Good morning, my name is Regina, and I will be your conference operator today. At this time, I would like to welcome everyone to the Noble Drilling third quarter 2010 earnings call. (Operator Instructions) All lines have been placed on mute to prevent any background noise. After the speakers prepared remarks, there will be a question & answer period. If you would like to ask a question during that time, simply press star and then the number 1 on your telephone key pad. If anyone should need assistance at any time during this conference press star, then zero and an operator will assist you. As a reminder, Ladies and Gentlemen, this conference is being recorded today, Thursday, October 21, 2010. Thank you, I would now like to introduce Mr. Lee Ahlstrom, Vice President of Investor Relations and Planning. Mr. Ahlstrom, you may begin your conference.

Thank you Regina. And good morning and welcome to Noble Corp’s Third Quarter 2010 earnings call. Before we begin, I’d like to remind everyone that any statements we make today about our plans, expectations, estimates, predictions or similar expressions for the future, including those concerning financial performance, operating results, tax rates, spending guidance, the drilling business, backlog, day rates, contract tenders, extensions or commencements, the period of restricted drilling activity in the U.S. Gulf of Mexico, and timing for compliance with new regulations, new bill delivery dates, plans and objectives of management for future operations, the outcome of any litigations, dispute, or investigation, and the effects of our confirmation of the previously announced Frontier transaction and Shell agreement, are forward-looking statements and are subject to risks and uncertainties. Our filings with the U.S. Securities and Exchange Commission, which are posted on our website, discuss the risks and uncertainties in our business and industry, and the various factors that could keep outcomes of any forward-looking statements from being realized. Our actual results could differ materially from these forward-looking statements. We have included summary balance sheets and income and cash flow statements with our earnings news release. Also note that we may use non-GAAP financial measures in the call. If we do, you will find the required supplemental disclosure for these measures, including the most directly comparable GAAP measure on our website and an associated reconciliation, also on the website. Now, I’ll turn the call over to David Williams, our Chairman, President, and Chief Executive Officer.

Thanks, Lee. Good morning, everyone, and thanks for joining us on the call today. It’s been a challenging quarter to say the least, on a number of fronts, and I look forward to discussing our accomplishments and some of the issues that we have with you today. Joining me on the call today are Tom Mitchell, our CFO, and our Senior Vice President of Contracts and Marketing, Roger Hunt, joining us from Geneva. Excuse me, I’m tongue-tied already. Let me begin with some positive. On June 28, we announced that we had entered into a transaction to purchase privately held Frontier Drilling. And a cash transaction that valued that enterprise at $2.16 billion. In addition, we entered into agreements with Shell for more than 23 rig years of work, including contracts on two drill ships. One of which the Noble Globetrotter was already at that time, under construction. Together, the shell of Frontier deals, at its seven drilling units in FPSO to the fleet, and doubled the backlog to about $14 billion. During the third quarter, we successfully closed the transaction and have been working hard to integrate the assets and the folks into Noble. We were also able to secure $1.25 billion financing for the debt portion of the Frontier transaction at a very attractive blended rate of about 4.9% and a combination of 5, 10, and 30 year notes. Finally, we entered into a shipyard contract for the construction of the second Shell drill ship, the Noble Globetrotter 2, with all in price of $550 million. We are delighted to have concluded these transactions and believe the strategic relationship we’ve established with Shell will provide a foundation for additional growth, and benefit the company and our shareholders for many years to come. Furthermore, our balance sheet remains strong…

Thank you, David, and good morning. Last night we reported net income for the second quarter of 86 million, or $0.34 for fully diluted share on total revenues of 613 million. The results include approximately 14 million or $0.05 per share of merger transaction cost related to our acquisition of Frontier. The results for the third quarter reflect the full consolidation of Frontier’s assets. As such, direct comparisons of second quarter figures will be a bit difficult, however, in my remarks, I’ll be breaking out revenue and drilling costs related to the required assets to help gauge the contributions to the quarter. Even with the inclusion of Frontier, our numbers are down significantly from the second quarter 2010. We had revenues of 710 million fully diluted earnings per share of $0.85. The difference is driven by issues related to the impact from the moratorium in U.S. Gulf, other stack time, day rate, rollovers, and the merger cost. For the third quarter, we reported drilling revenues of 585 million versus 688 million in the second quarter. The Frontier assets contributed about 48 million in revenues, but even so, our drilling revenues for the quarter were still down about $100 million. This reduction was driven primarily by a full quarter of reduced revenue from our Floater Fleet in the U.S. Gulf, which amounted to 146 million. Reduced revenue from our lower day rates in Mexico, the North Sea, and the Middle East, and some additional stack time in Mexico and on the Noble Paul Ramano in the Gulf, was essentially offset by fewer shipyard repair days, bonus revenue in Brazil, and the additional calendar day in the quarter. Quarter on quarter, the Noble home of Ferrington didn’t have much of an impact since we weren’t paid for the first, for most of…

Thank you, Tom, and good morning. I will begin today by giving you some detail about our contract backlog. At September 30, the value of the backlog was approximately $14 billion, about 72% of our days in the fourth quarter of book, and for 2011, we have about half of that days book. As well, it’s worth pointing out that the units we have under contract with Shell, on a suspension rate are not eating through the backlog since these contracts are extended day-to-day, so accounts for the suspension. Despite continuing global economic difficulties, the average WTI stock price for 2010, appears to end up well above the 2009 spot average of about $62 per barrel. And has recently exceeded $80. These robust prices have helped maintain a solid level of demand for both jack-ups and floaters, even in the face of issues in the U.S. Gulf. Outside the United States, jack-up utilization continues to hoover just under 80%. We are seeing some differentiation in the market with new units, and having utilization with around 96% while units that ended service before 2000, operating around 72%. Utilization for Noble jack-up fleet is better than average at around 77% for the third quarter and we continue to see opportunities to keep working our fleets. Let me expand on David’s comments on Mexico. Those of you who have been following the situation in Mexico already know that with current schedule of potential contract roll off, Pemex could be down to 14 or 15 jack ups by the end of the year if they don’t take action. That’s why we have seen a number of class-track tenders published recently. These tenders are designed to keep rigs all ready in country; working through the end of the year, and Noble is in a good…

Thank you, Roger. Regina, we’re ready to go ahead an open up for questions. I would however, remind everybody of our one question with one follow-up rule, so we can get to as many people as possible.

(Operator instructions) Your first question comes from the line of Collin Jerry with Raymond James. Collin Jerry – Raymond James: Hey, good morning, guys. I guess, let’s just focus in on the most relevant, the Gulf of Mexico. It looks like you’re hiring rigs based on details we know today in the [inaudible], looks like they’ve got a pretty good shot at full day rate in the Gulf of Mexico. I guess, just then give us your updated thoughts as it relates to the likelihood of not getting permits or some issues surrounding getting permits. Do you think that your customers are looking to maybe move those rigs around? Are they hoping to keep them in the Gulf of Mexico? Maybe just a little bit more detail on how the 2011 outlook looks relative to what you’re seeing on the lift in the moratorium.

Wow, first of all, the permits that we seen in deep water, there have been 12 permits issued since the moratorium started– all drilling permits. All those have been in shadow water. Although, they stepped up, I think there were four issued through the end of September, and I think eight have been issued since September 28, so at least in shallow water, drilling permits appear to be moving a little bit faster than they were early on. There have been no drilling permits as far as we know issued for, according to the website, none issued for deep water. It is likely that we’ll see some full-day rate time on many of our rigs. You know, the of course, the day in the Adkins we expect – we made this swap with Elon. Both the driller and the Thompson are undergoing shipyard programs for Shell. Our expectation is that they’ll have work when the ship yard protocols are finished. So there’s not a lot of other exposure here. We decided to stack the Bouzigard. The break- even time on stacking a rig temporary versus trying to hold it short crewed, is like six months. So we decided to go ahead and put that rig down and fight the battle on the other rigs. There’s nothing that says the Bouzigard is obsolete or anything else, we just decided the better part of battle was to push the other EDAs. We have valid bids outstanding for a number of these rigs outside; the rigs that we can move out, but we really only got a couple. So as far as we know, the operations we have here in the Gulf of Mexico are pursuing plans here. The fact that the judge overturned the second moratorium is an interesting factoid, I don’t know if it means anything. We don’t have any choice but to keep pursuing compliance with NTL5 because we don’t really have – they said it’s not – they struck that moratorium down. But we’re going to go ahead and be compliant, and act like we’re going to be compliant; we’re heading down that road. We don’t have any operations that we’re talking to that are actively with us, exploring taking any of our rigs out but we are actively pursuing opportunities for our rigs that don’t have contracts here in other markets. But it looks like most people we have contracts here with, or plans here with, they’re pursuing opportunities in the Gulf of Mexico. Collin Jerry – Raymond James: Okay, and then maybe just following up on that, as we look at 2011, if there is any perceived softness, are there major capital upgrades or a significant amount of capital you can put into some of your rigs that might have softness? Are you all looking into that to see are there any upgrade opportunities; I guess is what I’m asking?

Well, I mean, we will – we’re going through our budget process now. We’re not expecting – you know, there’s a lot of – there’s a huge portfolio of acreage in our customers hands in the Gulf of Mexico. And if you talk to most of our customers who are significant players here, they’re committed to the gulf, and they want to know what the rules are so they know what the playing field looks like, so they can move forward. I think the people that are in question, are the smaller customers, and it remains to be seen how they behave. Are there upgrade opportunities we could have to the extent that we have a long period of stack time on one of the EVAs, are there significant upgrades we could do? Probably, but I don’t actually expect we’re going to see that kind of down time in front of us. Collin Jerry – Raymond James: Okay, Lee, that’s my two. Thanks a bunch guys.

Our next question comes from the line of Ian McPherson with Simons & Co. Ian McPherson – Simons & Co. : David, I might stay on the same path there with my first question on the Gulf of Mexico, and just maybe try to ask it a little bit differently. When you look at the work that Marathon and Shell, and [inaudible] have, is there a visible duration of the work that the rigs are full and you know when and where that current permit coverage expires, or is it murkier than that?

Ian, I would tell you that we have – we’ve decided we really can’t give a lot of guidance about short-term programs in the Gulf, because it’s so dependent on the permit process. I will tell you that I believe where the operators have work, I believe that they believe that they can give work protocol approved it would be continuous. But whether or not their successful in that regard, is totally out of our hands. So we’re optimistic. I think clearly we’ll have with Danny Adkins working now, clearly we’ll have some up time on some other rigs in the fourth quarter, but exactly whether or not they’re able to get that done is totally in the hands of the government. Ian McPherson – Simons & Co. : Okay, fair enough.

I wish I could give you more clarity, I just can’t. Ian McPherson – Simons & Co. : I understand. Second question, maybe I’ll ask Roger. You mentioned, obliviously we’re all aware that there looks to be some upside to the ban out of Brazil next year, and I don’t know when we might see more specifics. When you expect to see things materialize in terms of tenders or direct negotiations for rigs, and how many rigs we may be contemplating for incremental demand next year?

Well, Ian, unfortunately that kind of fall within the same category as the first question to David. I think the speed in which Petraba commits to additional rigs is all about what happens within the election process. It’s well publicized that they’re out for up to 28 rigs. When you look at the inventory of wells that might have to be drilled in the subsalt discoveries that have already been logged, plus the additional subsalt field. You know, the number of ultimate rigs could be significantly higher than the 28. So it’s all about whether they proceed with the award for locally constructed rigs, and if they do so, and it’s delayed, it’s going to be several years before those years are available to drill. So in the meantime, there’s a view that Petraba will fill that gap with rigs from the existing fleet, or the nearly constructed fleets. So there’s two rigs per – no, six per quarter, coming on the market for the next two years. And if you look at the number of awards over the past quarter, it’s around six. So maybe surprisingly, the run rate right now, even in this awkward market, is about equal to the new supply, including those coming off contract, coming on to the market. So it really is just a story of what happens in Brazil over the next 12 months. Ian McPherson – Simons & Co. : Okay, thanks.

Your next question comes from the line of Robin Shoemaker with Citi. Robin Shoemaker – Citi: Thank you, I wanted to ask Roger, if you could give us your kind of broad, global outlook on the demand for more deep water units, and DP units, across your whole customer base.

Well Robin, that’s a really difficult question to answer, because I’m being a little bit facetious here, it would take quite a bit of time to walk through all the areas. I think in short, it comes back to the first question. The demand for units that are standard below all the deep-water units, is going to be a function of how quickly our customers, and in particular Brazil, take these ultra-deep water units off the market. And that will maybe tighten up the demand situation for the next year which would be some of these [inaudible] units. In the near-term, we do see prospects for our more units out of the Gulf of Mexico, it may take a while and I’m saying a quarter or two for some of these projects to materialize, but we are pursuing projects and we do have a view that these units will be employed. But it’s going to take the next year or two to work through this use supply and the ultra-deep water market, and that will in turn have an impact on utilization rates for the units. Robin Shoemaker – Citi: Right, okay. So this one follow-up then, with the recertification of the BOP in the Gulf, are there any additional rig modifications or upgrades that are currently to be enforced or perspective, and/or are the rigs with recertified BOPs actually ready to go to work without any further changes?

Robin, those rigs that are – the rigs with the certified BOPs are compliant with the rules, as the rules are today. So as the rules are issued today, there is nothing else that is required. Now there’s a lot of background noise, people are still talking about more sets of sheers, and you know, there’s lots of talk. But with the rules that have come out, the last rule to lease holders and the last rules that we’re trying to be compliant with, what we know now is third-party certification of the BOPs, and then there’s some safety protocol rules, basically it’s safety case that we’ve always operated our floaters in the Gulf of Mexico with the safety case environment so there’s really nothing for us to do in that regard. So the third part certification to BOPs will meet the current requirements to go to work in the gulf. Robin Okay, thank you.

Your next question comes from the line of Scott Grouper with Sanford Bernstein. Scott Grouper – Sanford Bernstein: Yes, good morning gentlemen. One of your competitors has been quite active in high grading their jack-up fleet recently by selling some low end rigs and buying high end rigs. We’ve also seen more high-end capacity be order by a few of your competitors. Do these moves compel you to more aggressively look to high grade your jack-up fleet? Is it time to look to sell some low end rigs in West Africa and in the Middle East? Or is the option value in those units, in a tight market still too valuable to divest?

Well, we like the jacket market, the fact that they’re making moves does not necessarily compel us to do anything. We do things because we see the market a certain way. We built three jack-ups in the [inaudible] which are higher speck I think than anything that’s been ordered in this last round, certainly higher than the Atwood rigs and I’m not sure about the Sea Drill rigs. But I think we’re higher speck in those as well. We like the high speck jack-up market; our worldwide jack-up fleet has been very heavily upgraded. We’ve taken most of those rigs to their technical limit, but they compete very well with where they are. Encos sold a couple of rigs, I think Diamond sold a new-build rig, I think different motivations for both of those guys. But would we be motivated to sell lower end rig for the right price? Sure. Would be interested at looking at new build jack-ups under the right circumstances? Sure. So we’re always looking at it, it’s something that we’re always studying and looking for opportunities. The three rigs we built, the Scott Marks, Hans Deul, and Roger Lewis, we like that design, we like the capability, we were able to slot those two rigs in, Scotty, which is a very high speck for a reasonable amount of capital investment. So we like that business. Scott Grouper – Sanford Bernstein: Okay, great. And also mentioned additional jack-up demand originating from Saudi. How many more of the real high speck jack-ups could Saudi absorb for deep-gas drilling?

You know, I think we are fairly certain there is more demand to build that. They have always done a great job in keeping additional demand close to the cup, and no pun intended on the cup design. I just have a view that you will probably see maybe some additional units by the end of mid-2011, we’ll probably see a tender for a few more units. Scott Grouper – Sanford Bernstein: Okay, is there any other countries right now that have a clear incremental demand for really high speck rigs, targeting deep gas flows? Are you going to identify?

Not to the specifications that [inaudible] requires, but you know, the new build jack-ups have seen utilization right about 90% And often that reflects the nature of the program. So I think it’s safe to say that we believe the demand for the higher speck units will continue up in the high level. Scott Grouper – Sanford Bernstein: Okay, great, I’ll turn it back.

Your next question comes from the line of Matt Conklin, with Wells Fargo Security. Matt Conklin – Wells Fargo Securities: Thanks guys. In the first question, I want to touch on that theme again. I understand that you like the high speck jack-up market, but do you like – which do you prefer, the investment opportunities now in building high speck jack-ups, or the opportunities to acquire speck build deep water rigs that are still in the ship yard, which do you think provides better opportunity in today’s market?

Matt, can I say both? We like the deep-water business, we probably sound a little more negative about the Gulf of Mexico just because it’s stoned so hard, but I’m actually very optimistic about the Gulf of Mexico. There’s such a heavy portfolio of acreage here, and some of the majors are heavily committed to the Gulf of Mexico. I don’t see anything that tells our floating fleet is obsolete, so I feel good about the deep water business. We would like to grow our footprint there, it’s one of the reasons we like the Frontier deal so well, is it – you know, the two bullies, plus the two Globetrotters, plus the DP Phoenix, which is basically rebuilt, so we like the deep-water capability that we’re building into the fleet, we think it adds a lot of long-term strength. But the jack-up business, we’ve been in the jack-up business a long time, and we like the high end of that as well. So we’re not trying to separate ourselves from the low end or the high end, we like both of those. We like the high-end floater business and we like the high-end jack-up business. So they’re different investment decisions, just because of the degree of risk that you’re taking, the amount of money that you’re investing, probably both are speck decisions at this point, but we like them both. And we’ve got the strength to do them both, we think. Matt Conklin – Wells Fargo Securities: Okay, great. And just to expand on the Gulf of Mexico, this moratorium is taking six, maybe it will extend to 12 or whatever months away from deep-water lease holders to drill up their properties. Is there any word that you’ve heard about leases being extended to adjust for the moratorium, or might we have some sort of a rush to drill if we need to do five years of drilling in four years?

I have no heard of – or anybody here sitting around the table. We have not heard anything that leads us to believe that the government has extended leases for leaseholders. And I would – if anybody in the government is listening, I would encourage them not to do that. So we have not heard that, and with the portfolio, I think there very well could be once the government gets their permit process to a point where they can actually deliver the product, and everybody understand what the rules are, I think there very well could be a run in the Gulf of Mexico. I know that there are at least a couple of companies that we’re aware of who are examining opportunities to maybe source rigs because they think the Gulf of Mexico is not going to have enough drilling rig capacity to be able to meet the demand once the process is in place. They’re looking for rigs around the world that may be able to run back in here because they think they’ll lose a year of drilling. So that is a probably outcome. It’s not one that we talk about a lot because it’s – there’s been so much negativity in the market. There’s certainly that discussion going around in back offices. Matt Conklin – Wells Fargo Securities: Okay great. That’s my two, so I’ll turn it back over. Thank you.

Your next question comes from the line of Dan Boyd with Goldman Sachs Dan Boyd – Goldman Sachs : Thanks, guys. David, or maybe even Lee, there seems to be a lot of question they’re confusing out there with regards to downtime for Noble, how much is coming from operational issues versus new or general market weakness. It would be great if you could give us an update on maybe what percentage then of the 4,200 down days for this year are related to operations, how this compares to what you were budgeting or expecting at the beginning of the year. And then maybe some reasonable expectations for next year, purely from an operational standpoint and we’ll make our own judgements, obviously, on the market weakness or strength.

All right, Dan, you hit right in Lee’s whole. He’s digging around for a piece of paper right now that explains exactly that. You know, we’ve had some unexpected down time, you know, downtime is bad. We don’t like it. And we’ve had some downtime in Brazil in the ships, primarly engines, plus the need for the reliability upgrades. A lot of the other downtime has been stack time. I think Lee’s got some more data. Lee?

Yeah, Dan, if I could answer that not necessarily for the year, but I know there was a large gap between our July fleet status and our September fleet status. So let me talk about kind of the 1,100 days difference that showed up between the two fleet status and break that down. I do think there has been a little bit of confusion around what should be the fleet status downtime versus what may be categorized in other ways. Out of that 1,100 or so days, there were about 330 days of stack time. Those were on rigs like The Favor, the Walker the Charles Copland, rigs that previously had been stacked on the fleet status report and I think the market has known that they’ve been stacked. And the we added the Paul Ramono, which the market, of course new came off contract in the middle of June and we haven’t found a job for that. So that have already been stacked and not really operationally down. We had about 220 days worth of rigs that were leased from contract and those were a couple of rigs in Mexico, one rig in the North Sea, one in West Africa. So again, not operational downtime, just available time. We announced the Roger Lewis was going to Armaco and because of that, because of the contract prep, there’s another 130 days or so of preparation time in the shipyard. The Bouzigard was down for about 170 days and that’s directly related to the moratorium and BOC certification. The Frontier rigs which were in the original July 7th Fleet status report accounted for about 50 days. And so when you kind of add everything else up, there were about 290 or so days of operational downtime. So I think there are – and we have this argument all the time internally, but I think in this particular case, the fleet status and how we’ve classified things, we’re just putting numbers out there, has caused people just to jump to the total and look at the difference between this fleet status and the last fleet status and say, well, look the downtime increased 80 percent. That’s not actually I think an accurate classification of the causes. I can’t give you downtime next year – for next year. We’re still going through the budgeting process. As always, we’ll have a number of surveys that we’ll want to do and we’ll roll out what we think the planned downtime is on the January call. But I would just ask folks to go through the status report

Ladies and Gentleman, thank you very much for joining us today. We apologize for not getting to those of you who were still in the queue. We will certainly be around for the rest of the day and tomorrow to answer any follow-up questions you might have. We will be back in January for our full-year 2010 Earnings Conference Call and you’ll probably look forward to seeing some guidance from us at that point. Thank you very much and have a good day.

Ladies and Gentleman, this concludes today’s conference. Thank you for participating and you may now disconnect.