second or third generation rates approaching the 150 to 200,000 range would seem to be the opportunity costs taking those rigs out 20 to 24 months would be pretty high, and therefore you would require an astronomical day rate to justify doing that. Could you comment on that?

That is certainly a consideration, but fortunately we have one or two rigs that are qualified for the upgrades that are presently idle. So the opportunity cost is not as high as taking an existing rig out. Now, I guess you could make an argument that there might be some lost opportunity cost if we could reactivate the rig and put it to work in its presents configuration, but right now we don't see the opportunity to reactivate all of these rigs in their present configuration. So the opportunity cost on at least the the first one would be not significant.

Okay. Then I wanted to ask Greg about cost trends. Obviously, it's kind of tough to forecast trends in maintenance costs, but in terms of your base operating costs, labor, materials, et cetera, we've been using sort of 6 to 7 percent annual cost escalation, is that enough? With the pressures on labor, both skilled and unskilled, should we be more like 10 percent?

Well, versus last year we are expecting about a 10 percent cost increase across the board. Labor cost, pressures because we have variable pay elements in our offshore costs, we're paying higher bonuses, pay raises, currency impact, all those things that put pressure on our labor costs and our vendors are just like we have, have taken the opportunity in this market to push through very significant price increases on a lot of our maintenance spends. So year-over-year versus last year, 10 percent is probably better. We're hoping next year that that will come down closer to 6 or 7 percent. But it really depends on what the continued pressures are, what our vendors do and what we have to to respond to an increasingly tight labor markets as some of these Jackup new builds come on stream this year. It may be hard to hold that at 6 to 7.

Mark, I would just add to that I'm getting more and more concerned that the escalation in costs is going to be on the higher side with all of the announced new capacity capacity coming in and upgrades and what we're seeing from both our customers and our suppliers trying to hire more and more people, I think that the cost increases both on the wage front and with all of the backlog that the suppliers are building up and going to build up to meet the demand for all these new builds. I think that the cost of equipment is going to increase pretty significantly. We've seen some pretty good increases already this year, and I'm concerned that next year's increases as these new build programs get even bigger, could be even greater. So it's tough to give you a lot of guidance on that, but I wouldn't anticipate that our cost increases are going to down over the next year.

Lastly I wanted to ask about this year's CapEx and maybe a possible range for next year, given the reactivations and upgrades that you're plan planning. I'm just trying to gauge how much free cash flow you might have or special dividend or share repurchases.

Well, this year we expect,t for the remainder of the year, to probably spend another 100, $125 million so putting the total close to the 200 -- it 25, $250 million range. It's really hard to say next year. Absent a major upgrade, we should be in that same range of the 200 to 250, probably towards the high end of that range. If we do some reactivations, but you throw in any kind of major upgrade, and then all bets are off because that, you know, major upgrade could cause that to be significantly exceeded depending on the timing of the upgrade, how much is exactly spent during the year. So the base is that 200, $250 million range.

Thanks.

Thank you. Our next questions comes from Dan Pickering. Please state your company name followed by your question.

Hi. Pickering Energy Partners. Bob, you teased us a little with the comment about thinking about your usage of cash, but you didn't really discuss how you ranked your options and were thinking about your options. Could you shed more light on that issue for us?

Well, I think, Dan, we're still at about the same place that I've been telling investors for a while. We've been thinking hard about the alternatives for returning cash to shareholders. I say that a normal quarterly dividend is pretty low on our priority list. We don't see that as being something that really makes a lot of sense for an industry like this. So we are in the midst of thinking hard about whether or not a share repurchase program or a special dividend or some combination of the two would make the most sense and create the most value. Since we just paid about $600 million or so, used about $600 million to retire debt, you know, our cash balances are down now, and it will be a while before we build them back up to the point where we actually have to start making some real decisions about which one of those methodologies we might use. So we're a ways away from making a decision, but that's kind of the different things that we're thinking about.

Okay. Then, Bob, with 63 percent of your High-Spec fleet contracted for '06, at what point for near term bids do you stop even bidding assets so that you will have some availability as we move into next year, or would you do that?

I don't think that we would ever not bid, Dan. It might be just a question of rate. When the demand gets good enough that we're not too concerned about whether or not we win any given bid, then that's what allows the industry to actually push dayrates up, because we can bid a rate that we'd be very happy with. If we don't have any remaining capacity because it's all tied up in very, very high rates, that's not a bad situation. So we would just continue to bid rates higher and higher in order to try and take advantage of the opportunities that existed.

Okay. And it's safe to say that that number is in the high 300s at this point?

Well, it depends on the type of rig. Certainly in the high 300 for some classes of rigs. I think it could be somewhat higher for other classes of rigs, and in particular, opportunities that exist that require specific capabilities for rigs that have fairly limited supply.

Okay. Final question. You talked -- the upgrade candidates that are currently idle, we can all look at your rig status sheet and see the idle assets. I'm just curious which ones you think are the ones that can meet some of these sort of Higher-Spec needs? Could you just walk us through the one or two rigs you think are the easy upgrades here?

I'm not sure that easy upgrades are the criteria, but I'd say that the winner and the prospect are the two likely candidates in the North Sea area for reactivation.

For reactivation.

Oh. I'm sorry, Greg. I'm sorry. I don't think we want to identify the specific rigs that are available or that we think we would upgrade to Deepwater. I don't particularly want to give out too much information about which rigs or how much we think that would cost until we get closer to firming up some of these opportunities.

Okay. Thank you.

Thank you. Our next question comes from Arun Jayaram. Please state your company name followed by your question.

Good morning.

Good morning.

Dan stole all my questions, but real quickly, in terms of the reactivations next year or the possible reactivations, would the bulk of those costs be expensed or would you be capitalizing some of those costs of notes early?

It's actually a combination. Some costs -- ordinary maintenance costs and training and things like that are expensed. Some costs that we're actually adding new capital, a new crane or mud pumps or whatever are capitalized and depreciated over their lives. Then the remaining costs that would normally be expensed, but if they're directly related to the contract, would be deferred and amortized over the contract life. Now, any revenue we get as well as that's related to contract prep or the mobilization is also deferred and amortized over the contract life.

Any gauge of what the split could look like? Is it 50/50?

Every rig is different. It depends on what has to be done to the rig to reactivate it, what the contract's specific requirements are, how long the contract is, all those things. So every rig is very unique. Every rig reactivation.

Okay. Second question. Rob, you highlighted in your comments the Celtic Sea got a day rate at 325. Are you seeing similar types of rates I guess on the Marianas? Is that where you think the rates are today?.

I don't think I mentioned that rig by name, but we look forward to rates for fourth generation rigs in the Gulf of Mexico, in particular, in the $300,000 range. I think that's fair. I think some of our competitors have echoed that sentiment as well.

Last question on the Jackup side. Are there any rigs that you're planning to upgrade? Second, are there any planned mobilizations perhaps to participate maybe in West Africa, which has been a really strong Jackup market?

In terms of upgrades for Jackups, as I mentioned in my comments, to the extent that we enter into longer term contracts that allow for or require additional capability for the rigs, we will take the opportunity to do so under a full payback scenario. As we haven't announced any of those yet, I can't go into any more detail. That's certainly an opportunity we're looking at. With regard to relocation of rigs, we continue to study the markets to figure out what's the highest and best use of our assets. And, at this point in time, we don't have anything to announce about relocations.

Okay. Thanks a lots. Next question comes from Pierre Conner. Please state your company name followed by your question.

Hibernia Southcoast. Good morning everybody. Let's see, Bob, just a quick one first on the Jackup side. You were concerned about the incremental supply coming on recently. This morning you say you see some good strength continuing. Has it changed a little bit, or do you have the same concern that maybe pushed out a little?

Yes. I guess I'd say I'm still concerned, but I'm a little bit less concerned than I have been over the last six months. Unfortunately I understand another Jackup was ordered on spec this morning. I was going to say part of my improving sentiment was because there hadn't been any -- there had been a slowdown in the ordering frenzy of new Jackups. I hope this announcement this morning isn't the start of another wave.

Exercise of an option anyway.

We are concerned about the number of rigs that are going to be in the market here by '07 or early '08, but right now the market seems very robust, and I'm a little bit more optimistic. I think you still have to be concerned about what the market will look like -- it must be up close to new 40 new Jackups that are coming out now.

Right. 39. On the cost side, Bob, I know we talked a lot about the wage pressures, et cetera. My question maybe more philosophical. It seems the opportunity costs associated with down time becomes greater and greater with the rates moving into these nice levels. So, had there been any -- I know you try to return your business as efficiently as possible, but has there been any inventory to increase the inventory of spares in any way? Is that something ongoing, if you did, is that over? What's your strategy there?

I think it's a fair observation in addition to the pressures we're getting both on wages and just the increase in costs of materials. There is pressure from the operators naturally who get more and more concerned when they're paying 3 and $400,000 type dayrates about avoiding down time. And there's a natural tendency for our people to react to that pressure, and spend some money for what could probably be characterized as insurance so we wind up building a little more inventory than we normaIly would have. I can't quantify that number for you, but I'd be naive to think some of that wasn't going on in the field, and therefore, increasing some of the cash that we're spending. It won't hit the P&L because it will wind up sitting in our inventories, but our inventories are probably going to increase, although we have specific goals and we focus on managing our inventories, still, difficult to not listen to your customer when he's paying you 3 or $400,000 a day

Right every minute counts. This one maybe more rather than when the peak rates would go to and maybe somewhat open-ended. How do you think about the differences in classes of equipment now? We see a lot of jumping around on these rates on occasion. Maybe it's a question for Rob, too, fourth gen equipment jumping 300 and jumping some. Is there timing issues and is there generally a closing of the gap between some of this equipment?

I'm happy to take that one. Just to give you a little bit of perspective on this, as Bob intimated and I did as well in my comments, the Highest-Specification fifth generation rigs are right now leading edge fixtures are right now around $400,000 a day. We talked about fourth generation rigs being in the $300,000 range and then as I alluded to in my comments as well, the other Floater fleet or mid-water rigs are approaching 200,000. So there's still separation between the asset classes and in particular for jobs that are requiring the very highest specification rigs with the more efficient activity, a larger variable deck load, a DP, et cetera, you know, we expect that those will continue to command a premium and lead the market upward.

Okay. That's fair, Rob, thanks. One last quick one. Greg, your cost of debt now currently do you estimate?

With this last retirement, our debt -- our interest expense in the fourth quarter -- third quarter should drop to around 25 million, $23 million in the fourth quarter and net of interest income right around $20 million a quarter.

Okay. Great. Thanks very much, guys.

Okay. Thank you. Our next questions coming from Waqar Syed. Please state your company name followed by your question.

Waqar Syed with Petrie Parkman & Company. Most of my questions have been answered. I just have one simple question. Transition Rather, there is some -- you have the current contract expiring in March, one contract expiring in March and the second one starting in September. Are there options between March and September or is there just free available time?

Yes there is some available time there that we are currently marketing to fill, and we are relatively confident that we'll be able to keep that rig working in direct continuation.

Okay. And the rate is -- for that rig is of 250,000 range? There's been talk of a 300,000 range rate for that rig?

Yes. At this point we don't have anything to announce on that. Similar with my previous comments. The 250 to $300,000 range is certainly where rigs of that type of going.

Okay. Great. Thank you very much.

Thank you. Ladies and gentlemen, if you have an additional question, please press the star followed by the 1. [OPERATOR INSTRUCTIONS] At this time, I show no further questions. I'd like to turn the conference back over for any concluding comments.

Okay. Well, I'd just like to thank everyone for joining us, and we look forward to another good quarter coming up, and we'll talk to you in three months. Thank you.

Thank you. Ladies and gentlemen, this concludes the Transocean second quarter 2005 results conference call. If you would like to listen to the replay of today's conference, you may dial 303-590-3000 and you will need to enter the access code of 11034804 followed by the pound sign. Once again that number is 303-590-3000 and the access code is 11034804 followed by the pound sign. Thank you for participating in today's conference, and at this time you may now disconnect.