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 Corp second quarter 2011 earnings call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer period. (Operator Instructions). As a reminder, ladies and gentlemen, this conference is being recorded today, Thursday, July 21st, 2011. Thank you. I would now like to introduce Mr. Jeff Chastain, Vice President of Investor Relations. Mr. Chastain, you may begin your conference.

Thank you, Regina. Good morning and welcome to Noble Corp’s second quarter 2011 conference call for earnings. A copy of the company’s earnings report issued last evening along with supporting statements and schedules can be found on the Noble website at www.noblecorp.com. Before we begin, this morning 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 the drilling business, financial performance, operating results, tax rates, spending guidance, backlog, dayrates, contract tenders, extensions or commencements, letters of intent, the outlook for the US Gulf of Mexico and other regions, new bill delivery costs and dates, plans and objectives of management for future operations, and the outcome of any litigation, dispute or investigation are all forward-looking statements and are subject to risks and uncertainties. Our filings with the US 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 those forward-looking statements. Also please note that we may use non-GAAP financial measures in the call today. If we do, you will find the required supplemental disclosure for these measures, including the most directly comparable GAAP measure and an associated reconciliation on the Noble website. With that, I’ll now turn the call over to David Williams, Chairman, President and Chief Executive of Noble.

Hi, thanks Jeff. Good morning and thanks for joining us today. With me in Geneva are Tom Mitchell, Senior Vice President and Chief Financial Officer and Roger Hunt, our Senior Vice President of Worldwide Contracts and Marketing. As you heard from the forward-looking statement, we are joined today by Jeff Chastain, our new Vice President of Investor Relations and we’re delighted to have a player of Jeff’s caliber and experience join the Noble team. He brings with him a wealth of experience and knowledge and we are certain that we all will benefit from his expertise. So Jeff, thanks for coming and welcome to the fight. In this case, we had to oversee the re-manufacturer and installation of a new flange at an appropriate on-shore facility before the slip joint could be reconstructed and redeployed offshore. Downtime in the Noble Dave Beard was a result of two separate rise or leakage issues involving faulty coatings and worn out rig seals. Most of these failures were equipment related to manufacturing and we have had numerous discussions at all levels with the executives and staff of these organizations. Unfortunately even though these events significantly reduced our revenue, our recourse is very limited. The good news is that these are separate, unrelated events that we have remedied and are not symptomatic of unknown or unsolvable issues. That said, giving the complexity of new kit and recognizing the inevitable change in a post-Macando world, I think it is likely the industry will begin to experience a decline in tolerance for even the most benign subsea issues, even on equipment that may have multiple layers of redundancy. The result is likely to be more extra downtime in the future worldwide. In some cases the cost of that downtime may be borne by the operator and…

Thank you, David and good morning to everyone. I plan to cover some specific details on the quarter, including some insights regarding contract drilling service revenues and costs and I’ll close with updated guidance for the third quarter and full-year 2011. Noble recorded net income of $54 million or $0.21 per diluted share on total revenues of $628 million for the second quarter of 2011. Earnings for the second quarter matched those for the first quarter of 2011. Results for the second quarter included a tax benefit of $9 million or $0.04 per diluted share while the first quarter results included a one-time after tax net gain of $0.06 per diluted share resulting from the swap of the drillship Noble Phoenix for the drillship Noble Muravlenko in Brazil. Highlights from the second quarter included a $47 million increase in contract drilling service revenues to $590 million that's up 9% compared to the first quarter of 2011. The revenue improvement was driven by 592 day increase in operating days to rigs return to work adding in excess of $85 million in additional revenues. Rigs contributing to the additional revenues included the Noble Homer Ferrington which is now operating under farmout agreement in the Eastern Med. The Noble Clyde Boudreaux which began a one year assignment in Brazil. The fix jackups returning to active status in Mexico, the Noble Jim Day although at a reduced dayrate for the full quarter in the U.S. Gulf of Mexico. Shipyard programs on several jackups were also completed including the Noble Julie Robertson in the North Sea, the Noble Roger Lewis and the Nobel David Tinsley in the Middle East. The increase in operating days in the second quarter resulted in a very nice improvement at average fleet utilization which rose to 70% among the in-service…

Thank you, Tom and good morning. Following the review of the company’s backlog statistics I will make some brief comments on the opportunities and challenges we see developing in our areas of operation. At the conclusion of the second quarter, backlog stood at approximately $15 billion, essentially unchanged from the backlog at the end of the first quarter. Our floating rates accounted for approximately $11.4 billion of the backlog while jackups made 1.6. Our backlog [extends in 2023] and represents visible revenues on ore around 1.5 to 2 billion per year through 2015. Prospects for backlog growth are improving as we evaluate the remaining half of 2011. We continue to witness improving conditions around the globe for floating rigs, especially deep water rigs and jackups with utilization and day rate improvements more apparent than was visible early in the year and in the deep order sector there are several indicators that customer demand is building. First, in the Gulf of Mexico, customers have been successful in receiving permits that allows for continuation of drilling in the region. The issuance of permits in the Gulf is a critical component of global supply and demand for rigs. The region represents a world class hydrocarbon play and we believe customers in the Gulf both large and small are gaining a little more confidence with a review of the award process. Having said that the process is complex and we realize that many customers made delayed recommitments until a predictable and reliable permitting process exists. In the mean time we believe that attractive current prospects continue to build creating a level of pent-up demand. Additionally, given the departure of quality rigs from the region and the possibility of further departures some of our customers have begun to express concern over the ability to secure…

Okay. We’re now ready to begin the question-and-answer segment of the call. While you’re assembling the queue, I’ll remind everyone that please follow a one question and one follow-up so that we can get to as many questions as possible in the time remaining.

(Operator Instructions). Your first question comes from the line of Arun Jayaram with Credit Suisse. Arun Jayaram – Credit Suisse: David, or Rogers, I wonder if you could give us a sense of what you’re seeing from Petrobras, we are seeing them at least with what it appears reducing backlog and some of the mid-water rigs and assignments elsewhere at some of the deepwater units. I just want to get the sense of what you’re seeing in terms of mid-water demand and the follow-up would be, would you or how aggressive you’re looking to bid into this tender that is coming up on the moored side?

Let me address the first part of that Arun. You know given Petrobras’s long-term plans where they have such a massive resource in terms of subsalt and I think only 30% right now in effective play being addressed and a lot of that’s got to do with the additional 21 rigs they planning on tendering or are tendering for a local construction. I think that the nature conclusion of that is Petrobras is going to looking for a very high level of specification to address subsalt. Having said all that they still have a lot of activity and demand to prosecute in the non-subsalt work. So I think the current tender for the moored units kind of addresses that and our expectation would be that you might see more of that from Petrobras. We think, we will well-positioned given that the EVA class is moored semi pretty well matches up to that specification. Arun Jayaram – Credit Suisse: And rather than look in to use the moored rigs in the subsalt I guess using some preset mooring systems?

Now, I believe its kind of address the non-subsalt work. Arun Jayaram – Credit Suisse: Okay. And my one follow up question is you guys could you give us an update on the shipyard programs on the [Sagaris] as well as Roger Eason?

Yeah, I think that’s especially your third follow up. We’ll let you to get away with it The Eason and the Sagaris are both on tracks since the last week status. There is one well, the derricks there on the Sagaris projects are signed, the construction of apt module in Singapore on the Eason, everything has gone well. So last week status updated the current expectation modes and there is nothing changed there. Everything is going to quality work that we already did on the [Sagaris] is some of the best work we ever seen and so we’re very pleased with those projects right now.

Your next question comes from the line of Ian Macpherson with Simmons.

I will ask both of my questions upfront. The first one, Roger, you mentioned 20 tenders from jackups from Pemex, 46 potential rig years under a realistic case of what you think they might say, can you project what you think the jackup rate count could do over the next few quarter for the next year in Mexico and also comment about the possibility of breaking through this dayrate sealing that they have been successful in imposing so far. That’s the first question. The second question, David you mentioned that your secured options are still, you consider them to be very attractively priced relative to leading edge, new build costs and I wonder if you could give us some more description around that delta and your thoughts on what you do with your options this year?

To the question about how much success is Pemex is going to have against this 20 rig requirement and what the ultimate rig count might be in Mexico. I think a lot of it does have to do with what Pemex does in some of their current contract standards and these rate caps. All 20 of those bids, for your information do have a rate cap on it. I believe that something like 60, 80, 83 to a 100 for the 250, 300, 350 respectively and there is one in there at for a 350 close to 1000 jackup at a 124. On the last two bids for 350 foot rigs effectively against our incumbent rigs, we can share with you so we chose not to bid. And I might expect that others will take the same position. So I am not sure how long in this kind of a market that the rate cap will survive. There are other conditions in terms of very tight delivery windows and severe penalties for being late or termination right. And just for relatively high cost of doing business in that part of the world, from a contract administration and penalty perspective. All of that is going to make it a little difficult for Pemex to prosecute. Our current rig count is around 24. It is good news, it is up from 14 from six months ago. We hit the numbers anywhere from up to as many as 40 additional rigs over the next period, 3, 12 to 18 months. So I think a lot of this is going to be function of whether this contract is willing to accept the terms and my guess there are going to have to make some changes.

On the options on the additional liability and you are correct, we have one ship option that remains, we initially contracted those to initial rigs 605, we accelerated our number three ship and priced it to 615, so we have one remaining option there and that option is due August 31st. It is a little bit above the third option, but still we think based on the specification of that haul, we think that it is very, very well price based on if we went to yard today, both from an equipment perspective and from an FX perspective we think we are in good shape. On the jackups, we have the first two committed at 220, the second two committed at 235. We have options that go out till the end of the year that as you know are indexed and so we are updating that index regularly, so we have kind of an everyday view of what we think the current pricing is. I will tell you that just anecdotally what the yard indicated, had we built those rigs, at the peak of the last new build cycle say two years ago, two and half years ago, in 2008. Those probably would have been shipyard priced at around 280. So we think we are still well in the range of what a good price of those rigs will be on a relative basis and given where we see the market for those rigs, we think we are very well priced currently on those. But again those options aren’t due till the end of the year. We will have a discussion with our Board at the next Board meeting and we will table the drill ship option in earnest and we will have a good lively discussion about how we feel about the jackups and then we will let you know. But we do have those options and frankly we think that (inaudible) does for the fleet I think we will be very well positioned.

Your next question comes from the line of Jeff (inaudible) with Needham & Company.

If I could get a freebie from Tom, the other income expense turned negative in the quarter. What was that?

We had, Jeff, we had a minor swing in some FX in that line. That’s where our transaction adjustment and as you know, there has been weakening of the dollar and that’s what it was, nothing major.

Okay, and nothing to forecast.

No, no.

On the subject of questions, you were saying to be fairly optimistic about the continuation of permits coming out in the Gulf of Mexico and Halliburton earlier in the week, say that they saw the possibility that rigs could get held up because of the lack of permits. Do you see any risk that rigs will go idle because permits aren’t available on time?

Yeah, I think there's always a risk. I mean we've cleared, the moratorium has been open over almost a year and we've seen rigs go idle, but not so much in deep water, but in shallow water. So yeah I think there's a risk, I think the benefit for us is who our sponsor is. You know we now have Danny Adkins and Jim Thompson all working for Shell. We are wondering (inaudible) has done a great job keeping rig busy and then we think the driller hopefully is going to get its permit fairly soon and it appears to us the (inaudible) that we’ve engaged in will be able to maintain some continuity. I think a well to well program is a little more challenged, but for us we believe there's going to be continuity out there for us and how it works for other people, not sure. And for Shell it would be a much better resource of information than we would but that's what it looks like to us. There is a growing confidence in the process, there is now a lot of evidence and you don't see it in terms of how much rolling out of the door, but there is starting to develop this kind of underlying current, we did get the wells drilled when Roger spoke about the Gulf of Mexico and opportunities there, there is a growing wave of excitement from operators on how are they going to get the work done and so there's a god bit of dialogue going on and there's confidence building. So the Gulf of Mexico is getting better all the time.

Okay and if I could ask you David about your comments around the downtime in the quarter, it was not quite clear to me whether you are suggesting the extra downtime was a result of greater scrutiny coming out of post-Macondo world or whether the issues that the company had during the second quarter would have resulted in downtime regardless of any change in regulation.

The issue, those are two separate ideas that I am glad you brought it out for we could clarify it. The issues we had were technical issues and largely manufacturing based issue. Those would have manifested themselves in any event.

Okay.

We would have had to trip the sack a couple of times on the Adkins under the circumstances, we replaced the bottles, with spare bottle had to trip it again to replace it with a later design that we had been informed was out there. For that particular piece of equipments, the flange on the slip joints wasn’t made up, it was just a manufacturing follow up. So those are not part of a post-Macondo world. The commentary on the post-Macondo world is I think is just notionally to give you guys guidance that as the rules and as the tolerance or and not only, keep in mind that BOP stack has multiple control functions and have built-in redundancy. In the past we would have continued to operate based on the capability of the redundancy circuitry and we would have continued to operate in many environments and many circumstances that in the future we may not be. And so I’m just cautioning you and whether other contractors do or don’t, I’m just cautioning you that as we move through the next and I’ve said months and years ahead as we more clearly define what the rules and expectations are, I think it’s reasonable to assume that we as an industry are going to have more data. Again, that’s the operator is going to bear some of that and we will bear some of it. The ultimate saddle for this is going to ride on the backs of the consumer because ultimately this is going to cost more to drill these wells. That’s what I’m saying.

You next question comes from the line of Scott Gruber with Bernstein. Scott Gruber - Sanford Bernstein & Co.: Well I understand that (inaudible) was included in – I understand comments around lower tolerance for subsea equipment failures in the resulting greater down time. I am also wondering whether there is an element of just increased down time due to more extensive reviews of the subsea equipment on a preventative basis to try to avoid the failures that can be an element that plays a part of the increased down time as well?

I think it could be, you know as we move to this you know we’re in the infancy of this. These rules we’ve been dealing it for a while exactly how it works from well-to-well and how extensive preventative maintenance protocol become. I think overtime those to get more heavily weight you know I also think as we move through cycle for these -- you know the BOP’s had to be recertified you know every five years, those may call it ways but we are way early in this process. We have some guidelines and this equipment is made to run, we’re just not getting back out there and let it run. Again, our down time wasn’t specifically related to any count of regulatory issues, I think we will fix these things anyway. But we are just trying to give you a flavor or at least a notion that as – this is very high spec, high tech stuff and the level of scrutiny that is going to be paid to it in operation and for the control of all wells is because of the events that we went through last summer and I think its prudent to assume that we are getting for more, that’s the point. Scott Gruber - Sanford Bernstein & Co.: That makes sense. And then another related follow-up, coming back to [pent-up] demand for incremental jackups and the wealth of outstanding tenders from them. Have we seen any relaxation of the short notification, termination clauses that annexed often appropriate in their contracts in order for them to try to incentivize greater participation, have we seen any relaxation?

The quick answer is, none. And just as recently as a week ago, they had a series of meetings with their contractors and understood the need to make changes, but we haven’t seen any yet.

Your next question comes from the line of Brian Uhlmer with Global Hunter Securities.

That’s wonderful. I want to follow-up on how you look at the future dots on this, and a follow up on the last subject and how we can look at modeling that and how you evaluate the cost of that downtime and the cost of any type of refurbishments or upgrades or changes to equipment for some of the older fleet if you think that may lead to attrition of rigs over the long haul and what’s your view as on kind of the total supply, addressable supply as we go out two, three, four years as we kind of newbuilds of fleet what happens to some of that equipment?

We’re having a shade malfunction in the room. If you can hear background noise I apologize for that. I think we are making a whole lot of this. We are just trying to guide you to the notion that in the future we think the industry is going to see more downturn. That’s the purpose of this. How we would model it, we don’t have enough data yet and enough experience operating in this regime to be able to predict it so how you model it is you know, we are entering our budget process now and this is a conversation we are having internally in terms of how we are going to budget and how we intend to model it, I cant give you any guidance on how we should do it. I hope we that don’t see this; I hope that we get a good enough handle on the preventative of this that we don’t have additional downtime, but I think its prudent to assume that we will and exactly how it manifest itself and how it looks; we just don’t have enough, there is just not enough days in good hard operation of the rigs, we have to predict that. In terms of attrition, no I don’t think this has anything to do. I don’t think this will lead to attrition, its just – you know in the past when you have an A plus and a B plus and a blue pod and A plus and AB plus on yellow pod you get so much redundancy built into a subsea system and if you’ve got a red light on one bus, on one function on one side of a non-executable function you keep drilling. If its open function on the blue pod on a third set of rams and you don’t have that size of pipe in the hole, you just keep going. If it’s a critical function like unlatching or closing sheer rims of course you deal with it. But we don’t know what tolerance there is going to be from the new regulatory authorities going forward. That's the only point. So let’s don’t make this more complicated. We’re just trying to guide you as an industry we think its going to be more complicated going forward that’s all.

And I’ll just add another one to what David has pointed out is that another piece of this is discussions with our customers. As we learn more about this, I think there has to be willingness by our customers to risk share which means that the traditional allocations or allotments for downtime are likely to change. And I can’t share with you any conversations that we’re having with customers in the Gulf of Mexico today, about projects starting out here on out including conversations about changing the downtime provisions.

Okay, I guess somewhat related to that, you know, as we look at specs of rigs going forward, do you guys, over the next three to seven years there has been a lot talk about the bifurcation of the fleet that we will have a large amount of exploration in the floaters or that most of the rigs are upgradeable to the higher end specs that the guys are saying for bids and that we will absorb all new capacity and mostly existing stuff will still configure to work?

There is nothing in the rules that makes the current suite of rigs technically obsolete. So you know that depends on the strength of the market. You know, one of the things you see as you continue to build rigs, one of the things we see specifically having more so on the jackups, is the delta between the low spec and the high spec is getting much wider than it was in the past. That’s one of the reason, we are still excited about the JU 3000 in jackups is because the delta between even some of the newbuild rigs that are not high spec, delta between those rigs and our rigs is dramatic. On the floaters, the delta is dramatic and it has been for a while, but there is nothing that comes out of Macondo that makes floaters technically obsolete. So our view is clearly there is going to be enough demand to absorb the newbuild capacity that’s coming in and the options, I don’t see that that’s a real issue going forward. The macroeconomic view of the deepwater business is very, very strong going forward and so we don’t have a lot of concern about that. Could you force some lower end rigs out of the bottom, yeah you might. The good news for us is I don’t see those rigs really coming out of our fleet. So you know it kind of depends on how the market flow but there is nothing out there from a technical perspective that makes any of these rigs that are currently operating in the world, anything out of Macondo that makes them [potentially] obsolete, that you can…

I wasn't meaning Macondo, I was more meaning just the increase in specs of the requirements of offshore drilling?

Well, the operators always want the high spec that they willing to pay for, there are some wells where you have to have higher spec and there is some that are just making more efficient and you can price the efficiencies or the inefficiencies of a higher spec rig converse the other if you could technically get to some of the wells that operators are trying to drill right now you can't technically get there with all the rigs. So it just kind of depends on what rigs are in the highest and best use and if there is enough market capacity to absorb all the rigs. And our view right now is we are headed into a period where yes there is going to be enough market support to accommodate the floating fleet that we have in the world today.

Your next question comes from the line of Robin Shoemaker with Citi.

Thank you. Good morning. Interesting discussion about this new normal with regard to rig downtime, I was interested in Roger’s comment about perhaps changing the provisions of the contract. I assume that would be on newly negotiated contracts where you might get a little more mechanical downtime allowance per month than you do today. So is that, is today is typically like 24 or 48 hours of mechanical downtime before you go off rate, is that kind of what the historical pattern has been?

If you look back over the last couple of years Robin, you would say yes, on subsea downtime you may get a free 24 to 48 hours and then you go on to some lesser rates which in some cases could be zero. I think your question is around obviously with new jobs there is going to be discussion around contract risks, that's not to say that they won't be or the similar discussions with our incumbent customers because they too realize there has to be a fair allocation of risk if they’re going to be able to prosecute. So it’s most with incumbent customer than new customers.

Yes, okay that was what I was getting to because you know I assume that like this 10-year contract would show you’ve already negotiated those contracts and you would go back to perhaps make some amendments or do those kind of provisions. But my question had to do with the regulatory environment that you referred to of course has been tightened up for the Gulf, but my understanding is outside of the Gulf, it’s really the operator who wants to -- apart from whatever local regulations might exists, wants to apply a much more stringent standard to BOP safety and all the other issues we’re talking about as opposed this being really a government-regulation driven issue. Is that correct or are regulatory agencies are all over really tightening up?

Well, so far it’s correct. I will see I think there’s a lot of people around sitting to see, there’s a lot of regulatory authority around the world sitting around and waiting to see I was you know, say gap. Most active deepwater market, most active flow to markets would probably we got all regulators in the room would probably say that they have the rules that they think are appropriate. So I don’t know that from a range or perspective, what it’s going to be, but I think you’re going to see operators as you correctly say you say, point to standard that we’re going to meet this kind of world. We’re going to apply some standards around the world. Interestingly, we may have seen the BP, New Gulf of Mexico standard, as I read that they’re willing to apply that in the Gulf of Mexico. So it’s going to be applied differently, its different license. Exactly how it works, again is why we were cautioning you and why we are saying it, but its again its going to take months and year to be able to define it and even [black wells], I’ll say again, I hope it doesn’t happen. I hope that they were able to keep up that and hope that the restrictions are appropriate and will be able to cover or risk by contract and we’ll see.

Your next question comes from the line of Jud Bailey with Jefferies and Company.

Question on follow-up on Rogers comment on the deepwater market. Sounds like the ultra deepwater market is tightening and you’re starting to hold this stuff a lot of these more in deep water rigs. Can you give us a little more color Roger on kind of where you seeing demand outside of the Gulf and then are you seeing term opportunities or there is more I am still kind of well-to-well type opportunities?

Yes, Jud. You are asking to ultra deepwater or…?

On deepwater like your EVA rigs.

Okay. The EVA rig. Yes, the discussion in the Gulf of Mexico which in or itself is very interesting and just make a side-by comment there on issue of permitting. An operator has to make his permanent rigs specific, so there is a chicken and egg issue here where he has the customer of kind of concerned about the process but actually with the process they have to in some cases make a rig commitment. So that is an element of what we are seeing right now and that is directing some attention to our EVA’s. When you take a look around to see what rigs have left the Gulf of Mexico under the past 10 to 12 month you know there is realization if a customer wants to draw up a program here till late 2011 or 2012 they better move smartly. So Gulf of Mexico is an interesting area we will also be looking at Mediterranean, West Africa and Brazil.

Okay. And then we saw this morning, we saw a fixture for a 5000 moored rig in the 320 range. Um, is that a reasonable expectation for your first similar class assets for yourself, is that a good indication of the market these days?

I will pass on that one Jud.

Okay, alright. Thanks.

We are embroiled in discussions and so it’s not appropriate to comment on that.

Okay, alright. And we will then now just follow up on the jackup market, you talked about the North Sea and rigs are showing some upsides. It sounds like, can you give a little more color may be what market you are seeing the most strength in outside of the North Sea and Mexico perhaps.

North Sea is an interesting place. We are being able to get rigs about 100. We were both, you know, well into in the early parts of 2012 but on other hand we also like the fact that we have got quite a bit of availability in entering 2012. So, no reason to think that story will not continue. Yes, there are rigs that can handle the North Sea but not a lot of movement in that direction. Mexico was spoken about. I think the story in Saudi is still unfolding. Probably as recently as about 12 months ago there were 20 jackups, plus or minus. Now we count that as probably around 30 of Aramco contracted. So they have had a 30% increase in the 12 months period. They are into market again. You know, the last time they did 10 and took 16. So Aramco is still quite active and there are some other small operators in the Gulf area that are trying to respond to commodity crisis and drill short-term programs. We are up to 90% in the Middle East and we would hope to keep it at that level. South East Asia behaved nicely but it has been stable. The newer rigs seem to be continuing to earn around though the 130 range. And West Africa I guess it has been may be a bit of sneaky uptick of over the past period you have seen a couple of rigs moving into the sector and as mentioned in the prepared remarks the prices have been at a 100 or better and I think you will continue to see a little more active there.

Our next question comes from the line of Jeff Tillery of Tudor, Pickering, Holt.

I just wanted to know about Paul Romano I just want to get a little color around the time tables that you guys are looking at if the Paul Romano going back to work and if the trend would continue, should we think about kind of the past five months of this year those rigs generally being idle?

Its kind of a stinker, it’s close to the other question about pricing but I can share with you that we are engaged in current conversations. I expect those to come to a head probably in the next couple of weeks and so the actual deployment would be a function of the mobilization. So with a little bit of luck there we may see those against contract certainly in 2011.

Thank you, Roger, and just last question. As mentioned early in the call, all that additional adds to the jackup exposure at the high-end, you guys clearly have options to do that organically. Just wanted to get new color on how you see the opportunities do that in the acquisition market as well.

There are some acquisitions out there. You know there are some rigs out there for sale, for what we see, for what it cost to go to the market, buy. We are building better rigs for not much more than what you go buy them for r so. So, not to say that we wouldn’t continue to look at them. We look at everything as we look at it hard and for ask on those rigs is what we are expecting to ship. We like our new build program. We think we are building very high, very high spec and very high performing rigs. The Bullys, both Bullys in the golden triangle all will be on the payroll this year, earning rates like what we are doing in the Gulf of Mexico. We like where the company sits right now. We like where we are headed. So, we have those rigs out there but I think we are building from the key left is much better than what you are going to see out in the open market. So, right now we will keep looking, we’ll play these.

Great, thanks.

The company is situated very well right now, I think, with, you know last quarter was a tough quarter where we are running very well right now. We got most of the rigs back up on the payroll. The days on the payroll, the Gulf of Mexico, is in a good place. Brazil’s is in a good place. There is a lot of tender activity; we are in a very good spot right now, going forward.

The next question comes from the line of Mike Urban with Deutsche Bank. Mike Urban – Deutsche Bank: Thanks good morning. Alright, good afternoon nearly, I guess. You talked a little about the exploration success that we have seen out there and that has been pretty impressive. There a lots of frontier areas opening up via the equatorial margin on both side of the Atlantic, East Africa, Deepwater gas and some others what would you say to you from the perspective of offshore drillers that most interesting, exciting of those areas and I guess a follow-up would be you know maybe the same answer where might you see the soonest or nearest term opportunity?

That's a great question and I would say all of them. The beauty of what's happening in the market right now is it’s not a singular part spot around the world, I mean we are seeing, where Roger’s talked a good bit about the North Sea jackup demand, the Middle East jackup demand, the Mexico proper demand you know those are some of the biggest markets in West Africa as well, so those are some of the primary jackup markets around the world. The same is true of the floater market. You talked about this, the new emerging markets, that is ongoing and contingent and it looks like more work possibly in the Black Sea, demand, Brazil rigs out in the Gulf of Mexico, we think Mexico is a potential deepwater market, there's going to be more work in Southeast Asia so there's no one market that I think is more interesting than others, they are all excited right now. Clearly Petrobras and what they do is meaningful for us, likewise what happens in the Gulf of Mexico is meaningful for us, but those things all are additive to what we see as a very, very exciting market going forward. We think it’s a sellers market going forward and so we are excited about our rate prospects, we are excited about the way we can contract their assets and we are excited about where the market is for us. So again we think we are in great shape and Roger do you have anything to add to that?

Yeah, thanks David. The only other comment I would make Mike is you know we like our position in the Arctic. We have one vessel that is unique to being able to work in the Chukchi Sea. We are working with Shell to operate the second vessel in the Beaufort Sea. So when you know Shell get the permit and we can prosecute the drilling program, we really like to flag that we have a heavy presence in the Arctic. Mike Urban – Deutsche Bank: And just following up on the kind of on the Arctic, would that be similar where you would looked at assets or you know potentially build a maybe Arctic class floater or drill ship?

, :

Your next question comes from the line of Roger Read with Morgan Keegan.

I guess may be getting some of the comments you had at the very beginning Dave about you know by 2014 ever real high spec fleet but then obviously we have some of the units that are older then may be you don’t want anymore. How far along in the process are you of identifying may be you know what that 2014 fleet would look like in an optimal situation in terms of which rigs you would like to sell what the impact of that would be in terms of may be asset write-offs or anything like that, just may be where we are in that process?

I would look for asset write-offs and when I’m talking about the high-spec fleet, I was talking specifically about the floater fleet, but I’ll take the opportunity to address the broader fleet. Just on the floater side there’s very few rigs, a few but not very many that we think are kind of lower into the fleet chain. But we’ve added so many at the top, if we exercise our option on our next ship we’ll have 28 floaters, 16 of those are going to be DP, so that will be a very high performing, high returned generating suite of assets we believe. So, its hard to imagine how far we brought this fleet in a very short time from 12 motors 4 DP rigs just a few years ago what we are headed to now. So we have done a good job on that side with it will be a very high spec. On the Jack up side, we talked in the past about what we are looking at from the Jack up fleet, we are still looking at, we are still evaluating processes to see with the best to way to if we decided to best to some with the best way to do. The challenge for us is Roger (inaudible) to put the rigs to work and our utilization its get so high that they just complicate processes. It creates customer issues and employee issues, other issues. So, if that process ongoing its it is, its you know which we give you more color we are still working on it we are still trying to identified the best that’s way to do it. We don’t have anything to definitive to tell you yet but the process is ongoing. In the mean time with what we have is already we look forward and with our great performance and utilization run around it, it’s helping us out in the mean time. So mostly look like 2014 I am not sure yet I can tell you that will be higher spec, higher performing fleet we have right now exactly how many jack ups we have I am not sure.

While including rigs to work a certainly a high class from to have there?

It is a very class problem there. Okay. With that I would like to thank everyone for your participation on day calling your interest in Noble. Please make a note that Noble referred a Third quarter 2011 result is scheduled for October 19 with the call to follow to morning of October to 20th and will confirm those days and the details later in the quarter. Regina, thank you for coordinating in the call. Good day everyone.

Ladies and gentleman this does conclude today’s conference. Thank you well for participating and you may now disconnect.