Good day, and welcome to the Transocean third quarter 2013 earnings conference call. Today’s conference is being recorded. At this time, I would like to turn the conference over to Thad Vayda. Please go ahead.

Good day, everyone. Thank you, operator, and welcome to Transocean’s third quarter 2013 earnings conference call. A copy of the press release covering our financial results, along with supporting statements and schedules, are posted on the company’s website at deepwater.com. We’ve also posted supplemental materials that you may find helpful as you update your financial models. These materials can be found on the company’s website by selecting Quarterly Toolkit under the Investor Relations tab. Joining me this morning as usual on the call are Steven Newman, chief executive officer; Esa Ikaheimonen, executive vice president and chief financial officer; and Terry Bonno, senior vice president of marketing. Before I turn our call over to Steven, I would 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. Among others, these include future financial performance, operating results, estimated contingencies associated with the Macondo well incident, anticipated results of our cost savings initiatives, capital allocation and strategy, newbuild projects, and the prospects for the contract drilling business generally. 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; and 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 or 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 Regulation G. You will find the required supplemental financial disclosures 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 folks an opportunity to participate in this call, please limit your questions to one initial question and one follow-up. Thanks very much. I’ll now turn the call over to our CEO, Steven Newman. Steven?

Thanks, Thad, and welcome to our employees, customers, investors, and analysts. Thank you for joining us on the call today. I’m very pleased to say that our third quarter results demonstrated clear progress towards several key objectives. For the third quarter, we reported adjusted earnings from continuing operations of [unintelligible] million or $1.37 per diluted share. Including $47 million in net favorable items, we reported net income attributable to controlling interest of $546 million or $1.50 per diluted share. Our third quarter financial performance reflect continued operating improvement. Our revenue efficiency was 94% compared to 93.1% in the second quarter, and fleet utilization was 83% compared to 80% in the prior quarter. These improvements translated into an increase of $81 million in contract drilling revenues, about half of the total increase of $161 million in consolidated revenues. The remainder is associated with increased activity in drilling management services. These improvements were partially offset by an increase of $98 million in operating and maintenance costs, mostly due to drilling management services and, to a lesser extent, higher shipyard costs. In a few minutes, Esa will take you through the third quarter numbers in more detail, as well as provide you with guidance for the remainder of the year and our preliminary outlook for 2014. During the quarter, we continued with our fleet transformation efforts with the commencement of operations on the Transocean Ao Thai, a newbuild high-spec jackup working for Chevron in Thailand under a long term contract. We also announced a long term contract with Chevron for a state-of-the-art ultradeepwater drillship to be delivered in the second quarter of 2016. The five-year contract on the drillship adds about $1.1 billion in backlog. The $725 million in capital costs includes the shipyard contract, project management, owner-furnished equipment including a second BOP,…

Thank you, Steven. Thanks to all of you for joining us today. I’ll spend a few moments reviewing the key financial elements of our third quarter results, and I’ll provide some comments on our full year expectations and finally close with preliminary guidance for 2014. As Steven said, we reported net income attributable to controlling interest of $546 million, or $1.50 per diluted share for the third quarter of 2013. Our results for the quarter included $47 million or $0.13 per diluted share in after tax net favorable items detailed already in our press release. Excluding these items, our adjusted earnings from continuing operations were $499 million or $1.37 per diluted share. This compares with similarly adjusted earnings from continuing operations of $1.08 per diluted share in the second quarter of 2013. Additionally, related to severances, certain existing benefit plans were accelerated into the third quarter as a result of our onshore reorganization, resulting in about $11 million or $0.03 per diluted share. For the third quarter of 2013, our consolidated revenues increased by $161 million to $2.66 billion compared with $2.4 billion in the prior quarter, reflecting continued improvement in our operational performance. As Steven said, the increase was due to better fleet utilization and improved revenue efficiency as well as increases in other revenues, reflecting higher activity levels in our drilling management services business. Higher average day rates [unintelligible], particularly in the North Sea, provided an additional positive contribution. Third quarter operating and maintenance expenses increased sequentially by $98 million to $1.49 billion due primarily to increased drilling management services activity. This was in line with the increase in revenue I mentioned already. The increase in O&M was also partly due to higher shipyard costs and an unfavorable adjustment in contingencies associated with the Macondo well incident. While…

Thanks, Esa, and good morning to everyone. Before we cover specific markets, I would like to make a few general comments. The third quarter of tendering activities slowed a bit over the previous quarter for the global floater fleet, but still provided solid contracting opportunities for our fleet. We increased contract backlog to $29.8 billion as of October 16, 2013, from $27.3 billion as of July 17, representing approximately $4.5 billion of contracts signed during this period. Additionally, 95% of the contracted backlog we added, including the ultradeepwater and newbuild, was achieved through direct negotiations with satisfied customers, avoiding the time and expense of an open tender. Year to date, we have added $7.6 billion of backlog and have now exceeded the 2012 year-end contract backlog of $29.4 billion. Needless to say, we are very proud of this accomplishment. Fleet utilization improved to 83% from 80% and the average daily revenue jumped to $392,000 per day from $383,000 per day. Numerous outstanding tenders for ultradeepwater units remain open, particularly in West Africa, as the pace of tendering has slowed due to regulatory requirements and governmental sanctioning of development programs, putting pressure on near term day rates for available units. Additionally, during the third quarter we observed an increase in the number of farm out opportunities in the ultradeepwater and midwater floater markets. While the near term softness has resulted in idle time for some of the floater fleet, we remain confident in the long term fundamentals and our customers’ willingness to continue to increase their future activity levels, as evidenced by the the contract with Chevron for a newbuild ultradeepwater drillship to be delivered in 2016. Now to specific markets. Utilization for the global ultradeepwater fleet is currently over 99%, with one [unit] available, the DWD, which we are actively…

Thanks, Terry. With that, operator, we’re ready to open it up for questions.

[Operator instructions.] And we’ll take our first question from Collin Gerry with Raymond James.

Could you give us a little bit more specificity in terms of where the cost reductions are coming from? We talked about the $300 million cost-cutting effort a while back. Is that all of that? Is there more to come following that? And then what other onshore or back office initiatives are in place on the margin improvement side of things?

Thanks for recognizing that it is actually pretty impressive guidance, and I wouldn’t mind giving some further color to that given the opportunity. If you look at the original 2013 guidance, including the G&A, our guidance was $66.2 billion. Just a reminder, that’s including G&A. Now, if we include G&A to our preliminary 2014 guidance, the corresponding figure is between $5.7 billion and $5.95 billion, so there’s a $300 million reduction at a headline level already, and that’s not even accounting for inflation. So I think you’re right, it’s pretty impressive. Now, where does it come from? It really comes from across the [unintelligible]. Fairly significant onshore reduction in line with our earlier commitments to reduce about $200 million, in comparison with the 2012 base. So that’s included now. It’s not exactly $200 million on a year on year basis, because part of the onshore expenses also got transferred as part of the jackup deal. But it’s a significant part of that. Another significant part has to do with our project execution performance in our current budget and guidance, and the third one is that we are starting to see improvements on the offshore cost base as well, which has to do with the way we operate the rigs. But that’s maintenance, that’s manning at the offshore level, and all the associated expense. So that’s the way I would like to break it down. We’ll provide further information about that when we report in more detail and a more refined format, and that will be in February when we report our Q4.

And when you say project execution, I’m looking at the out of service cost per day in the ultradeepwater space. It came in considerably lower than the last couple of quarters, and maybe where a lot of people were modeling. Is that the number that reflects your statement of project execution?

Yeah, it’s volatile is one way of looking at that. So quarter on quarter, comparisons are potentially a bit misguiding, but that’s kind of what overall is going to reflect the improving performance. But you have to keep in mind that it’s not just out of service time related, because the mix of projects has got a big impact. So the more we do a lot of enhancement projects, the more we capitalize, the more we do periodic survey type activity and five-year [SPSs] and so on, the more we expense. So it really is a mixed bag, but that’s kind of the activity that drives the improvement there.

And then last one from me is kind of a detail one. So the payments that you’ve outlaid in your press releases for Macondo, where do those show up in the cash flow statement? Is there a specific line item that we should see, or that is in one of the different buckets?

Yeah, they’re part of the operating cash flow. So working capital comes down as a result.

So it’s in operating cash?

Correct.

And we’ll take our next question from Judd Bailey with ISI Group.

I wanted to ask a couple of questions, just following up on Terry’s comments, on the ultradeepwater and deepwater segment, if I could. Terry, did I hear you right that you expect some weakness for lower-tier ultradeepwater rigs, to the $500,000 to $550,000 range? Is that predominantly for some of the smaller fifth gens that you have?

That’s what we’re seeing right now, that sort of pattern. We know that as we look at some of the open opportunities and as we put our ear to the street, trying to figure out where we are, that’s the range that we end up in.

And then on the deepwater side, you noted recent fixtures - there haven’t been a lot of them - were $425,000 to $475,000, and your [unintelligible] is going to be more weakness, probably below that range? We may see some competitors with lower rates below that range? I just want to clarify that we could see more of a step down, whether it’s temporary or not, for some of the deepwater rigs.

I think what we may see here is we may end up seeing a few of the deepwater rigs being bid into the midwater market. So I think you’re going to see that phenomenon, just like we saw in the last cycle. And since there’s very few data points and not a lot of tendering, I expect that the tendering is going to be very competitive. So I think there’s a chance that that may happen.

And do you think that’s a dynamic that’s going to kind of continue throughout 2014 and into 2015? You kind of alluded that some of this stuff could be temporary. Do you think that dynamic will reverse itself or do you think that’s just kind of going to be how the market’s going to be for the next couple of years, as all these ultradeepwater rigs come in?

I think it’s temporary. I think we could get a lot of health in the market if we could get these multiple opportunities in West Africa. And if we had any help from the Brazilian market, I think that this market looks a lot better. I don’t really have an exact timeframe that we’re looking at. And another thing I think that potentially could help the market, it’s unfortunate, is the delays of the rigs coming out of the shipyards. So if you see some of those delays, then we may have some filler opportunities for our fleet and for our competitors’ fleet.

And then my last question would be, it sounds like we’re going to have some gaps between jobs for some of your deepwater rigs. Can you give us any type of insight as to what’s a decent timeframe? Should we count on three months, six months? Or is it just going to vary depending on the rig and the specification and the location of the rig?

I think the latter part of your commentary is fairly accurate.

And we’ll take our next question from [Lucas] [unintelligible] with [APG]. [Lucas] [unintelligible] - [APG]: Terry, if I may, considering the bifurcation theme that you sort of touched upon, you were saying that most of the lower spec rigs are able to drill the [prospect], that the higher end rigs are getting contracted for. I was wondering is there sort of a meaningful spread in the day rate where operators would be willing to go for the older, lower-spec rigs? Or is the technical specification [unintelligible] just excluding them?

To answer the first part of your question, there’s always a meaningful differentiation in the numbers depending upon the type of equipment. When we look at our competitive tendering, that’s what we like to look at. We can see against dual activity, single activity, offline handling, and I think you have to look at the programs that are being drilled, you have to look at the efficiencies, and you have to figure out what’s competitive. But to look at what’s happened recently, we haven’t seen that phenomenon because of the availability of the ultradeepwater newbuilds. There’s clearly a preference, so there hasn’t been a price differentiation that has actually come into play yet. So we’re looking at every opportunity on a case by case basis, and like I said, once this market gets tight, these rigs are perfectly capable of drilling a huge portion of the world’s resources. [Lucas] [unintelligible] - [APG]: And when you talk about the license project sanctioning in, for example, West Africa, is that coming from the operators, or is it coming more from the authorities?

Well, the governmental authorities have to sanction the project and approve the programs that are to be drilled, and if you look at a couple of examples in West Africa we’ve got one tender that we participated in in Angola that’s still on the plate, and that started a year ago. So it’s just something that we deal with in West Africa and it’s pretty typical. But there is a tremendous amount of demand there, and like I said, as soon as we see those programs being awarded, I think our market looks a lot better.

We’ll take our next question from J.B. Lowe with Cowen & Company. J.B. Lowe - Cowen & Company : I just had a quick question on the West African opportunity. Could you guys give us an idea of how many rigs could actually be taken, if all of these projects were sanctioned?

You know, today we’re looking at anywhere from 8 to 10 that have already been tendered. And we know that there’s more to come. So there’s a lot of capacity there that could be fulfilled. So I think when you look at 8 to 10 rigs in 2014, that changes things up quite a bit. J.B. Lowe - Cowen & Company : And same question on Brazil. If projects there were accelerated, particularly in the Libra side of things, same question. How many rigs do you think of the older rigs do you think Brazil could take?

I think we have to look at numbers instead of older rigs. You know, in order to develop that program, what we’re hearing, the preliminary numbers are that wells to be drilled are between 200 to 300 wells. And if you add that to the northern opportunity that we know the independents have signed, and quickly put a consortium together to start drilling those prospects, and then the majors are looking to the 2015 season. Again, I think it helps the numbers, and it supports what we’re saying. As we get through this near term softness, to the other side of development of more demand, because of the success in the exploration programs, I think this market starts to look really good. J.B. Lowe - Cowen & Company : Okay, and one final one, just kind of rig-specific, on the Polar Pioneer, when you move it to Alaska, what’s the daily operating cost there compared to Norway? Is it about the same?

You know, right now we’re going through that. I don’t want to really talk about the specifics of the contract. But what we didn’t know, we protected ourselves, and then the pricing that we did know… So I wouldn’t say it’s very dissimilar to the U.K., but we’re just going to have to wait and see.

And at this time there are no other questions in queue. I’ll turn it back to Thad Vayda for any closing remarks.