R. Thaddeus Vayda - Vice President of Investor Relations & Communications Steven L. Newman - Chief Executive Officer, President, Director and Member of Executive Risk Management Committee Gregory L. Cauthen - Interim Chief Financial Officer and Executive Vice President Terry B. Bonno - Senior Vice President of Marketing

Angeline M. Sedita - UBS Investment Bank, Research Division Robin E. Shoemaker - Citigroup Inc, Research Division Judson E. Bailey - ISI Group Inc., Research Division Ole H. Slorer - Morgan Stanley, Research Division Ian Macpherson - Simmons & Company International, Research Division Matt Conlan Matthew D. Conlan - Wells Fargo Securities, LLC, Research Division Kurt Hallead - RBC Capital Markets, LLC, Research Division Harry Mateer - Barclays Capital, Research Division Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division Hugh Wynne - Sanford C. Bernstein & Co., LLC., Research Division Darren Gacicia - Guggenheim Securities, LLC, Research Division

Good day, everyone, and welcome to today's Transocean's Second Quarter 2012 Earnings Conference. As a reminder, today's call is being recorded. At this time, I would like to turn the conference over to your host for today, Mr. Thad Vayda. Please go ahead, sir.

Thank you, Sarah. Good day and welcome to Transocean's Second Quarter 2012 Earnings Conference Call. A copy of the press release covering our financial results, along with supporting statements and schedules, is posted on the company's website at deepwater.com. We've also posted a file containing 4 charts that may be referenced during today's call. This file can be found on the company's website by selecting Investor Relations, Quarterly Toolkit and then PowerPoint charts. The charts include average contracted dayrates by rig type, out-of-service rig months, operating and maintenance cost trends and a new chart illustrating historic and forecasted out-of-service rig month by asset class for the years 2008 to 2013. The quarterly toolkit includes 4 additional financial tables provided for your convenience, covering revenue efficiency, other revenue detail, daily operating and maintenance cost by rig type and contract intangible revenues. Joining me on today's call are Steven Newman, Chief Executive Officer; Greg Cauthen, Executive Vice President and Chief Financial Officer; and Terry Bonno, Senior Vice President of Marketing. Before I turn the call over to Steven, I'd like to point out that during the course of this call, participants may make certain forward-looking statements regarding various matters related to our business and company that are not historical facts, including future financial performance, operating results, estimated loss contingencies associated with the Macondo Well incident and the prospects for the Contract Drilling business. Such statements are based on the current expectations and certain assumptions of management and are therefore, subject to certain risks and uncertainties. As you know, it's 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, the effects and results of litigation assessments and contingencies, and operational and other 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. Transocean neither intends to nor assumes any obligation to update or revise these forward-looking statements in light of developments which differ from those anticipated. Also note that we may use various numerical measures on the call today that are or may be considered non-GAAP financial measures under Reg G. As I indicated earlier, you'll 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 Investor Relations, Quarterly Toolkit and non-GAAP financial measures and reconciliations. Finally, to give more people an opportunity to participate in this call, please limit your questions to one initial question and one follow-up. Thanks for your time and I'm now turning the call over to Steven Newman. Steven?

Thanks, Thad, and thank you all for joining us today. In beginning my comments, I'd like to focus on 2 key highlights from yesterday's press release. First, our second quarter revenue efficiency of 92.5% was the highest we have seen since the second quarter of 2010. While I will remind you that our progress going forward will not necessarily be linear, the 2 percentage point improvement over the first quarter demonstrates that we are making progress in our efforts to improve our operating results. And I'm particularly pleased with the performance of the Ultra-Deepwater fleet, which delivered revenue efficiency of 92.2%. These high dayrate rigs have the greatest impact on our performance and our people are doing a great job in focusing on operational excellence. Second, between the April Fleet Status Report and the July Fleet Status Report, we signed $4.7 billion in new contracts. This represents a tremendous accomplishment and a lot of hard work on the part of Terry and her worldwide marketing team. As significant as the dollar magnitude of this backlog is, more importantly, we have seen an improvement in contract terms, particularly in the area of enhanced subsea-related maintenance and repair provisions. Our customers recognize that this is an industrywide issue and are partnering with us in addressing it. For the second quarter, we reported a net loss attributable to controlling interest of $0.86 per diluted share. These results included net unfavorable items totaling $560 million, or $1.58 per diluted share, including an increase to our Macondo Well incident estimated loss contingency, discrete tax benefits, gain on the sale of rigs and other items. Considering these items, adjusted earnings were $0.72 per diluted share, a quarter-on-quarter increase of $0.18 versus the first quarter of 2012. While our operating and maintenance costs in the second quarter…

Thank you, Steven, and good morning, everyone. As Steven mentioned, we reported a net loss attributable to controlling interests of $304 million, or $0.86 per diluted share, in the second quarter 2012. Excluding $560 million in certain net unfavorable items, our adjusted earnings were $0.72 per diluted share. This compares to similarly adjusted restated earnings of $0.54 per diluted share in the first quarter 2012. During the second quarter, we identified an error associated with the recognition of $104 million of Macondo-related insurance receivables for legal and other costs and have made appropriate adjustments to our prior-period consolidated financial statement. Based upon the very favorable district court ruling with respect to our insurance coverage, we believe that the ultimate reimbursement of our legal cost remains likely. At this point, however, we are just not able to record these particular insurance receivables as an asset under U.S. GAAP. In this regard, we have determined that our insurance receivables were overstated by $67 million in 2011 and an additional $37 million in the first quarter of 2012. These amounts are immaterial to prior-year financial statements. However, the company has made these adjustments in accordance with SEC guidelines, which stipulate that if, when corrected in the current year, a prior-period error to be material to the current year, the prior-year financial statement should be corrected. In addition to the adjustments related to insurance receivables, we are required to record all other adjustments related to the fiscal year 2010 and 2011 in the first quarter of 2012, even though these adjustments were and continue to be immaterial. These additional immaterial adjustments primarily relate to repair and maintenance costs, income taxes and the allocation of net income or loss attributable to noncontrolling interest. As the adjustments are immaterial to the prior years, we do not…

Thanks, Greg, and hello to everyone. Before we cover specific markets, I would like to make a few general comments. From a marketing standpoint, the recent weakness and volatility in oil and gas commodity pricing during the quarter have not dampened the demand for any asset classes within our drilling fleet. This is evidenced by the significant number of contracts executed since our last earnings call, totaling $4.4 billion. Year-to-date, we have secured contracts totaling $6 billion, resulting in an increase in our total contract backlog for the first time since the fourth quarter of 2008. Additionally, we have opportunities worth over $2 billion currently under discussion. More importantly, the pace of contract executions so far this year has already exceeded the level we attained in all of 2011 and we still have 5 months left to go. We look forward to the many opportunities available in the market for the remainder of 2012 and on into 2013. Utilization in dayrates for the Ultra-Deepwater fleet are near historic highs, and our customers continue to secure rig capacity at near record levels over the past 2 quarters. With multiple customers competing for the same units available in 2013, we believe that the remaining supply will be quickly absorbed, pushing the positive contracting momentum to the units available in 2014. With the high utilization in the Ultra-Deepwater market, we are seeing increasing opportunities for our Deepwater fleet. Tendering and contracting activity in the Deepwater market is continuing to improve, as evidenced by the recent fixture for our Transocean Marianas at 530,000 per day plus performance incentives. This is the first fixture over 500,000 per day for a lowered Deepwater unit since 2008. We expect to report more positive news for the rest of our Deepwater fleet with availability in 2012. Midwater activity,…

Thank you, Sarah. With that, we're ready to open it up for Q&A.

[Operator Instructions] We'll go first to Angie Sedita of UBS.

Steven, just first, a theoretical question on the dividend and potentially or ultimately the reinstatement of the dividend. Do you believe, you and the Board, that you would already need to have settled with the Department of Justice and the plaintiff before considering the dividend or reinstating partially the dividend? Or given the large reserve that's been taken, could you consider, you and the Board, reinstating the dividend before settling with both parties?

This is delving into the realm of speculation. So, let me try and give you at least some guidance in how we would think about this. First of all, I would tell you that the reserves we have taken are noncash reserves. They are booked through our balance sheet but they would require, once we do reach agreement with the other parties in the Macondo situation, it would require us to actually fund that with cash. So that would be a use of cash that as we book reserves on our balance sheet would ultimately have to be satisfied. As we think about it from the perspective of the board, we're focused on the quality and the strength and the integrity of our balance sheet. We're focused on remaining an investment-grade quality issuer. We're focused on identifying opportunities to reinvest in our business and then we're committed to returning excess cash to our shareholders. And so that's kind of the framework within which we would think about it. I wouldn't set out that as an absolute requirement, we'd have to have a settlement but that would be a significant factor in our consideration, for sure.

Okay. That's helpful. And I know you touched on briefly on the new rig construction and, obviously you've talked about it in the past. But correctly or incorrectly, I had recently heard that there could be a reevaluation of building Ultra-Deepwater rigs on speculation. And is the Board reevaluating this policy or could they revisit this policy?

As I said in my comments, Angie, we remain reluctant to add speculative capacity. That's not an absolute. It is something that the Board regularly evaluates. We are interested in identifying opportunities to reinvest in our business that meet our reinvestment criteria and add to our focus on high-spec assets.

Okay. Okay. Finally, and as a follow up to that, as you mentioned, new management on the jackup and placing it into a separate entity, does that imply that it could still be a possibility or is still a sale clearly on the table?

Well, we continue to consider all of the divestiture alternatives that are available to us. We've made progress in selling single assets and we continue to evaluate the possibility of selling a package of assets or packages of assets and also the possibility of an IPO or spin type transaction. It's all still on the table.

We'll go next to Robin Shoemaker of Citi.

Steven, just for clarification. On the $750 million additional charge, was there any event or court ruling or anything specific that led to that charge taken in the second quarter? How does that process work, if you could describe it?

The way the process works, Robin, the process itself is relatively straightforward. It is a result of management evaluating all of the facts and circumstances associated with the Macondo Well incident and we do that evaluation almost on an ongoing basis. So as we approach the end of a quarter, we get together and we do the internal evaluation and then we obviously review that evaluation with our external auditors. And that is what resulted at the end of the quarter in the addition of $750 million to the loss contingency.

As you identify rigs for potential sale, you mentioned the Discoverer 534 and another rig, how you gauge demand for those rigs, which obviously need considerable capital investment, to put them back into service? And are there, these last 2 that you've identified, are we likely to see more within the idle fleet that would be good candidates for divestiture?

Yes, I would tell you that if you think about the company's strategy to reduce our exposure to low-spec commodity class assets and you look at some of the idle capacity we have, certainly some of that idle capacity falls into that category of low-spec commodity class. And so it's really an ongoing process on the part of our asset divestiture team to evaluate opportunities in the marketplace, to remain in contact with both rig brokers and buyers to see if we can identify opportunities that make sense for us, to dispose of those assets, to divest ourselves of those assets. That divestiture team is doing a great job. We're making good progress on it and we'll continue to focus on that as one key element of our strategy.

[Operator Instructions] Up next, from ISI Group, we'll go to Jud Bailey.

Quick question on Brazil. It sounds like Petrobras may be coming out with some tenders here shortly, but I was wondering if you're having any conversations or talking to any non-Petrobras customers in Brazil. It sounds like there may be some more opportunities developing for non-Petrobras operators down there. So I was wondering if you could comment on that, please.

Judd, this is Terry. We remain in discussions with Petrobras and we look for them for guidance, certainly on the existing fleet and when they're going to go about doing that. Right now, they are tied up on the steady contract awards. So you just noticed that 6 awards have already been awarded to BrasFELS by Petrobras to SETI. So they're working on those contracts, they're trying to finalize the other ones. And then, after they do that, they're going to refocus on their extension of fleet and also incremental rigs. So we think that there will be, as I stated in my notes, some incremental rigs to bridge to these newbuilds. Now, we are engaged in discussions with the independents in Brazil also and we are drilling for a few independents now. So we do see that there's other opportunities there too.

Okay. And a follow-up on some of the asset sale questions, kind of broke up into 2. The disclosed sale price on the 534 was below low below what we had expected. Can you say if there was any equipment that was taken off that rig or wasn't included or if it was coming up against a survey of any type? And then also, are there other opportunities to sell that class of asset and upgraded Deepwater rig?

Yes. I'll tell you, Judd, we don't ever comment on the individual consideration we receive for any particular asset, and each one of those asset transactions is a little bit different in terms of the equipment that's sold and the provisions that are included in the sales agreement. So I'm not going to comment specifically on the sale of 534 beyond the fact that we've listed it as an asset held for sale. Outside the 534, beyond the 534, there are, as I said earlier in response to a question, there are other assets in our fleet that fall into that low-spec commodity class, older conventional Deepwater equipment, older generation Deepwater equipment that we think would be better in somebody else's hands. And so we will continue to execute that asset strategy to position the company as a clear leader in Ultra-Deepwater and high-spec jackups.

We'll go next to Ole Slorer of Morgan Stanley.

Could you talked a little bit on that point? I mean you raised guidance on a sort of slightly, I mean it was not much at all. So hoping to get some confidence now that you're hopefully getting through the biggest hurdle in terms of upgrading your very ambitious upgrade programs. So could you give a little color on what specifically is left for you to do now in order to get the operating efficiency to the level that you think is appropriate?

As I mentioned in my call, and this has been a consistent theme in our comments for the last several quarters now, we're focused on thorough inspections and standardized maintenance and rigorous pre-deployment testing. And when you say that, you can generally get it out pretty quickly, but when you try and implement it across a global fleet like ours, each particular element of that approach to improving our operations takes a lot of hard work and effort on the part of our worldwide operations team. I think the results in the second quarter demonstrate that we're making progress. But as Greg indicated in his comments, our guidance for revenue efficiency for the full year 2012 remains about 92%, and it could take us some time to get back to our historical levels of where we were prior to experiencing our troubles, where we were delivering revenue efficiency in the mid-90s. So we've still got some work to do in terms of implementing that consistent program across the entirety of our fleet throughout all of the different elements of it. But I'm convinced we're making progress.

Would you still have a roadmap in place to get you to the mid-90s?

Absolutely. It's a combination of the technical efforts we're making in terms of improving the performance and the reliability of our equipment and all the hard work being done by Terry and her marketing team in terms of improving the contract terms and conditions. We'll get there.

We'll go next to Ian Macpherson of Simmons & Company. Ian Macpherson - Simmons & Company International, Research Division: Steven, with the creation of a separate organization for the jackups, should we consider this to be more of a process in order to move one step closer to a standalone entity? Or in the meantime, will we see some appreciable change in the way the jackup business is running? In other words, are we going to see higher or lower costs in that business than we otherwise would have and any change in the way the jackups are marketed more or less aggressively, et cetera, et cetera?

Ian, I think your characterization of this as a process is exactly right. We've just taken the initial steps of starting to create the organization. We've been working on the approach to selling individual assets for some time now. This positions us further along the spectrum if we were to actually identify a package opportunity that we could pursue or ultimately some kind of a large capital markets transaction like an IPO or a spin. This is a process that will help us get there. Ian Macpherson - Simmons & Company International, Research Division: My follow-up is, again, kind of flogging the asset sales topic. Do you see the opportunity to sell floaters for well intervention conversions as scalable in any way? I know that Helix doesn't have unlimited balance sheet, but do you see new entrants into that market or existing participants in the eastern hemisphere looking for conversions?

That's a good question, Ian. Over the course of the last year or 18 months, we've sold assets into the accommodation market. We have sold assets into the drilling market. We're open to selling assets into the intervention market. I'm not sure how much that will actually grow. We've been talking about the intervention market for several years now with the increasing prevalence of subsea wellheads installed around the world. You'd think there'd be a market there. And so if it does materialize, I guess it wouldn't surprise me.

We'll move to Wells Fargo's Matt Conlan.

So just getting back to the stronger revenue efficiency, it seems like not only you but also the other drilling contractors show that they kept their Deepwater assets operating better this quarter than they had for the last few. What kind of -- how is the relationship between you and your customers? Are they becoming less draconian as to what level of VOP issues are tolerable versus what requires a drilling stoppage?

I think what I would say to that, Matt, is everybody's learning as we go on. We started out in the immediate aftermath of Macondo with a lot of heightened scrutiny and very, very low levels of tolerance. I think we're all learning and improving the way we risk assess and operate and maintain subsea equipment. And I think that's reflected in the industry's improved performance.

Okay. That's terrific. And as a follow-up, on your forward cost guidance, does that include expenses for reactivating rigs that haven't already been announced? And if so, how much of that is in those cost estimates?

It generally doesn't include expenses for reactivating rigs that haven't been announced. The only exception, and we've talked about this previously, is on the Richardson, we are doing some preliminary work on long lead time items and everything. And so those costs are included in the cost estimates. But other than that, until we make a decision to reactivate a rig, it's not in our cost guidance.

Kurt Hallead of RBC Capital Markets.

I just had a question on the overall market dynamics. You indicated, Terry, I think, some possibilities to activate rigs, I think both in the Midwater and on the jackup front. How would you characterize those opportunities today versus maybe 3 or 6 months ago? And could you potentially put a number behind that?

We haven't been putting actual numbers of what we think that rig could reactivate. What we're doing is we're going through this business case analysis as you would expect to see which rigs we could put to work with the continued improvement of demand out there. And the North Sea, we believe, is going to perhaps provide an opportunity where we could reactivate a rig and be happy to do so. The term is certainly there and the rate is certainly there. So we like what we see there. We're working on that. And then there are other opportunities that we see also in Australia, where we could potentially reactivate a rig there. So we like those 2 opportunities. We're working on them very hard. In the jackup space, multiple tenders are coming in from Qatar, from Saudi. Certainly, ONGC is about to come out with what we think is going to be a 8-rig package. So we think that those -- with the current demand situation in those arenas, we believe that we'll be able to reactivate some more jackups.

From Capital Markets [ph], we will hear from Robert Jensen [ph].

You touched a bit upon this earlier, but circling back to the 534, you previously said that, that was one of the units you considered to reactivated. And if I remember correctly, you had already ordered some long lead items for that rig. And given that's now sold, should we read into this that you've become less interested in reactivating floaters? Or was that just a oneoff?

No. You have to look at those decisions on an asset-by-asset basis, Robert. The evaluation surrounding the 534 was specific to the 534. So even though we may have ordered some long lead equipment when we do that, we typically focus on the equipment that is transferable across our fleet. So that investment can be recaptured elsewhere. And then we look at the specific condition of the 534, the opportunities that are available in the marketplace that meet the specifications of the 534 and the economics of reactivating the 534. In the case of the 534, we made the decision that it made more economic sense for us to sell that asset.

Okay. Fair enough. Just one question on the cost side as well. You gave some indications on the 2013 cost level. But if you look longer term, like 2, 3 years down the road, in your opinion, is there any chance of you getting costs back towards the $6 billion mark or even below? Just trying to get some sense of what's this long-term normalized OpEx level for you guys.

One, certainly looking long term like that is very problematic. Certainly over time, we would expect to see improvements in some of the issues related to the BOP recertification and all that. But over that same period of time, you've got general industry inflation that's moving the other way and some of the issues regarding the new regulations have given our OEMs a lot of pricing power. And so net-net, long term, we would expect to see costs continue to increase. I mean that those 2 trends, the inflationary trend is going to offset the improvements and how we are able to do our maintenance.

From Barclays, we'll hear from Harry Mateer.

I guess first question, as you see it today, do you expect to be able to pay down the early 2013 maturities, as well as the Series C convert with cash?

That's what we're currently anticipating. Steven talked about we're targeting $500 million to $1 billion of asset sales. And so with our cash from operations, the proceeds from those asset sales as well as the cash we currently have in the bank, we're considering paying off that debt now. As time progresses, we'll certainly look at that and whether it makes sense to refinance or pay that off with cash. But we are certainly, at this point, able to pay that off with cash, if that makes sense.

And then as my follow up, can you just give us the exact balance on the Aker export debt? At June 30, I know you mentioned it was around $800 million, but if you could give us the exact breakdown between short term and long term that would be great.

I don't have that exact breakdown between short term and long term, but we'll have to report back with you later.

We'll go next to Joe Hill with Tudor Pickering. Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Greg, I was just wondering if there's any Macondo legal expenses in the 2013 cost bump?

Yes. So we -- as Steven's talked about, we expect the trial to start in 2013. So in our very rough estimate of 2013, expenses are Macondo, legal expenses and because we expect to be in litigation, there's some increase, but frankly, it's a small -- compared to the overall operating and maintenance expense, it's relatively small. So that's certainly not a big driver in the increase, but there is a small increase. Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. And, Greg, just thinking about your tax guidance here. We're certainly not seeing the benefits of the tax inversion with the redomestication, and I'm wondering if you can give us some insight as to why that is and what the prognosis is going forward for that?

Yes. Our tax structure is actually working exactly as anticipated, but the tax structure generates very low marginal rates, which benefit the company when it has very high margins. And despite the operational improvements we've seen several quarters, we're clearly not back to the kind of margins that we should have and expect to have in the future. And so as you see, our margins increased with those low marginal tax rates that will drive the effective tax rate right back down. If you go back and look at a 15-year cycle, you'll see this happened to the company previously in the downturn in the early 2002, 2003, where our tax rate went way up and profitability declined. And as soon as profitability came back, tax rate plummeted and that's what we would expect to happen here.

Hugh Wynne [ph], Sanford Bernstein. Hugh Wynne - Sanford C. Bernstein & Co., LLC., Research Division: I appreciate the detail in expected out-of-service days in '13. Should we assume that about 2,700 days is probably a normal run rate or is that on the low side?

If you look at Chart 3, that's the new chart that we've now provided out on the website, we show our 5-year history of out-of-service days and you'll see that 2013 looked a little lower than the average pre-Macondo. Now as I pointed out, we don't, in the Fleet Status Report, include unplanned shipyards or whatever, and those pre-Macondo years have unplanned shipyards in them. So it's a little low but broadly, if you factor in some contingency for unplanned shipyards, it's broadly in line with what we saw pre-Macondo. Hugh Wynne - Sanford C. Bernstein & Co., LLC., Research Division: Okay. And then an unrelated follow up. I believe you're currently not booking any tax benefit associated with the Macondo charges. Is that correct and have you assessed that potential?

We're not booking any tax benefits associated with the Macondo charges, because currently we have a reserve into booked tax benefits. You really need to know with great specificity what exactly is going to be paid, when it's going to be paid, what entity is going to be paid in and at this point, we have none of that information. And so it won't give us a lot of comfort to book any tax reserve. But even as we look at hypotheticals, I want anticipate a very significant tax offset, even when we do get that additional detail.

And we'll hear next from Darren Gacicia with Guggenheim.

I wanted to ask, I noticed very kind of positive about the guidance on costs. As you look into what you have in your fleet in terms of existing contracts for cost escalation clauses, and you look at that versus what you're planning at the margin and how you see that kind of rolling through, can you give me a little color on the mix of rigs that have cost escalation clauses? And then maybe what's included in that incrementally? Is that a part of the contracting process that's actually getting better?

This is Terry. Most of our High-Specification Floaters that are on long-term contracts have cost escalation provisions in them. It's been an industry standard for quite some time and we don't believe that that's particularly going to go away because we're seeing, in a lot of the countries that we're working in, we're seeing the cost certainly of labor going up quickly. So this is something that we've negotiated for years. We're continuing to negotiate those same provisions and we haven't seen pushback. But as far as to give you a specific number, I don't have that information readily with me. But, again, if you look for long term and you look for the High-Specification Floaters, it's an industry norm.

And so therefore, some of the concerns across the states about labor shortages and costs going up shouldn't really be an issue for you? And then kind of secondarily, if you think about subsea stack downtime as you kind of read through the industrywide presentations about what's causing downtime, that's an incremental too. Is that something where, not only do you get kind of labor coverage, but you also may be getting it for subsea stack down incrementally too, and that's part of why you're looking a little bit better on the cost side looking forward?

Darren, I wouldn't make that 100% statement. Yes, it's not universal. I mean each contract is negotiated on a case-by-case basis and it's all dependent upon where you are in the market and what you get and you don't get full coverage on every escalation provision. They're all different. Some are indices, some are based on flat rates. So it's just, it completely depends on the situation and the country.

And be careful of when we have cost escalation protection. That shows up in the revenue line. So when we guide to cost, that includes all our expectations of future cost increases on those contracts that have cost escalations that will show up in the revenue line. And as Terry mentioned, it's not unusual on maintenance costs for those escalation provisions to be based on indices or other formulas that have not really captured all the additional maintenance we've had to do post-Macondo. So they work very well on labor and on general inflation, but not on an increase in actual maintenance activity. So they're not working well. And also, I'd caution you not to assume because we have escalation provisions, that cost increases don't have an impact on the company going forward because new contracts are falling or dayrates are set by the general supply/demand and we're still subject to the higher cost level in that area. So be very careful on this topic.

And it appears we have no further questions at this time. Mr. Vayda, I would like to turn the conference back over to you for any closing remarks.

Thanks very much, Sarah. Thanks to all our participants today. We very much look forward to speaking to you again on the third quarter call. If you have any follow-up questions, please don't hesitate to ring us up. Thank you.

And again, that does conclude today's conference. We thank you all for joining us.