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Executives

David Williams – Chairman, President and Chief Executive

Dennis Lubojacky – Vice President and Controller

Roger Hunt – Senior Vice President Marketing and Contracts

Jeff Chastain – Vice President Investor Relations

Analysts

Kurt Hallead – RBC Capital Markets

Dave Wilson – Howard Weil

Judson Bailey – Jefferies and Company

Ian Macpherson – Simmons

Robin Shoemaker – Citigroup

Joe Hill – Tudor, Pickering & Holt

Geoff Kieburtz – Weeden & Co.

Scott Gruber – Bernstein

Mike Urban – Deutsche Bank

Noble Corporation (NE) Q3 2011 Earnings Call October 20, 2011 9:00 AM ET

Operator

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. Q3 2011 earnings call. (Operator instructions.) As a reminder, ladies and gentlemen, this conference is being recorded today, Thursday, October 20th, 2011. Thank you.

I would now like to introduce Mr. Jeff Chastain, Vice President of Investor Relations. Mr. Chastain, you may begin your conference.

Jeff Chastain

Thank you, Regina, and welcome all to the Noble Corporation’s Q3 2011 earnings call. A copy of the company’s earnings report issued last evening along with supporting statements and schedules can be found on the Noble website, and that’s at www.noblecorp.com.

Before we begin this morning I’d like to remind you once again that any statements we make 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, day rates, contract tenders, extensions or announcements; letters of intent, the outlook for the US Gulf of Mexico and other regions; new build 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 our 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.

Also note that we may use non-GAAP financial measures on 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 our website. I’ll now turn the call over to David Williams, Chairman, President and Chief Executive of Noble.

David Williams

Thanks, Jeff. Good morning and thank you for joining us on the call today. With me in addition to Jeff are Dennis Lubojacky, our Vice President and Controller; and Roger Hunt, our Senior Vice President of Marketing and Contracts is in Geneva with us today. Dennis is stepping in for Tom Mitchell who, as we previously announced, has left the company and that was effective October 10th to pursue another opportunity. Our search for Tom’s replacement is well underway and we hope to have his successor identified by the end of the year.

I’ll begin today with some brief comments on our Q3 results which were significantly better than Q2 and update you on our ongoing fleet transformation efforts. I’ll then ask Dennis to cover the detailed financial highlights for the quarter and then Roger will follow with a discussion on what has become a very active market for both the jack-up and floating rig sectors. I’ll then make some closing comments before we take your questions.

We began to see a meaningful pickup in client demands for offshore units all over the world during Q2 as we noted on our last call back in July. This improvement in inquiries and activity persisted through Q3 and continues today with a steady flow of new contract rewards throughout the fleet. During Q3 we finalized discussions and secured 21 contracts on five floating units and 15 jack-ups, adding approximately $655 million in fleet backlog, which given the current burn rate per day kept the total backlog number as of September 30th at about $12.8 billion or basically flat with the June 30 numbers.

Since the conclusion of Q3 we’ve added an estimated $395 million to backlog following the award of seven contracts including contracts for a previously stacked jack-up and a drillship, further indications of an improving business climate. Our financial results for Q3 reflect the higher activity as well as an improvement in average daily revenues, the latter driven primarily by the return of all five active semisubmersibles in the US Gulf of Mexico to their full operating rates, a condition we’ve not experienced since the deep water drilling moratorium was mandated back in 2010.

Improvements in Q3 results were partially offset by downtime in the fleet, a frustrating occurrence that we are continuing to work very hard to correct. The downtime included unpaid repair days on three rigs in Brazil and two in our US Gulf of Mexico division. Each instance was a separate unrelated event that had to be identified and resolved. With few exceptions the downtime was due to required repairs on the subsea control system or the top drive drilling systems.

We are attacking this issue on many fronts. We are partnering with certain suppliers including NOB to improve communications between parties and jointly tackle reliability issues. Further we’ve identified and are following programs of optimal cycle counts for certain subsea components prior to their replacement and we’ve upgraded other components with more robust alternatives. Additionally our worldwide subsea facility is now up and running so we are warehousing more spares, training more people and working smarter. Finally, we’re taking a more active role during equipment refurbishment programs to reinforce the quality assurance control processes. Clearly our Operations Team is being proactive in this area and we’re making progress. This will remain a top priority to the company and it will get better.

In addition to the improvement in quarter-over-quarter financial results, Q3 was noteworthy for the achievements relating to our fleet enhancement efforts. During the quarter and into early October we exercised options with the [Jerong Shipyard] in Singapore for the construction of a fifth and sixth [Dijae 3000N] high specification jack-up at a cost of $245 million per rig. Both units are expected to be delivered from the shipyard by the second half of 2014. We also exercised the option for a fourth drillship with Hyundai Heavy Industries, or HHI, in Korea. The estimated cost for this turnkey project is estimated to be $630 million excluding capitalized interest. And again, we expect to deliver this rig in the second half of 2014.

As for the projects in progress, we delivered the drillship Noble Bully I from the [Keppler Yard] in Singapore and the rig is currently in transit to the US Gulf of Mexico where final commissioning and client acceptance will take place over the remainder of the quarter. The drillship Noble Bully II left the dock at the [Keppler Yard] and is currently testing thrusters before it begins sea trials later this month. And as we noted in our October 6th fleet status report, we will keep the rig in Singapore to execute a larger portion of commissioning at the yard prior to the rig’s departure to Brazil. We now expect to depart Singapore in December.

Additionally we dedicated the drillship Noble Globetrotter 1 at the [Houseman Yard] in Holland earlier this month, following the installation of the rig’s multipurpose tower in August. The rig is currently expected to be completed in Holland in December and will then depart for sea trials in the US Gulf of Mexico. We remain on schedule to deliver these three initial drillship projects by the end of 2011 and we’re excited about the unique sophisticated technology that these rigs bring to the industry.

With that, I’ll turn the call over to Dennis Lubojacky to review the Q3 financial results. Dennis?

Dennis Lubojacky

Thank you, David, and good morning to everyone. Today I will discuss the significant drivers behind the Q3 revenue improvement compared to the Q2 results and our operating cost experience, and I will close with updated guidance for Q4 and full year 2011.

Noble reported earnings of $135 million, or $0.53 per diluted share, on total revenues of $738 million for Q3. Results for Q3 included a tax benefit of $0.04 per diluted share relating to certain discreet tax matters. You may recall that our Q2 results also included a $0.04 benefit due to certain discreet tax matters.

Highlights from Q3 include a $115 million increase in contract drilling service revenues to $705 million, up 20% compared to Q2. The revenue improvement was driven primarily by two events. First, day rates on the Danny Atkins, the Noble Jim Day and the Noble Driller returned to their full operating level in the US Gulf of Mexico for all or a substantial portion of the quarter after operating under standby rates in the prior quarter, adding $54 million. Also we experienced a 442-day increase in operating days in the quarter as the rigs returned to work primarily in Mexico and the Middle East, adding an additional $52 million. The increase in operating days in Q3 resulted in improvement in average fleet utilization to 77%, up from 70% in Q2. The measure includes average Q3 utilization for semisubmersibles of 84%, slightly below 85% in Q2; and average jack-up utilization of 82%, up from the previous quarter of 71%.

As David mentioned, we experienced significant downtime on five floating units in the quarter, all of which have returned to their contractual day rates. Average day rates increased in Q3 to $151,800 from $143,000 in Q2 due primarily to the US Gulf of Mexico rigs returning to full day rate. Contract drilling services in Q3 increased $22 million or 6% from Q2 to $359 million, slightly above the top of the range of guidance provided on the last call. The increase reflects the ramp-up costs incurred on rigs returning to work in Mexico and the Middle East for $8 million, including mobilization costs of $4 million. Also we saw an increase in operating expenses on the Noble Phoenix in preparation for its substitution for Noble Muravlenko in Q1 2012 in Brazil. That accounted for about $5 million. Finally, we continued to experience startup costs associated with the continued hiring and training of crews for new build assets that will be added to the fleet over the next six months and that amounted to about $2 million.

Depreciation and amortization for Q3 increased $3 million to $166 million reflecting capital projects on various rigs. SG&A expense increased $6 million in the quarter to $27 million, slightly above our guidance. Interest expense net of amounts capitalized decreased $3 million in Q3 to $11 million as a result of increased capitalized interest on our new build capital program. Capitalized interest in the quarter was $32 million compared to $29 million in Q2.

Our effective tax rate in Q3 declined to 12% as compared to 15% in Q2 and our previously full-year guidance in the low 20% range. The decline was primarily due to certain discreet tax items mentioned earlier. Without these discreet items the tax rate would have been approximately 19% in Q3.

Finally, capital spending including capitalized interest during Q3 was $559 million, bringing spending through September 30th, 2011, to approximately $2 billion. Year-to-date we have spent approximately $1.3 billion for our new build projects, $463 million for major repairs, $156 million for sustaining capital expenditures and capitalized interest of $88 million.

Turning my attention to guidance, we’re currently in the budgeting process and our initial guidance on 2012 will be available when we report Q4 2011 results. Q4 contract drilling costs are expected to range from $370 million to $380 million, and consistent with our previous guidance it’s driven primarily by higher anticipated fleet activity as we continue to prepare our new build rigs for service and as new contracts commence in Egypt for the Noble Paul Romano and in Saudi Arabia with the commencement of activities on the Noble Gene House and the Noble Joe Beall.

Depreciation and amortization for the full year is estimated to be in the range of $655 million to $660 million with our Q4 figure expected to come in between $170 million and $175 million. SG&A is still expected to fall in the range of $90 million to $100 million. Costs in Q4 should be slightly lower than Q3. Interest expense net of capitalized interest should remain in the range of $50 million to $60 million in the year with Q4 flat with Q3.

We are lowering our full-year effective tax rate from the low 20% to the range of 17% to 20%. We did experience a rate of 12% in Q3 due to the benefits of discreet tax items, and I cannot rule out other matters from quarter to quarter that could cause volatility in the rate such as changes in the geographic source for revenues or tax assessments or settlements. We anticipate our full-year 2011 annual capital spend to be about $2.7 billion, which is an increase of approximately $200 million over Q2 guidance due to the recent exercise of options for the construction of two additional high-specification jack-ups and a fourth ultra deepwater drillship.

That concludes my remarks, and I will turn it over to Roger to provide commentary on the offshore market.

Roger Hunt

Thank you, Dennis, and good morning everybody. We have been very busy with marketing efforts in our operating regions as well as regions we’re looking to penetrate. As David mentioned we’ve had success with 21 contract signings during Q3 and into October, including the relocation of one semi and the reactivation of a previously stacked drillship and jack-up rig. I’ll spend my time today covering some facts regarding our impressive contract backlog, highlight some of our recent contracting success, address the current state of the ultra deepwater sector given the acceleration in contract awards witnessed during the second half of the year, and review the opportunities we see developing around our regions of operation.

A contract backlog of approximately $12.8 billion at September 30, 2011, is composed of floating rig contracts totaling an estimated $11.2 billion and jack-up rig contracts of $1.6 billion. The backlog continues to represent visible revenues of approximately $1.5 billion to over $2.5 billion for each of the next four years, providing a significant base to seek future contracts on our three drillships under construction with Hyundai in Korea, and six high-spec jack-up new builds at the [Jerong Yard] in Singapore. Clearly this revenue visibility affords us a nice flexibility as we run our global operations and investigate alternatives for further fleet enhancement.

During Q3 we secured contracts or contract extensions for several of our conventionally more deep water semis, including the Amos Runner and Max Smith in the Gulf of Mexico, and the Homer Ferrington and Paul Romano in the Eastern Med. The Romano, which has been idle since June, 2010, is expected to commence an initial six-month drilling assignment in Egypt in November of this year. Day rates for these units range from $325,000 to $380,000. We were also successful in securing a three-year contract for the drillship Duchess at a day rate of $180,000 for drilling offshore India. The rig is expected to commence the program during March of 2012 following a period of reactivation.

In the standard jack-up rig sector we achieved notable fixtures in most of our active regions. In the North Sea we added approximately 56 rig months of backlog at day rates ranging from $113,000 to $125, 000. In West Africa Tommy Craighead was awarded a seven-month program at $100,000 per day. The day rates associated with these fixtures represent meaningful improvement from previous levels. In Mexico we added approximately 1500 additional days of backlog at slightly higher rates and in the Middle East we will reactivate the Dick Favor for an initial 90-day contract at a day rate of $95,000. The increase in contract activity is as good as we’ve seen it since early 2010.

We’re also witnessing increased demand from customers for ultra deepwater drilling rigs. If we turn the clock back to this call in 2010, we saw 17 ultra deepwater rigs under construction scheduled for delivery in 2011 and without contracts. Today, only two of these 17 units are officially without a contract and we see operators committing on units with deliveries in 2012. This is an impressive turn of events to say the least. Since the end of Q2 2011 we’ve seen approximately 20 contract announcements covering ultra deepwater rig needs in multiple geographies, and during the past month we saw fixtures on four new builds with two of them above $500,000 per day. The average term of these fixtures was over two years each.

The long-term need for ultra deepwater rigs has been driven by a number of important factors. First, the crude oil price remains resilient even in the toughest macroeconomic environment, averaging $93 per barrel over the past year and over $85 per barrel since August of 2011. Next, we continue to witness successful exploration drilling results. According to ODS, through September we have seen 15 announced discoveries during 2011 in deepwater, defined as 4000 feet and greater, with an average water depth of 6500 feet. Given three months left in the year, we can see the fourth straight year of 20 or more announced discoveries following 27 in 2010, 28 in ’09 and 32 in ’08.

These discoveries are occurring in an expanding number of geographic locations. In 2011 there were discoveries in eight different locations including Australia, Brazil, French Guiana, Ghana, India, Mauritania, Mexico, Mozambique and the US Gulf of Mexico. This compares to only five different locations in 2008 when there was concentration in Angola, Brazil and the Gulf of Mexico. In addition, new offshore areas are opening for exploration as various countries obtain a better understanding of the hydrocarbon potential. Finally, the drilling success is supporting a continuing shift toward development drilling which typically requires multi-year commitments to rigs.

As the ultra deepwater sector improves we believe Noble is well positioned with near- and long-term availability including the semis Jim Day in the Gulf of Mexico, which is expected to be available in late January, 2012, and the Clyde Boudreaux with an expected availability date in April of 2012. Our three un-contracted drillships under construction in the Hyundai yard have delivery dates in 2013 and 2014, and we’ve began a dialog with customers regarding some of these units.

Before I close this morning I’d like to quickly cover some of our regional markets and how we see those regions developing. In Mexico we achieved 85% utilization for Q3 versus 65% for the previous quarter. As of today we have 11 of 12 jack-ups in the region under contract. Half of our fleet is contracted through 2012 with two rigs booked into Q3 2014 while the other half will come off contract at the end of this year. This tends to suggest a dilemma – i.e., is the glass half full or half empty? However, considering Pemex’s urgent need for additional rig capacity and their current tendering activity combined with our solid reputation in the region, we believe we are positioned for upside; i.e., we do see the glass as half full. Regarding the semi Max Smith, we believe Pemex has a significant program to support a floater for several more years. We expect the tender to be processed by the end of December; however, we’re also monitoring prospects for this rig in other regions.

We are pleased to report that we continue to receive considerable support from our customer base in the North Sea. Since announcing extensions two weeks ago on the Lynda Bossler for six months at $125,000, and on the George Sauvageau for twelve months at $115,000, we have been awarded an additional four months on the Lynda Bossler at $115,000, twelve months on the Ronald Hoope at $113,000, and ten months on the Piet van Ede at $113,000 per day. We believe this speaks well on two key demand drivers: our customers place high value on the reliability of Noble’s service in the North Sea and they are optimistic about their longer-term programs. On the floater side we can report on a five-month extension to the Ton van Langeveld from mid-2012 at a rate of $247,500.

With the reactivation of the Dick Favor all 14 of Noble’s jack-ups in the Middle East are under contract, with six units contracted into 2014. We made a decision in 2010 to place some jack-ups in the region into accommodation mode to avoid stacking during the weak market conditions. We have seen two of these units, the Gene House and the Joe Beall move back into drilling mode under long-term contracts with Aramco. We may see similar opportunities on the remaining three units during 2012. Additional tenders are expected from Aramco in the near term for a variety of drilling needs. As for our six [JU-3000] high spec jack-ups under construction, we continue to identify and pursue prospects in the UK and Danish sectors of the North Sea as well as key locations in the Middle East, Asia and Australia, and West Africa.

Lastly, some news on Alaska. While Alaska may not represent a major revenue source for Noble at this time, we are excited about our potential commencement of drilling operations in the [Bofet] and the [Chuckchee] Seas. We are working closely with Shell to prepare the drillship Discoverer for Arctic operations and to upgrade the Shell-owned semi [Colluck] in Seattle for next year’s summer drilling season. We can also report that we’ve reached agreement with Shell to extend the current contract from December 2011 for a term of two years at a base rate of $240,000 per day. It is widely reported that Shell has invested heavily in preparing to drill in Alaska and we are honored at the prospect of playing an important role in their exploration campaign.

In summary, utilization and day rates are improving across the mobile offshore drilling fleet. Ultra deepwater has once again crossed the $500,000 per day threshold and could move higher in 2012. Tightness in the ultra deepwater segment is leading to opportunities for deepwater rigs such as our Paul Romano, Amos Runner and Max Smith. More standard jack-ups are going back to work around the world and Noble is well positioned to benefit from further rate increases. With that I’ll pass the call back to David.

David Williams

Thanks, Roger. As I noted earlier we are making tremendous progress toward the transformation of the Noble fleet. Our 14 shipyard projects consisting of eight dynamically positioned drillships and six high specification jack-ups have begun to exit the yards. Very soon we will be down to five drillships and six jack-ups projects in progress with all but one of these projects consolidated into one of two top-tier shipyards with excellent histories of project execution, and by the end of 2014 we’re projected to have 16 dynamically positioned semisubmersible drillships in the fleet, up from just 4 five years ago.

Three of our eight drillships under construction and all six of our jack-ups new builds are all currently without contracts. We view this capacity as a huge positive. As Roger indicated, client demand for the timely availability of high specification units is building as evidenced by the high number of contract awards for the ultra deepwater units since the end of Q2 2011, and the rapidly depleting ultra deepwater capacity available for 2012. I believe Noble is in a great position with the opportunity to offer these new high specification jack-ups and drillships as well as certain existing rigs such as Roger mentioned on the Jim Day and the Clyde Boudreaux, at a time when availability of the industry’s current and future high specification units is increasingly secured by contracts.

The combination of these factors should provide Noble with an earnings and cash flow growth profile over the next three to four years that is among the industry’s best. And with that I’ll turn it back to Jeff.

Jeff Chastain

Okay, thanks David. And Regina, we’re now ready to begin the question-and-answer session of the call, and while you’re assembling the queue let me remind everyone that we’d like to follow a one question and one follow-up rule so that we can take as many questions as possible in the remaining time.

Question-and-Answer Session

Operator

(Operator Instructions.) Your first question comes from the line of Kurt Hallead of RBC.

Kurt Hallead – RBC Capital Markets

Good morning, hi guys. So I guess my initial question here is focused on that news item that came across Bloomberg yesterday about Pemex saying that they don’t want the Max Smith or don’t want to extend the Max Smith at the end of the year. I know you guys have been through enough gyrations in dealing with Pemex over the last 18 months if not longer in that situation. Can you help us handicap what Pemex’s plans are? What is it about the Max Smith that it may not like or maybe is it something, another rig in your fleet that they may be looking at? Can you give me some color on that please?

Roger Hunt

Well Kurt, you’ve just got to love it when the head of E&P for Pemex starts off a negotiation by saying he doesn’t want our rig. We can take the positive side of that and say that we’re just exactly in the right place at the right time. In all seriousness, we haven’t heard any of those signals. Everybody we deal with at the operating level sees the requirement; the Max Smith has done a great job. So the bid process, we expect it to be probably complete by December and we have every reason to think that we’ll participate in that. Should that not be the case we have a lot of interest in the Max Smith behind its current project so I won’t speak to handicapping Pemex but I will speak to we like our position with that particular unit.

Kurt Hallead – RBC Capital Markets

Okay, and then my follow-up is for David. The industry in general has been plagued by this unplanned downtime situation for the better part of two or three years now, and by your comments here on the call it sounds like you guys are aggressively attempting to address that and to whittle that unplanned downtime as much as possible. Can you outline some of the things that you’ve already put in place, some of the successes that you’ve had? I don’t know if you can suggest that unplanned downtime gets close to zero but can you handicap for us how you can whittle it down from here?

David Williams

Well Kurt, we talked about some of it. I don’t want to dwell on it too much. I will tell you that we’re getting better at it. These rigs are made to run and we took a year and a half off in the Gulf of Mexico, and a lot of what we’ve seen – and I think our competitors have seen – is just startup issues with these rigs. This stuff’s made to run, it’s not made to sit. But we’re working hard. We started consolidating our subsea efforts and building a subsea capability about three years ago and it’s now fully up and running. A lot of things we’re seeing, one of the issues we saw on the top drive was a top drive that had been freshly shopped during the moratorium and we brought it out, and we had a seal failure and a gearbox drained. And you know, it takes time. Those units are not on the shelf – you’ve got to take them down, rig them down, send them in and re-shop them. It was just a foul-up in the manufacturer’s shop.

So we’re doing a lot of things. I mean we work closely with suppliers. We’re watching closer what they do. We’re more involved and we’re kind of getting ourselves wired for running more sophisticated equipment flat out all over the place. We’re spared up; our downtime will improve. It’s frustrating right now, it was really frustrating Q2 and it’s frustrating now but with what we’re doing it will get better. You’re never going to get to a place where you’re zero, but we will get to a place where we get steady operations. It will get back some into more predictable and more manageable and it will get better.

Kurt Hallead – RBC Capital Markets

Okay, thanks David.

Operator

Your next question comes from the line of Dave Wilson with Howard Weil.

Dave Wilson – Howard Weil

Good morning, gentlemen. David, real quickly on the recent rates signed in the ultra deepwater, some as Roger mentioned above $500,000 a day, I just wanted to get your thoughts there and see if you think that there’s a possibility that these rates can go even higher or maybe that we’ve just reached a nice plateau?

David Williams

You know, in my experience rates are very rarely flat for very long. They’re flat at the bottom, they generally run up to the peak and then kind of they’re flat for a while and they roll over. I don’t think we’re at the peak yet with the rate of… And I’m not trying to set an expectation of you know, I don’t know how big this gets, but certainly we’ve seen the rates continue to improve through the last year. Roger talked about the number of contract signings and a great point of reference I think is Roger’s note about where we were on this call last year when people were concerned about could the industry assimilate the number of rigs that were in the market and the rigs coming out of the shipyard.

The expectation was we just couldn’t keep up and the fact is we have and then some. And so the deepwater, the ultra deepwater and the deepwater frankly, market is in very good shape I think where we are today and going forward. I mean the question that Kurt asked about the Max Smith – when we took the Romano out of the Gulf of Mexico we had more than one opportunity for it. We’ve got more than one opportunity for the Max Smith. So the deepwater, the floating drilling market is in very good shape and so I’d say the market is still under-rigged if you will, and so no, I don’t think that we’ve flattened out.

Dave Wilson – Howard Weil

Okay great, and then just one follow-up. Your relationship with Shell has been very important as you’ve reconfigured your fleet so far, but I wanted to know how big a part the knowledge of Shell’s future demands played into your moving forward with the new build drillships. I mean did you see demand above and beyond what Shell could possibly require and kind of almost using their demand as a safety net? I hate to characterize it like that but was it, or were the construction costs just too good to pass up? I guess what I’m trying to get at here is how critical this relationship has been and will be going forward.

David Williams

Well, we have a great relationship with Shell. I mean they’re half our backlog; we are a huge part of their not only deepwater capability but global drilling capability. As Roger talked about Alaska, I mean we’ve opened an office in Anchorage and we are actively engaged in that program to support those guys when they get their permits but we have different shareholders and different drivers than Shell and we both recognize that, and we talk about it regularly. We have no intention of being an extension of Shell or being a one-trick pony. We’ve got other opportunities out there. Clearly Shell is a big piece of our business and with our acquisition of Frontier last year and the contracting of the two Globetrotter rigs and then later the HHI ship, that backlog is one of the things that’s providing the fuel for us to be able to drive this transformation.

But while they’re interrelated they’re not interdependent. We certainly appreciate Shell; we’ve got a great relationship with them. We have a very frank and open dialog with those guys which I think both sides appreciate but we’re not building a fleet for Shell. We’re building a fleet for Noble shareholders and our relationship with Shell is important but they’re not dependent on one another.

Dave Wilson – Howard Weil

Great, thanks Dave for the insights. I’ll turn the call back over.

Operator

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

Judson Bailey – Jefferies and Company

Thanks, good morning. I wanted to circle back on some of the deepwater commentary and what seems like an acceleration in the market. One thing that seems a bit striking is we’ve seen higher rates but it also seems like operators have gone from a situation where they could contract a rig one or two months in advance and now it’s more like they’re contracting rigs in some cases eight, nine months in advance; and it seems like the availability is really tightening for 2012. I’d just be curious to get your perspective, David – why do you think all of a sudden it seems like we’ve seen this acceleration in day rates and lack of availability for 2012 for operators?

David Williams

I think Roger’s probably better to answer this question. My perspective is that we knew this was going to build after the Gulf of Mexico moratorium, that everybody kind of took a year on the sidelines. The work didn’t stop but they underspent their capital budgets and they’ve got a lot of work to do. But I think Roger probably has a better insight to that than I do, Jud.

Roger Hunt

I think one element is that the new supply coming onto the market plus rollovers in the market are very visible, and I think customers may have had an attitude of “You know what? If we’re patient this year pricing’s going to come our way.” And as it turns out there’s been quite a bit of discipline on the supply side from a pricing perspective and I think if you look at the most recent bid to Petrobras for the 1500-meter bid, I think only one number of all of the bids for a 6000-foot job was below $500,000. So I think there’s quite a bit of discipline on the supply side. Having said that, there’s still 2.3 units coming to the market every month, either new build or coming off contract so there’s still quite a bit of supply coming to the market but the rate of pickup right now, it seems to be matching it.

Judson Bailey – Jefferies and Company

Okay, thank you. And my follow-up is when looking at the Jim Day and the Boudreaux, do you have a particular strategy on wanting to lock those up longer-term now that that seems to be more available, longer-term contracts? Or do you prefer to keep it short-term in anticipation of maybe higher rates in 2013?

Roger Hunt

Well, I think just your question speaks to the strength of the market, that you have it in mind that we have the option and we do. We are looking at programs, particularly on the Jim Day where we have customers in the Gulf of Mexico that have got 2012 programs to prosecute and may not have lined up a rig. We’ve also got customers that are interested in the unit long-term. We’ve got customers behind the availability of the Boudreaux. So I think probably the best way to answer that is we have to respond to what our incumbent customers’ requirements are so that may be a factor, but I think it’ll all sort itself out before the end of the year.

Judson Bailey – Jefferies and Company

Great, thanks. I’ll turn it back.

Operator

Your next question comes from Ian Macpherson with Simmons and Company.

Ian Macpherson – Simmons

Thanks. David, I doubt that you want to answer this question specifically but I was hoping you might talk around it anyway. Really the question is are you finished ordering new builds or are you not, and you know, if you did order more would it be a jack-up or would it be a drillship; and what are the decision factors from here now that you’re pretty fully-loaded with what you’ve purchased so far?

David Williams

Ian, we’ve got a Board meeting next week and we’ll take that up with the Board. My expectation is right now I think we’ll get three rigs out this year, we’ll get down to 11 projects. Those projects are all in good yards, in good shape. Globetrotter II, which is the only non-Hyundai or [Jerong Yard] is actually ahead of schedule at the shipyard in China and so we feel very good about where we are right now. Shipyard pricing is coming up some. We exercised our fourth option in Hyundai at $630 million which is an all-in number but it was a very attractive shipyard price. I think those prices are coming up a little bit. I think for us, we will probably focus on execution more in the months ahead as we move through. You know, we’re still doing this fleet evaluation to see which rigs we think are key, core assets going forward and so we’ve got a lot going on right now.

We are heavily focused right now on a number of projects, not only the new builds but getting the [Colluck] ready and the Discoverer both for Alaska next year, finishing our drillship upgrades. So I think right now we’re going to work hard one execution, get the projects in good shape; get everything done that we want to do fleet-wide and then we’ll take another look at it probably sometime next year on what we think the market looks like for future opportunities. But right now I think we’ve got our plate full and I think we’ll play these and work on execution.

Ian Macpherson – Simmons

Okay, sounds reasonable. And then Roger, you mentioned that you saw predominantly over $500,000 bids. I think you were referring to the 1200-meter and 1500-meter tenders that Petrobras opened a day or two ago. Is that correct and can you provide any more color on what you’ve seen from those bids and your expectations for what Petrobras is going to take against those bids?

Roger Hunt

Oh, probably just the same things you’ve see, Ian. I guess some of the takeaways were the number of bidders was much fewer than we’ve seen on recent Petrobras tenders – only four or five bidders as opposed to double that number; fairly consistent pricing on the two- to five-year packages and not a lot of discounting for the difference between three- and five-year terms. I think there was only $20,000 to $30,000 a day. So I think that that’s a great indicator. I think how many rigs they’ll take? It could be as little as two and as many as five.

I guess I’ll make a comment that you know, it’s reinforcing to me that contractors are pricing the way they’re pricing it, and part of it is that OPEX in Brazil is increasing. It’s got a labor market plus the strong currency that you know, is escalating. So we need to be paid more for our services.

Ian Macpherson – Simmons

Good point. Alright, well thanks a lot.

Operator

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

Robin Shoemaker – Citigroup

Thank you. So Roger, just following up on your last comment, do we read anything into the fact that you did not offer the Boudreaux or the Jim Day or the Max Smith in this recent tender in terms of you’re seeing just better opportunities elsewhere?

Roger Hunt

The quick answer, Robin, is yes, and it does speak to the margin erosion nature of Petrobras contracts is that if you have opportunities to put rigs under contract where you may get some protection then we would be looking at those kinds of alternatives.

Robin Shoemaker – Citigroup

I see. So better cost escalation provisions?

Roger Hunt

Well, all elements of it but the easy answer is that we didn’t believe that the Clyde Boudreaux was suited to the nature of that tender and that there were better opportunities.

Robin Shoemaker – Citigroup

Okay. So David, my other question was that we see the new build activity with deepwater vessels and we also see some M&A activity of companies that have built new rigs or have relatively new fleets. So since you’ve done both new builds and you’ve done acquisitions of companies here recently, how do you see the relative advantages of build versus buy with what you’ve seen recently in terms of pricing in the market?

David Williams

Robin, what drove us to the shipyard really was the lack of good opportunities in the M&A space for what we wanted to put in the fleet. Frontier was kind of a unique opportunity specifically because of their primary sponsorship with Shell and Shell’s desire to do a major long-term alliance with us. But when we look at $85 oil, which is what the average price is right now, even in this global economic bust that we’ve got going on right now the oil price is high enough to support basically any kind of offshore drilling activity anywhere in the world, so that gives everybody hope.

What drove us to the shipyard was the value in the yards versus the value in the market that we could put those kinds of assets in the fleet for, and I think that’s probably still the case even though the shipyard prices are starting to come up. I think you’ll see shipyard prices and equipment prices continue to move up but we’ve seen no slack in the ask of existing assets, assets that we might want to put in the fleet. We’ve seen no slack in what these guys are willing to take for those assets so that’s really what drove us to the yard anyway.

Robin Shoemaker – Citigroup

Yeah. And so the nearest availability in the yards, are we talking now 2015 delivery?

David Williams

Just by virtue of time you’re probably getting close to it. The fourth ship we have is at the end of 2014 and I’ll leave that to the yards to tell you exactly what they can do. I think the [Atwood] announcement on the DSME ship the other day, I think that was a 2014 delivery if I’m not mistaken. So there might be some capacity around the world in 2014 but I mean if you’re looking at a 34-month to 36-month horizon from commitment to delivery you’re about there anyway.

Robin Shoemaker – Citigroup

Okay, thank you.

Operator

Your next question comes from the line of Joe Hill with Tudor Pickering Holt.

Joe Hill – Tudor, Pickering & Holt

Good morning. Dave, are you guys making any progress in terms of the jack-up asset divestiture packet and what’s the interest level in those types of assets today?

David Williams

Joe, we are making progress. What we’ve said is we’ll try to identify a plan by the end of the year. We’ve got 49 jack-ups; of those 49, three we’ve delivered in the last 2005-2008 cycle and six we’ve got under… So there’s really kind of 40 rigs on the table there that we would want to do a full evaluation and it takes time to do that. So we’ve kind of focused on trying to get something out to the market by the end of the year. I tend to continue to believe that given where we are in the cycle, the strength of the jack-up market and the condition of our fleet, once we identify a package my expectation is that there will be buyers there.

This business attracts capital when the cycles are in the right place and I think the rigs that we’ve got with the backlogs we’ve got in place, I happen to think that we’ll have an opportunity to. That may or may not materialize and that might lead us to a spend but we’re just not there yet. We’re still working the process and we hope to have something identified that we can talk about by the end of the year, but we’re still doing a lot of soul searching within the fleet to figure out what we think fits us best.

Joe Hill – Tudor, Pickering & Holt

Gotcha. And then circling back to the Max Smith for a moment, is the receivable issue with Pemex still outstanding with regards to both their [rent ends] of the rig?

David Williams

Yes.

Joe Hill – Tudor, Pickering & Holt

Okay, that does it for me. Thanks.

Operator

Your next question comes from the line of Geoff Kieburtz with Weeden & Company.

Geoff Kieburtz – Weeden & Co.

Thanks very much. Roger, just a follow-up: you talked about the deepwater contracting from a day rate perspective from sort of a contracting lead time perspective. What about the term of these contracts that you’re seeing? Would you expect those to start elongating here or do you think we’re going to see a lot more of the sub-two year contracts?

Roger Hunt

Well, as I mentioned the average of our recent four fixtures was two years; embedded in that was I think five years with one customer in the Gulf of Mexico. So I think we’ll continue to see a blend of terms just to suit the particular programs that the customers are prosecuting.

Geoff Kieburtz – Weeden & Co.

What you’ve described is a marketplace that’s getting tighter. We see some evidence on that in terms of the upward movement in day rates but where do you think we should be looking for benchmarks or barometers here over the next couple of quarters? Do you think it’s going to be primarily rates moving up and terms staying relatively static or do you think we’ll see term extending first and then another leg up in day rates?

Roger Hunt

Ask me that question again two quarters from now.

Geoff Kieburtz – Weeden & Co.

(laughter) I want a forecast, Roger, not a report.

Roger Hunt

You know, I think we’ve talked about it. I think the fundamentals are sound. Operators, our customer base, they’re quite active in the market and looking at their own programs. All of these discoveries we’ve mentioned in different places, I think in 2012 you’ll start to see some of those come to the market in terms of the appraisal program so it’s good news. It’s a good story. It’s something other than just a Brazil story.

Geoff Kieburtz – Weeden & Co.

Okay, and a second question just for calibration – you mentioned that a year ago at this time we had 17 deepwater rigs without contracts. There’s only two of those left. By your count today, how many deepwater rigs are there including new builds that don’t have contracts?

Roger Hunt

Let me answer it this way. By my count in 2012, if you combined spec new builds plus equivalent units – the ultra deepwater rigs coming off contract and it’s not evident that they’re going to be extended – it’s around 27 units. So my metrics is you’ve got to see 2.3 per month taken off the market for demand to equal supply.

Geoff Kieburtz – Weeden & Co.

Right. Are you suggesting that that 27 be compared to the 17 a year ago?

Roger Hunt

The 17 speaks to new builds. I haven’t gone back and tracked what rigs were coming off contract.

Geoff Kieburtz – Weeden & Co.

Okay, maybe we can do this later. We’ve got our calculation; I just wanted to see whether yours was in the same ballpark. Thank you very much.

Operator

Your next question comes from the line of Scott Gruber with Bernstein.

Scott Gruber – Bernstein

Good afternoon, gentlemen. Most of my questions have been answered but a couple on the downtime issue. In the deepwater Gulf, one of the changes that we’ll see if we’re not seeing it happen already is increased downtime due to regulatory inspections and just a generally slower drilling environment. Can you provide some color on your ability to cover some of the lost rig time with a standby rate? Are customers willing to accept a standby rate for regulatory inspections in particular? And if so, what level of rate do you think is achievable?

David Williams

Most of the regulatory inspection issues were really mandated during the moratorium and permatorium where you had to go through and get a certificate of compliance for the rigs. So that is going to be a recurring issue going forward and we’ll try to take that offline. The regulatory issues right now that are slowing down drilling operations really go to operators’ processes and we’re effectively on full rate there. So I don’t know that it’s really regulatory issues that’s slowing us down; it’s just equipment repair periods.

We have downtime provisions in our contracts. In some cases they’re better than others and in some cases we build up a bank, but the fact is if you’re working in 10,000 feet of water it takes you a long enough time to [trick the stack up] and get it where you can work on it that effectively you’re going to outrun your downtime bank. So the right answer is do what we’re doing and try to build up to prevent the downtime and not deal with it after the fact. So I would expect that over time our revenue performance is going to improve in this respect just from those efforts.

Scott Gruber – Bernstein

Okay, that makes sense. Do you think it’ll take a materially longer period of time to drill deepwater wells in the Gulf of Mexico going forward?

David Williams

There are more testing procedures, more cementing, more issues with well processes that yes, on an apples-to-apples basis it will take an operator longer to drill a given well under today’s rules than it would have taken him to drill the same well two years ago. Every well in the Gulf of Mexico’s different so it’s kind of hard to be able to quantify exactly what that means but most of the estimates I’ve seen are if you drill in the same well today that you were drilling two years ago, you’re arguably 15% to 20% longer just in time, and that cost really at this point accrues to the operator, not the contractor.

Scott Gruber – Bernstein

Right, okay. That’s all from me, thanks.

Operator

Your final question will come from the line of Mike Urban with Deutsche Bank.

Mike Urban – Deutsche Bank

Thanks, good afternoon. The first one’s kind of a qualitative question: clearly no impact in the field or in current day rates from a lot of the macro issues that we’ve had out there. As you’re talking to customers, though, is there any concern or maybe even a loss of a sense of urgency out there; in other words, “Hey, maybe we’re talking about getting a tender out or rig signed up next period but wait, let’s take a wait and see on that approach?”

Roger Hunt

I’ll take a crack at that – no, almost to the contrary. If you look at what’s happening… Our experience in the North Sea – we have 100% utilization, I think we’re ahead of the market. We have seen 20% or better increases in pricing call-to-call, and we’re seeing customers book all the way through 2012. You’d have to go back quite a ways to replicate that.

Mike Urban – Deutsche Bank

Okay, good to hear. And unrelated, you’ve talked a little bit about your opportunities in Alaska and the drilling in Arctic environments – I think there’s a little bit of a debate on how big a market that’s ultimately going to be globally. Would you like to be doing more of that? Do you see Arctic opportunities as something that is a growth market for you and if so, would you take a look at building a customized or maybe an Arctic-class rig or drillship?

Roger Hunt

Mike, you know you’ve got to like our position. Shell has invested heavily in getting ready to drill wells in [Chuckchee] and the [Beltic] seas. We’re involved in both of those drilling operations – in one case with the Discoverer, in the second case we’re upgrading Shell’s asset. And these are significant programs. There’s a lot of optimism on behalf of the customer. It’s not so much a question of “Is there a resource?” – it’s accessing it. And if and when they do that it really is going to be a question of what is the appropriate asset to develop to drill up and develop these prospects, and it’s likely to look very different to what we’re using today. So given our position we think we’re going to have an interesting opportunity to participate in that whole technology evolution for drilling in that section of the Arctic, so we like our position.

Mike Urban – Deutsche Bank

So there are discussions going on at this point, even if it’s preliminary, as to what that asset might look like. Is that something that you’re working on?

Roger Hunt

I think the focus is on execution in 2012, hence looking at the Discoverer and the [Colluck]. But if you look at a photograph of the [Colluck] it’s a very different looking asset than a drillship, so just those two assets for the different water depths are quite unique. So yes, there is discussion and obviously you see something like the [Stenna] solution, and it is at a totally different end of what the CAPEX equation might be. So yes it’s an active discussion but it hasn’t come to modeling stage yet.

Mike Urban – Deutsche Bank

Great. That’s all for me, thank you.

Jeff Chastain

Okay, Regina, we’re going to end with that and I’d like to thank everyone for your participation today. Please make a note on your 2012 calendars that we do plan to report Q4 2011 results on January 25 with a call scheduled for January 26, and we will confirm those dates and the call details in early 2012. I will be available to take any follow-up questions over the day. Again, thank you, Regina, for coordinating the call and good day, everyone.

Operator

Ladies and gentlemen, this does conclude today’s conference. Thank you all for participating and you may now disconnect.

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