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 Corporation, second quarter earnings call. (Operator Instructions) As a reminder, this conference is being recorded today, Tuesday, July 20, 2010. I would now like to introduce Mr. Lee Ahlstrom, Vice President of Investor Relations and Planning. Mr. Ahlstrom, you may begin your conference.

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

Thanks, Lee. Good morning to everyone, and thanks for joining us today. It has certainly been an eventful time from the tragic events in the Gulf of Mexico and the impact of resulting drilling limitations to our recently announced agreement to acquire privately held Frontier Drilling and further, our separate agreements with Shell provide unprecedented backlog and sound contract security. To put it mildly, it's been a busy quarter. Joining me today on the call are Tom Mitchell, our CFO and our Senior VP of Marketing and Contracts, Roger Hunt. Our prepared remarks will be relatively brief. In addition, because our deal with Frontier hasn't closed yet, we won't be able to provide you with much more detail than we did in our call of June 28. For those of you who might have missed the Frontier news, let me offer a very brief recap. Noble has agreed to acquire Frontier Drilling in a cash transaction that buys the enterprise at $2.16 billion. We will fund this with a combination of cash and debt. The deal has an FPSO and six floating drilling units, including two high-spec, dynamically positioned ultra deepwater Bully-class drillships that are owned 50-50 by joint ventures between Shell and Frontier. Together, this part of the deal adds about 23 rig years of work and $3.2 billion to our growth backlog. On top of this are separate agreements with Shell, which provide firm contracts on two new ultra deepwater drillships, one of which is the Noble Globetrotter already under construction and one as yet unnamed ship, plus a three-year extension on the Noble Jim Thompson. The ships are both at rates of $410000 per day for the first five years, and float with an index in years six to 10 plus a 15% upside in the form…

Thank you, David, and good morning. Last night, we reported net income for the second quarter of $218 million or $0.85 per fully diluted share. On total revenues, that's $710 million. The results included approximately $0.02 per share resulting from a provision related to the company's ongoing Nigeria FCPA investigation as well as $0.06 from a higher-than-anticipated tax rate of 19% versus last quarter's rate of 13%. I'll discuss taxes in more detail in a few minutes. Overall, our figures are down from the first quarter when net income was $371 million or $1.43 per share on total revenues of $841 million. The majority of the differences can be explained by lower contract drilling services revenues and a higher tax rate for the quarter. For the second quarter, we reported drilling revenues of $688 million versus $809 million in the first quarter. The difference of $121 million represents a 15% decrease quarter-over-quarter and is primarily associated with a combination of dayrate changes across the fleet, downtime on our floating units in Brazil and Libya and the impact of the drilling restrictions in the U.S. Gulf of Mexico. In Mexico, we have been very successful at obtaining both contract extensions as well as some direct assignments and have kept our units operating. However, many of the units that received those extensions were operating at rates over $100,000 per day and several were in the $170,000 per day range. The units have re-priced considerably lower. We had a similar story in the North Sea and West Africa for the Noble Ronald Hoope, the Noble Piet van Ede and the Noble Percy Johns all re-priced lower. You can see this impact in the release on the schedule where we note the average dayrates for our different classes of units. In the first quarter,…

Let me begin today by recapping our backlog position. Noble's Backlog, excluding the Frontier transaction or the Shell agreement stood at approximately $6.7 billion as of June 30, 2010 with about 61% of the days booked for the rest of 2010 and about 35% for 2011. As David has already mentioned, when we close Frontier later this month, the estimated backlog will double. Speaking to the jackup market, this past quarter has been flat in terms of the absolute number of rigs employed. However, if one sets aside the Gulf of Mexico, we would have seen an increase in demand with net gains in Southeast Asia, the North Sea and the Arabian Gulf. In the North Sea, Noble has been able to maintain 100% utilization. As David mentioned, we are pleased to see Shell commit to a 2-year contract extension on the Hans Deul commencing February 2011 at $175000 to-date. In the Southern North Sea, we received a one-year contract extension from Gaz De France at around $86,000 to-date. In West Africa where overall utilization of the jackup fleet is around 60%, we executed 2-year contracts for Exxon Mobile, Nigeria on the Percy Johns and the Ed Noble at rates of $85000. In the Middle East, utilization has remained relatively constant since the first of the year despite an increase in the number of rigs being marketed. This is significant because outside of the US Gulf, the Middle East has the highest number of stack rigs. Dayrates have been under pressure, although term is still available as evidenced by an 18-month contract on the Harvey Duhaney at $60,000 per day. We are still waiting on the outcome of the tenders submitted to Aramco in January. And we also believe that Aramco may be in the process of preparing the tender…

Thank you, Roger. Regina, we’re going to go ahead and open it up for questions. But I would like to remind everyone of our one question with one follow-up rule, so that we can get as many people participating as possible. Go ahead, Regina.

(Operator Instructions) Your first question comes from the line of Angie Sedita with UBS.

David, I’m sure you’ve begun to have some conversations with your customers in the Gulf of Mexico on your floater fleet. What are you hearing so far from the tone? Are they undecided on the Gulf of Mexico? Are they anxious to get out of the Gulf of Mexico, or is it a wait and see attitude? Can you just give us a little bit of color?

Let me tell you in two pieces. Clearly, Shell and others have a program in the Gulf of Mexico and they expect to be able to operate successfully in the Gulf of Mexico post-moratorium and whenever that is, whether it's the end of the November or sooner. So I would say the operators that have big portfolios of acreage and who have the wealth above financial wherewithal to be able to meet whatever guidelines the government may throw at them, clearly on going forward. Some of the smaller operators I think are still looking at the Gulf as a place where they would like to be operating. But in the face of not knowing what caps might be and what the political environment might be I think they are some are taking wait and see attitude. We've have always viewed the Gulf of Mexico, politically as a very safe environment and a place where one could operate under a normal regime and expect some level of government support. Even though the people of United States are driven by misguided green views of what normal operations be, the fact is Gulf of Mexico and drilling contractors and operators have a very good track record. And that scares the hell out of people. So I think the major operators and those that have wherewithal are working as fast as they can to keep it going. I think some of the smaller operators are still trying to see what's going to happen. Clarity from our government would go a long way to bridge that gap. So I think it's a mixed bag, Angie. I don't thing anybody things the Gulf of Mexico is dead. I think that they put an unlimited cap on it. You know if I am David Williams operating campaign, I am spending my family's money or I have a small group of investors that may change my view of the world. But with the amount of money the people have spent on lease opportunities here over the last couple of years. They have a great portfolio of acreage and I think they look at this with hope and think that cooler heads will prevail. So I think we have to give our government a little more time to respond.

Okay. That's fair enough. And then as a follow up, it's early to tell exactly what's going to change. But as far as potential changes from equipment standpoint for the contract drillers, BOPs, backup, shut-off systems, et cetera, any thoughts there on time to achieve these changes and costs?

The costs on a per rig basis are not out of line. I mean they are not crazy. You know we are talking millions of dollars not tens of millions of dollars. It clearly depends on whether the rig is equipped with a BOP and a four stack system that was delivered 20 years ago or a newbuild late generation rig like the Danny Adkins and the Jim Day. But you got a six RAM package, but there is no reason to believe that technical obsolescence is coming as a result of this. Exactly how long it's going to take to retro fit some of this stuff depends on the configuration of the current BOPs and how fast the manufacturers can deliver what we got. And how long the government gives us to be compliant? Some of our rigs are really almost compliant or really compliant now. Some are very close and some will need a little time and some manufacturing. So it kind of depends, but we're talking, say, on average we're talking just a few million dollars not tens of millions of dollars and not over $10 million, frankly. So it's not anything that should scare the hell out of you. It's something that if we're mandated to do, we can easily do. In some cases, we can pay for it out of our pocket. In some cases, we'll have some recovery. In some cases, we're already equipped. In some cases, there are things we might do anyway. So from a regulatory standpoint, it's not a ridiculous feat for us get compliant. It may take time. If we've got to build an additional ramp cavity or something like that, that may take some time to manufacture and install, but there is no reason to believe that we're headed towards technical obsolescence on the floating fleet.

Then just to build that ramp cavity, is that a three month timeframe, six month just to put something around it?

Angie, it's going to be different per rig per manufacturers. For instance, on the EDAs, we've got four-ram stacks, and we've put on the bottom of the test ram. So we've actually got a five-ram stack already. That's going to be easier to convert than a rig that's only got a four-ram stack, and we may have to go back and retrofit a new ram to it. We may have some spares in some cases. We may be talking about bonnets and seals and stuff like that. In some cases, we may be talking about more, but it's different for every rig.

Our next question comes from the line of Collin Gerry with Raymond James.

Quick, if we switch gears to Brazil, clearly their lack of capacity or their demand exceeds what's available in the market before this accident. What's your sense or have the conversations changed with Brazil in terms of their new goal program and or whether they want to take some of this capacity out of the Gulf of Mexico?

Yes, Collin, this is Roger. Thus far, we haven't seen any significant change in what's coming out of Petrobras. I think as you are aware, they are in the process of evaluating what they're terming a 28 rig bid. The nature of that law as it appears that most of the bid if not all of the serious bid is where Brazilian contractors or associated with Brazilian contractors. It is a live process and there is an expectation that Petrobras will award some of all of the rigs offered in that process. I think there's also a view that possibly the delivery of those rigs would take longer than the mandated four years and therefore Petrobras still has a program to prosecute. And so they will be going to the market to get filling rigs. And so back to your question I think they'll be looking at rigs out of the Gulf of Mexico as they would have looked at rigs from all over the globe.

But we haven't seen anything tangible yet in terms of them actively coming out with new programs or the conversation is changing?

No, I mean their hands are full on the tender process we have going on right now.

Okay. And then switching gears a little bit, obviously you all have bit off a pretty big chunk with the Frontier deal. I was just curious from the CapEx perspective if you look at some of your floaters in terms of upgrading to a DP, whether or not discrepancy between DP and Moore is growing overtime can be argued? But it seems to me like that might be something that you all considered in the past, is that still on the horizon?

Collin, we're always looking at opportunities to high grade the fleet. I mean, we clearly have an EVA that is the worst DP the Noble Paul Wolff drill. The major finds of pre salt finds in 2P and Jupiter in Brazil, so clearly that haul is capable of being DPd and we actually have a design that we can go back and retro fit DP. Whether or not it makes economic sense, it's probably too early to say whether or not on a rig by rig basis it makes economic sense. But it's doable and it's not a ridiculous amount of money, so we've been talking about this evolution of, "Oh my god, we got Moore rigs for a long time." I don't believe that Moore rigs are obsolete yet. So we have that era in the quiver, we have an opportunity if we choose to utilize it. We'll see whether or not it's warranted or makes economic sense as we go forward.

So it sounds like a not a near term issue and if it did happen you probably like to see a contract associated with that upgrade?

Well, those are your words not mine. I'm saying we have a plan. And if it makes economic sense, we will pursue that plan. As Roger said, the outlook for the Gulf of Mexico is fuzzy at best. I’ll put it this way; we have an engineering solution, if that becomes a warranted modification. Whether or not that is warranted is I don’t believe going to be a technical obsolescence question. It will be a market-driven question or whether or not it’s an opportunity for us, not a requirement for us. So if we see that it makes sense and it pays, we’ll do it; if it doesn’t, we won’t.

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

Just to start off, Roger, do you have any feel for getting a new contract on the Duchess might be like at the end of September and whether or not that asset can actually work in West Africa?

Joe, I’m not sure if I understand the second part of that, because it’s working in West Africa.

I was just curious about its opportunity for continued employment there.

Yes, well, of course that's not part of that fleet yet. But just looking from the outside, several things could happen. The current customer could keep it. If not, it would be marketed in the sector. And so, there are opportunities for a unit of that specification.

And then, you guys got a really nice fixture with the Hans Duel in the North Sea. Do you see similar opportunities for the Julie Robertson which Shell rolls off in September?

Julie Robertson is not the same rig class, just for clarification. The Hans Duel is capable of working in the central North Sea and Shell’s program will use it in that sector. The Julie Robertson spends most of its time in the southern North Sea. The outlook is good. I'm fairly confident that that will see continued employment.

Finally, switching back to West Africa here, you’ve got three jackups not working for Exxon in the area which should be available soon. What are the prospects for work for those rigs?

I missed the first part of your question, I’m sorry?

The three jackups you have in West Africa that are not currently contracted with Exxon look like they’re becoming available soon. Can you comment on the prospects for work there for those rigs?

The way I’d answer that is, West Africa is bumping along at around high 50% to 60% utilization depending on how you treat the cost back units. Until there is a resolution of the Petroleum Directory Act in Nigeria and more political stability in that area, I don’t think there's going to be much near-term change in the West Africa jackup market. So I think for the rest of this year, maybe the beginning of 2011, we will see the kind of utilization rates we've got now.

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

David, I wanted to ask you, or Roger perhaps, you made a couple of references to the high-spec jackup market and there does seem to be a niche there. And I'm just wondering, to what extent does your fleet address that high end market, specifically where there are tenders with very high capabilities for hoisting 1.5 million, 2 million-pound hoisting capability and 15 cape BOP stacks. Where do you see the high-spec market segmented and how does your fleet address that? Citigroup: David, I wanted to ask you, or Roger perhaps, you made a couple of references to the high-spec jackup market and there does seem to be a niche there. And I'm just wondering, to what extent does your fleet address that high end market, specifically where there are tenders with very high capabilities for hoisting 1.5 million, 2 million-pound hoisting capability and 15 cape BOP stacks. Where do you see the high-spec market segmented and how does your fleet address that?

I think it's probably taken us all by surprise. If we saw back 12 to 24 months ago and saw the large quantity of jackups coming into the market, there was cause for concern. The industry is rocking long at about 80%. There's still some 34 jackups to be announced, and to maintain 80% utilization you got to employ 29 of those over the next 21 months. I am backing up a little bit, but I think when you look at such areas as the Middle East, particularly Aramco's high-spec program, when you look at any kind of economic improvement in Southeast Asia, it doesn't take much to fix West Africa to see a marginal increase, and the Pacific. So those areas combined will I think keep the jackup market at 80% or above. Now, specifically, the kinds of things that you said high-spec, some of our units could be high-spec just by virtue of their water depth capability. But if you are talking about large hoisting capacity, big mud volume storage, big quarters capacity, it really gets into rigs like the JU-2000 class, the Hans Deul, the Scott Marks and the Roger Lewis and as observed with the Shell fixture that's being put away at nice rates. But also we have units like the Roy Rhodes that has been upgraded to a very high spec for a 116-C, and I think time will show that that will attract higher rates.

So you see that market as pretty well positioned from a supply/demand balance and keeping rates kind of where they are here with recent fixtures?

Well recent fixtures for that class of rig depending on the sector you look at have been in the 120 to 150 range, unless it was a North Sea type high spec unit and they have been higher.

Our next question comes from Kurt Hallead with RBS Capital Markets.

I'm just curious as to what exactly are some of the benchmarks that we should be looking for as it relates to the situation in the Gulf of Mexico? I know you got the Presidential Commission out there. You got the drilling moratorium that's put in place. You got the district and appeals courts pretty much saying the moratorium is not really relevant. So is the industry waiting on the presidential commission findings or are they waiting till the end of November when the moratorium ends? Can you give us some things that you guys are trying to do to read the tea leaves to determine what's going to happen next?

Kurt, that's a great question. This is one of those things, the more you chew it the bigger it gets. We're doing a lot of things; the industry we included have an active dialog with Washington on many fronts in many levels and many places. There is a deepwater coalition that is much like the shallow water coalition that lobbied to try to get the shallow water rigs released for operations early on in this episode. API, IDC, all kinds of industry groups are working this. In the meantime we are monitoring the current state of rules, the notice to leaseholders to come out that affect our equipment, and engineering, and pricing and evaluating the consistency with how we fit and how we match up with what it's going to take to plan. And then we moderate the rhetoric, I mean the best move I’ve heard in a long time is when after the lawsuit, the court overturned the moratorium and then that was upheld on appeal. And then when the second moratorium came up, they actually put an end date to it. So the first time the moratorium was mentioned, they said, let's not pause for the Presidential Commission. Well, the Presidential Commission didn’t meet until about a week ago. So if we had to wait on those people that bunch of industry experts to evaluate our industry. They just met. So I don’t know when six months runs to. But at least on the second go round they out an end date to it. The end of November or sooner is what they’re now saying. We’re watching a myriad of things. I think of you read the tea leaves, the political outfall or outcry as a result of the moratorium has been much stronger than I think anybody…

Okay. And I don't know if you guys had seen, but there is something this morning about Pemex potentially upping their budget for next year, a significant 54%. Obviously what they submit to the finance ministry and what actually gets approved could be two different things. But getting early read or any read through on what that may mean for your jackup rigs going out into 2011?

Let Roger add to this. I mean obviously it's a good news. Let me go back to where (Robin's) brought up a point about the High-Spec market. And it appears to be, and there's a lot of speculation. A couple of people have called the high-spec jackup market as being headed way up and off to the races. That coupled with a rise in the budget in Pemex, all bodes well for us. Pemex went out for this age restriction that scared everybody to death, it hurt our stock. And we're a large provider of premium equipment to Pemex. And it scared everybody dramatically, and they're afraid, "Oh, my god, they're going to legislate out, with all the fleet." Well that didn't happen, they only got very few bidders. And as Roger pointed out, not only few bidders one of them was now not evidently going to deliver the rigs. So if those rates go up and those rigs get higher demand that means Pemex is not going to have the excess they had hoped. And that all bodes well for us. The fact that they are going to raise their budget, and if they don't continue to contract rigs through the end of the year, I think they'll be down to about 14 or 15 rigs, if they don't do something. All that means is the prospects for our fleet is good. So I had not heard that news, but I'm delighted to hear it. And I would think that the benefits of that will accrue our jackup fleet. And I'll ask Roger, if he's got anything to add to that.

We understand that Pemex will be going out to bid shortly. And it sounds like it could be for 21 rigs for February startup. And if you look back over the last period, if we go back and look at the last two years, Pemex has averaged more than 30 rigs over that period, and the prior two years it was round 27 rigs. The situation they've got right now is they're at around 24-25 rigs, and if they're unable to work the direct assignments through the system, we might see that number drop down to below 20. And over a similar period of the possible years, production has declined some 600,000 barrels a day. So I think what we're going to see in Mexico is they're going to need a lot more rigs, they're going to have to kind of shore up their systems. If you just add those 21 rigs to where the rig count might be at that time, you're probably looking at a number around mid 30s, 35 rigs.

Our next question comes from the line of Roger Read with Natexis.

I just wanted to ask you, and this may get back to Roger's comments in the beginning about sort of the lack of visibility in the deepwater markets. Yesterday on the large integrated service companies call, they said they thought things might, in the international market, take until the fourth quarter to sort of clean up. Customers were back looking at their commitments that they wanted to make the large projects. Are you seeing some of that? Are you seeing any sort of maybe bidding activity, requests for proposals on rigs that would give you an idea that, internationally at least in the mid water and deepwater markets, we could see some commitments coming through on either, rigs that were coming up for bid or for some of the spare capacity in the Gulf deepwater?

Roger, I think the answer is, yes. And one of the things that you would look at is Shell just committed for 20 rig years of deepwater work. And that's for a global portfolio. And they did that during this whole Macondo period. And so I think you should take that as one indicator that the super majors have robust programs worldwide. And they will be arranging that portfolios to be able to prosecute.

Well, in the second part of that question, are you seeing, from companies other than Shell, in other words, other than what we know about and where commitments have been made, but other sort of companies just sort of trying to figure out what they are going to do six or 12 months from now in terms of rigs that you are bidding, I mean the Amos Runner is an example.

I would say that during the period of the Macondo exercise that we've been going through during this quarter, what we're seeing internationally is what is exactly what we saw internationally before. We haven't seen anybody change their behaviors really to speak off on the international front as a result of what's going on here. Those that were out looking for rigs are still looking for rigs, those that were not are still quite, and those that had programs that were continuing to develop are still continuing to develop those programs. I think the question you're asking or may be asking has somebody jumped up and said as a result of what's going on, are they seeing an opportunity for fire sale potentially to move rig out of the Gulf of Mexico, because they think they will get a cheaper rate; and frankly, I'm not aware of any of that. What we're seeing outside the Gulf of Mexico largely is normal course of business step. Right now, people are prosecuting their budgets as they plan them last year. They're going through whatever relative changes they may have as a result of product price fluctuations and how they tweak and ebb and flow their budgets. And the net outfall of what's happened outside the U.S. Gulf of Mexico as a result of events in the U.S. Gulf of Mexico is immaterial. That's how I would characterize it. It's probably just the obvious that operators that have deepwater equipment in the Gulf of Mexico are watching very closely to see whether they have to redeploy it. And if they do, that's probably going to impact the total demand.

Okay, that's fair. I wasn't really trying to insinuate a fire sale, but more so that, for example, if the most recent rigs that have been going to work are the older peak rigs, let's say, north of 500,000, new rates are let's say somewhere between 3.50 and 4.25 where you're seeing some projects that previously might have been skipped with rates above 0.5 million a day, be more interesting to operators and that they are now willing to say, "If we could get A rig from you, three-year commitment, 3.75, does that make them more willing to bid on rigs than projects essentially resurrected that otherwise might not have occurred due to either availability or cost?

No, I don't think our newbuild ships are with the bonus are 4.50s or so depending on how the performance goes. That's not materially often the peak of the low-5s or mid-5s. And so I don't think anybody has refined their economics that tight. Keep in mind all of it is still at a fairly robust price, and most of you would argue that all often oil is a result of the euro, not of anything else. At 80 hours a barrel, almost anything works. At 72 or 73 or 75, almost everything works. So it's not the modest reduction, if there's been a reduction in deepwater rates, is not enough to just drive demand to a point that you're going to see a big run on activity.

Our next question comes from the line of Robert Mackenzie with FBR Capital Markets.

My question comes back to, I guess, a derivative of the Macondo issue, David. I'm wondering how you're thinking first about how much and what kind of insurance you guys are going to want to hold, particularly in the U.S. Gulf of Mexico in the wake of this tragedy; and secondarily, how you think about working or contracting your rigs to smaller or mid-sized operators going forward.

We're always the first up on renewal. Our renewal was done in March for our P&I piece and the hull and machinery piece. And we did not then and we have not now really contemplated any change in our insurance profile. I think we're adequately insured and appropriately insured for the risk that we assumed under the contract. And I don't really see that that's going to be materially different going forward. So I don't at this point anticipate any changes in how we contract our services. We don't have anybody in the Gulf of Mexico who is not on our approved customer list that wasn't on our approved customer list before. That's the question. It will depend on how things evolve. If the U.S. government says they're going to raise $35 million cap to unlimited and you take a $2 billion or $3 billion or $5 billion market cap E&P company who is putting everything on the line, on every well, that may change their profile. I think largely that's going to be self-regulating depending on how the government responds and what kind of risk our customers take. We don't assume much liability or we don't assume really any liability for oil emanating from the wellbore under normal operations. So that's not a risk that we assume, and that's not a risk that we would plan to assume. So we'll have to see how the environment looks. But as it is now, our customer base is still our customer base, and we'll see how they behave and what the government does.

And a follow-up to that is you guys have arguably one of the industry's best safety records in the wake of Macondo. What, if any, changes have you guys made to your procedures, including potentially stopping customer activities if necessary to how you run the rigs?

Well, shutting down an operator that's doing something that we don't agree with is not new here. It's something that we exercise vigorously whenever we think it's appropriate. Frankly, we haven't done a lot to our safety culture. We have reinforced it. And as I said in my opening remarks, we already have safety cases in all the floaters operating in the Gulf of Mexico. We have a culture in this company of operating excellence and safety that we didn't make up yesterday. It's something that's been developed throughout our 90-year history. And I am very, very proud to say it runs throughout the fleet. You land on one of our rigs in the Middle East, Mexico, North Sea, it doesn't really matter, you get the same induction, the same treatment and the same type of environment that you do on any rig anywhere in the world. An operational consistency and a good safety culture is something that's been fostered and developed and shared throughout this company forever. So we've reinforced it to our hands. We talked to our customers, we talk to our supervisors to make sure that they understand that the full support of management and they had the full support of everybody involved. And if there is something that's unsafe, it's not their right to shut it down, it's their obligation. And that's not new here. So all we've done really is to reinforce what we believe we already had.

Our next question comes from Alan Laws with BMO Capital Markets.

The first thing I wanted to say, Dave, just wanted to say a great job in a very fluid Gulf of Mexico backdrop of preserving shareholder value. I think you guys have done a great job. For my question, though, I'd like to ask this. Hopefully it won't violate any of these rules here. But you've made solid investments in newbuild rigs and upgrades over the last two years and are still doing that, and you're absorbing ongoing construction projects in your recent acquisition. Can you discuss your views on investment and returns as it applies to the fleet additions, the delivered and undelivered ones, and the construction risks that you may see out there? I don't know if this is kind of a compound question, but maybe address if there has been any changes to your hurdle rates or maybe an expanded range of competence intervals for expected costs and returns.

Well, we've never really discussed our hurdle rates. We've always talked about value and long-term value. I think the Frontier opportunity for us in conjunction with the Shell endorsement and commitment is exactly what we've been talking about for at least the last four years. We have always talked about wanting to add rigs that add long-term benefits to shareholders. We have in the face of building big part of the cash returned some of that cash. In fact, we returned a lot of cash through share buybacks and through some dividends. As you know, the shareholders approved another dividend going forward in the place of regular. So we've been active on all fronts. As you know, Alan, and I hope everybody knows, this business can be fairly volatile, as the last quarter has blaringly demonstrated. By adding almost 50 years of backlog with a company of the quality of Shell, it provides a base of operations that carries through the volatility. This would almost double the fleet backlog through ebbs and flows and peaks and valleys as effectively at no risk deal. All it does is provide return on earnings to shareholders over the next 10 years. For us, with the opportunity to do this deal and layer on all the backlog and all of the support that Shell has given us, it's a no brainer for us. It's a great opportunity to add floaters with a lot of backlog, with a very high-quality customer and under very, very secured contracts for way into the future. So it is a great investment. And as I said, I think it's exactly what we've been talking about all long. People have talked about age of the fleet and this and that. The scene expectedly is the only thing on that rig…

That actually helps a lot, Dave. So you model it more on a pool basis, not an individual project basis?

Somebody asked me on the call on 28th that the Duchess was a core rig. I mean if somebody asked me a while ago what are the prospects of the rigs working, it's been working. Is it going to be working for the next 90 years, no history? I doubt it. But it's a making a very good dayrate right now. Its uptime over the last several years is extraordinary. So is there a particular niche in which it ought to work? Yes. Is there a risk that we could stack it? Sure. But that's not the rig's history. And our expectation is that if Globetrotter is going for full 10%-plus or 15% bonus and newbuilds are going to 14%-plus or 15% bonus, we will find a spot to work with Duchess at a rate that makes sense. So this collectively is a great opportunity for us and our shareholders, I believe.

Our final question comes from the line of Dan Boyd with Goldman Sachs.

Just a follow-up on the 21, I guess, tenders that are potentially coming out of Pemex. Any indication if they'll remove that age restriction? It sounds like they might have to.

We can't give you a direct answer to that question. We think 18 of the units are going to be 300-foot capability and three of them will be 350. We don't expect to see an age restriction per se on the 300-foot.

I know you won't negotiate with your customers on the call. But on the Paul Romano, can you just give us an indication of have you been able to bid that into existing tenders or are you looking at private negotiations, and any indication of regions of the world, maybe duration of contracts without going into rate?

I'll probably give you a no. Dan, we're doing both. I mean we are having direct conversations and there are bidding opportunities. But given that lots of people are looking at the opportunities of exiting the rigs out of the Gulf of Mexico, it's just not appropriate to get into detail.

Ladies and gentlemen, we want to thank you for joining the call this morning, and we will look forward to seeing you on the road and then again at our third quarter earnings call in October. Thank you and you may disconnect.

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