Diamond Offshore Drilling Inc (DO) 2017 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Q3 2017 Diamond Offshore Drilling Earnings Conference Call. (Operator Instructions) As a reminder, this conference call is being recorded.

I would now like to introduce your host for today's conference, Mr. Samir Ali, Senior Director of Investor Relations. Sir, you may begin.

Thank you, Danielle. Good morning, everyone, and thank you for joining us. With me on the call today are Marc Edwards, President and Chief Executive Officer; Ron Woll, Senior Vice President and Chief Commercial Officer; and Kelly Youngblood, Senior Vice President and Chief Financial Officer.

Before we begin our remarks, I remind you that the information reported on this call speaks only as of today, and therefore, you're advised that time-sensitive information may no longer be accurate at the time of any replay of the call.

In addition, certain statements made during this call may be forward-looking in nature. Those statements are based on our current expectations and include known and unknown risks and uncertainties, many of which we're unable to predict or control, that may cause our actual results or performance to differ materially for -- from any future results or performance expressed or implied by these statements. These risks and uncertainties include the risk factors disclosed in our filings with the SEC, included in our 10-K and 10-Q filings.

Further, we expressly disclaim any obligation to update or revise any forward-looking statements. Please refer to the disclosure regarding forward-looking statements incorporated in our press release issued earlier today, and please note that the contents of our call today are covered by that disclosure.

We will be referencing non-GAAP figures on our call today. Please find the reconciliation to GAAP financials in our press release.

And now, I'll turn the call over to Marc.

Thank you, Samir. Good morning, everyone, and thank you for participating on our call today.

For third quarter of 2017, Diamond Offshore announced earnings of $0.08 per diluted share, which includes an after-tax loss of $0.17 related to our recent successful debt refinancing. Excluding this transaction, our adjusted third quarter 2017 results of $0.25 compared favorably to our third quarter 2016 results of $0.10 per share.

The Ocean BlackRhino and Ocean GreatWhite, having commenced their contracts earlier this year, were large drivers of this increase in year-over-year earnings. But I also want to highlight that our ability to high grade operations and deliver industry-leading up-time greatly influenced these improved results.

Diamond Offshore continues to focus on superior operations for our clients as we progress through this downturn. This effort has allowed us to achieve an operating efficiency, excluding planned downtime of 98.5% in the third quarter, making it the highest operating efficiency quarter since I joined Diamond Offshore in 2014.

This operational improvement has translated into real savings for our clients. Case in point, one of our premier 6th-generation drillships recently drilled and completed a well 47 days ahead of schedule.

Additionally, one of our drillships delivered operational efficiency this quarter, very close to 100%, with only 7 hours of downtime in the entire quarter. Our ability to bring wells in ahead of schedule on reduced total well cost is a win for both our clients and Diamond Offshore as we work towards making offshore drilling more efficient.

Before I provide a fleet update, I would like to briefly discuss our recent bond offering. Given the continued uncertainty in the offshore drilling market, it was prudent to extend our already best-in-class liquidity runway and bolster our balance sheet.

We have no remaining significant planned capital expenditures, including new build capital, and now have an attractive debt profile as our next bond maturity is not until 2023, with more than half of all maturities in 2039 and beyond. In other words, over 20 years from now. We also have significant untapped borrowing capacity available from our $1.5 billion revolver.

Now turning to our moored rig fleet. We are pleased to announce that we have secured additional term for 2 rigs. The first for the Ocean Apex in Australia and the second for the Ocean Patriot in the North Sea.

The Ocean Apex was extended by Woodside with an additional well added to the current program, taking the estimated contract expiry to early second quarter 2018. Recall that the rig has been on contract with Woodside since May 2016, and the additional well was allocated to the Apex based on its track record for delivering wells ahead of schedule.

The Ocean Patriot also secured a new contract with Shell in the North Sea. The rig is now completing its current term work with Shell and will then be mobilized to undergo a special survey and top-drive upgrade.

Post-upgrade, it will begin a drilling campaign from March 2018 to May 2018, after which, the rig will be mobilized for her contract with Apache. Our marketing team was able to fill the schedule gap and was able to do so with a contract at a sustainable margin. Again, this is on the back of the solid reputation that the rig earned during the primary term of the Shell contract.

Here in the Gulf of Mexico, the cold-stacked Ocean Onyx was recently loaded onto a heavy lift to begin her transit towards Asia, where we believe the market will be more conducive to putting the rig back to work. We were able to secure a vessel that was returning without cargo, which allowed us to take advantage of extremely favorable transit rates. At this time, we are exploring a few opportunities for the rig, but do not have an imminent plan to reactivate her upon arrival in Asia.

And a few words from the Ocean Valor. The contract status has not changed from last quarter. The court-enforced injunction remains in place, and we continue to invoice and collect the contractual standby rate. However, we continue to look for ways to work with our clients and are always open to mutually beneficial solutions. To this end, both the Diamond and Petrobras teams are working tirelessly to resolve this issue in a manner that is a win for both parties.

So allow me to provide some general commentary on the offshore drilling market. We here at Diamond are still not ready to call a bottom, as the number of contract rollovers in the next 12 months exceeds new fixture opportunities currently in the pipeline. Utilization, certainly for 6th-generation assets, will track down another peg, but we do believe we have some visibility as to what the trough may look like. The number of tenders has increased, albeit from a very low platform, and customer inquiries have picked up, although also starting from a low base. Yet contract durations for the most part remain short, and pricing is very challenged.

A handful of customers continue to show opportunistic-buying tendencies trying to secure long-term contracts at low rates. Much of the increase in activity appears to be in the moored category, not the depressed DP drillship market. We have long suggested that the most distressed asset category is that of the sixth-generation drillships.

Though we are not immune to this oversupplied market, our 4 sixth-generation DP drillships are contracted at very solid day rates until 2019 and beyond. And as we have previously explained, we have uniquely differentiated these assets through our Pressure Control by the Hour construct with the OEM. Our continuously improving operational performance is testimony to the benefits of this partnership.

We have also long maintained that our fleet mix is an advantage. We have spent approximately $1.5 billion upgrading our moored fleet over the past 5 years and found that from a tendering perspective, the most active areas are Australia and the North Sea, markets that are both primarily suited to moored assets.

Allow me to also restate that the new scope we are announcing today on these moored assets are at rates above cash breakeven. For pricing to meaningfully recover, we believe that the industry will need to scrap additional dynamically positioned assets. We remain consistent in our belief that the market will bifurcate between those assets that are working and those that have been cold-stacked for a considerable period of time.

So with that, I will turn the call over to Kelly to discuss the financials for the quarter, and then I have some closing remarks. Kelly?

Thanks, Marc, and good morning, everyone. As mentioned earlier, we took action during the quarter to proactively extend our liquidity runway by refinancing our 2019 senior notes with newly issued 2025 senior notes. These new 8-year unsecured notes were issued with a 7.875% coupon rate and will mature in the third quarter of 2025.

Cost associated with the retirement of the 2019 notes resulted in a third quarter pre-tax charge of $35 million or $0.17 per share after tax. There is also an additional $10 million of new debt issuance costs that we will be amortizing over the term of the new senior notes. As a result of this transaction, our next debt maturity is now not until 2023 for $250 million.

So today, as we look at our liquidity runway, with an undrawn $1.5 billion revolver that matures late 2020, no new build capital commitments and over 60% of our debt maturities dated 2039 and beyond, we are in a very enviable position relative to our peer group.

Now turning to our third quarter 2017 results. From a GAAP perspective, we reported after-tax net income of $11 million or $0.08 per share for the third quarter of 2017. Adjusting for the $0.17 impact for the costs associated with the debt transaction, our earnings totaled $0.25 per share.

Contract drilling revenues of $358 million for the third quarter represented a sequential decline of 9%, driven primarily by 2 rigs, the Ocean Victory and Ocean Courage. If you recall, we announced on our last call that the Ocean Victory completed her contract at the end of the second quarter, driving the majority of the revenue decline during the third quarter.

Also contributing to the sequential decline was the Ocean Courage, which was out of service for over half of the third quarter for planned BOP upgrades. These decreases were partially offset by a full quarter of operations for the Ocean Monarch and continued improvement in our operational efficiency metrics.

Contract drilling expenses of $198 million was in line with the prior quarter and our most recent guided range of approximately $200 million. A full quarter of operations for the Ocean Monarch resulted in higher cost for the third quarter, but this increase was mostly offset by the Ocean Victory coming off contract at the end of the second quarter.

Depreciation and G&A costs were all within range of our previous guidance, and interest expense was also within our revised guidance provided after our new debt issuance. We also experienced a net income tax benefit during the quarter of $15 million, which was due to the mix of our domestic and international earnings, inclusive of the loss on extinguishment of debt recognized in the third quarter.

Now moving on to fourth quarter guidance. We expect operating expenses for the quarter to be between $205 million and $210 million. The increase quarter-over-quarter is driven by a few factors. First, there's a special survey in top-drive upgrade planned for the Ocean Patriot. Diamond has historically expensed special survey cost and will continue this practice going forward.

Next, we have 2 mobilizations planned during the quarter. The Ocean Scepter will be returning to the U.S. side of the Gulf of Mexico and, as discussed by Marc, the Ocean Onyx is moving to Asia where the market is seeing higher tendering demand.

Given that both rigs are not being moved for a specific contract, our practice is to expense both mobilizations. We estimate depreciation expense to be approximately $83 million to $85 million for the fourth quarter of 2017, in line with our third quarter run rate.

G&A costs are expected to be approximately $17 million to $19 million in the fourth quarter, also in line with our recent run rate. Interest expense on our current debt and expected borrowings on our bank line of credit is projected to be approximately $29 million in the fourth quarter. The small increase quarter-over-quarter is to reflect the full quarter impact of the higher interest rate on our new 2025 senior notes.

We anticipate our effective tax rate to remain low in the fourth quarter, likely coming in at a single-digit percentage or lower, due to the mix of our foreign and domestic earnings. Of course, the rate may fluctuate up or down based on a variety of factors including, but not limited to, changes of geographic mix of earnings as well as tax assessments, settlements or movements in exchange rates.

We expect our capital expenditures to be approximately $125 million for the year. This was a decrease from our previous expectations as some projects have shifted into 2018, and we also continue to rationalize our spend, causing certain projects to be deferred or canceled. For more detail related to projections of currently scheduled downtime on all of our rigs, please refer to our quarterly Rig Status Report that we filed this morning.

And with that, I'll turn it back to Marc.

Thanks, Kelly. Here at Diamond, we have proactively strengthened our balance sheet and increased liquidity. With the refinancing of our 2019 bonds, we are the only major driller that does not have a bond maturity between now and 2023. And of course, our revolver remains untapped.

We will continue to look for ways to drive the industry forward, may it be through innovative technology, improved operational efficiency or exercising our financial strength, while at the same time, we remain focused on preparing the company for sustainable success when the market does recover.

And with that, I will now turn the call over for questions and answers.

(Operator Instructions) And our first question comes from the line of James West from Evercore ISI.

Marc, I know in the recent quarters, you've been hesitant to really look deeply into M&A. I'm thinking that pricing was -- for rigs was still too -- or asset values were still too high. We see 2 deals go through -- or with 1 go through and another 1 pending, but it seems like there's other conversations happening in the market. Has your thinking changed at all on M&A at this point? Are you more interested or is it still really not for Diamond?

Well, it's not correct, James, to say that it's not for Diamond. We, as always and as I've said in the past, we have -- the management team here at Diamond are always looking at capital efficiency moving forward and the allocation of that capital. And really, it's down to the math of the economics around any of these deals. So we've got a number of options on the table. We've explained those in the past. It can include a distressed asset purchase, it can include participating in M&A and it can be -- and it can include investing in innovative new technology moving forward. But at this moment in time, we are not in any rush to transact. And again, as I've said before, one of the basic principles of value creation is knowing the true value of these assets or companies and then being prepared to take action when the time is right. So I think that's the best way of looking at it and explaining our position. We are looking at the market, and we will be opportunistic as we move through this downturn.

Okay. Okay, great. And then I know you don't want to call the bottom in the cycle yet or you're not willing to call the bottom of the cycle yet. What's the trigger that you would see that you think would allow you to call a bottom? Is it that retirement of sixth-gen rigs? Is it just more tendering activity? I mean, what are you looking for to be able to put a stake on the ground and say, "Okay, we bottomed out."

I think we got to, first, see utilization stabilized. As I mentioned in my prepared remarks here, we're still going to see utilization certainly in the sixth-generation fleet track down over the next few quarters. Clearly, the number of opportunities within the pipeline is less than the number of contract rollovers that we see over the next 12 months certainly. So utilization needs to stabilize. But at the same time -- I think some of the more, let's say, older sixth-gen assets, as they remain stacked for a significant of time, I think, we've got to see those truly exit the market. One could suggest that the reactivation costs become a barrier to reentry in the market in the long term, which would then allow pricing to perhaps track back upwards, and then who knows, maybe we reach the level of pricing where it might become attractive for those assets to be reactivated. But I think that's quite some distance into the future. In the moored fleet, I think as we've already mentioned, that market, it seems to be fixing itself a lot faster than the DP fleet for example. So we've had close to 100 assets stacked. The vast majority of those are in the moored fleet. And we see more activity in terms of tendering in that sector. Certainly, in the 2 geographies that I've already mentioned, Australia and the North Sea. And again, as we've stated in our call here, we're able to take assets, third- and fourth-generation assets and put them to work at rates that are meaningfully above cash breakeven. So it's a combination of both that you mentioned there. I think we've got to see more scrapping, and we've definitely got to see more activity in the tendering space. We've got to see our clients become more active in sanctioning projects, bringing them back over the horizon so that demand for these deepwater assets increases as well.

And our next question comes from the line of Ian MacPherson from Simmons.

Marc, that was a remarkable comment about the -- I think you said you beat your drilling curve with one of the black ships by 47 days. Could you elaborate on that one? Maybe compare it to what the AFE entails for drilling time and -- we're hearing more of that, but I'd like to hear maybe if the trend is so pronounced that it dovetails into new contract structures that are more performance-based for the industry and for Diamond going forward.

Yes. It's somewhat of a double-edged sword, of course, because as you accelerate wells on a drilling program, if you're on a fixed scheduled work, it does mean that, that scope might come to an end ahead of schedule. But of course, for our critical sixth-generation assets, all those contract are time-based and not a well-based or scope-based. But if you're looking at spread costs, let's say, spread costs have knocked them down to $800,000 or close to $1 million. That 47 days accelerating the well is closer to, you could say, $40 million or $50 million of savings to the client. And that's quite appreciable in anybody's world. And this was part of our strategy from well over 2 years ago when we decided to go down this Pressure Control by the Hour construct, drive efficiencies into offshore drilling by taking out unnecessary nonproductive time, especially if it's related to the stack. And again, as I said in my prepared remarks, we're now in our second -- well into our second year of this Pressure Control by the Hour construct. And one of our rigs here in the Gulf of Mexico had only 6 hours of downtime in 90 days, and none of that associated with the stack, the subsea stack. So we're making considerable advances in eliminating nonproductive time throughout our fleet. We came in at 98.4% when you take out the unplanned downtime for the Courage -- sorry, the planned downtime for the Courage. So we are making significant strides in driving efficiency through process gains to offshore drilling, and its savings are material to our clients.

Yes, that -- it's incredible. And, I guess, the follow-up to the question is really what that means with regard to how you approach your business, from either a performance-based contract structure or a day rate business going forward, and whether you have had sufficient engagement in the contracting process yet to really explore how you get paid for a better performance because really most of your contracting lately has been well-to-well and on your moored rigs, but do you think that, that's going to be the future of contracting when the black ships roll onto their next contracts?

Well, I'll pass it over to Ron in a minute to answer the question specifically. But to your point here, the -- one of the reasons we embarked on this Pressure Control by the Hour construct was to differentiate our drillships, the sixth-gen assets, in a market that was significantly oversupplied. We wanted to push into the top of the deli line in terms of attractiveness. And we thought that, that's the best way to do this. It was actually to eliminate this nonproductive time. Nonproductive time, in any industry, is a burden on the end user. So in terms of being able to differentiate that, I think, we're beginning to see a tangible and material differentiation moving forward. But as it relates as to how we translate that into contracting efforts moving forward, let me just flip it to Ron.

Good morning, Ian. It's Ron here. Yes, I think the question makes a lot of sense. And there is a general, I think, trend for operators to favor, I think, performance-based consideration and contracts away from kind of legacy models. And we think -- for our drillships, I think that works to our advantage. As we think about the upcoming contracting cycle that include our drillships, the fact that our black ships have had, what I'd call, extremely kind of deep and positive resumes, kind of experience that is very rich and challenging. I mean, these rigs have worked at some pretty -- in some pretty tough sort of drilling and completion programs, well depths over 32,000 feet. So they've really been working at the, call it, the deep end of the pool, if you will. We know that the operators, they do look for it, it's proven performance, not just of the hardware, too, but also the crews themselves in terms of how, I think, closely knit our crews are and how well that translates into performance for the operators. That does make sense. And so we know they do stress the premium value that comes familiar in successful kind of crew complement can bring. What I'd also say as we think about recontracting with the black ships, by the time these drillships come up for recontracting, to Marc's point, they will have had 2 to 3 years of Pressure Control by the Hour behind them. Now although the drillship market itself may be commoditized, I would argue, and I think operators will recognize that the reliability engine behind our BOPs on the drillships, that's not a commodity, that's quite distinctive. So I think the general emphasis towards performance, I think, will work to our favor long term.

And specifically, to your point, we will be prepared to stand behind these numbers. It's very important that when you go back and transact with clients and show a performance schedule that perhaps is differentiated, it's also important that we go with our client and financially stand behind those numbers.

Very good. Well, yes, well done there. And I actually do have some more for Kelly, but I'll re-queue. But thanks for the help with that topic.

And our next question comes from the line of Jud Bailey, Wells Fargo.

Question, you mentioned Onyx, moving that to Southeast Asia for work prospects. I wonder, as you're having discussions with customers for 2018 programs, it sounds like the Onyx has the possibility of getting some work. What's -- how are you thinking about your cold-stacked rigs? And specifically, do you have a number in mind that would be fair to think about that has a possibility that you could reactivate or is the Onyx kind of the only one? Or are there others that would seem like a reasonable possibility that could be reactivated at some point in the next, I don't know, 12 to 18 months based on what you're hearing from customers?

Jud, this is Ron. So just to reemphasize, the Onyx is moving out to Asia because we think that's a good market in which the rig can compete. And we've caught a cheap ride to get there. So there's some just on a pure kind of opportunistic kind of move there on our part. In terms of the reactivation in general, I would say that there's a few things that we look at. We're going to focus on rigs that have a long-term future for us, obviously. A good match in operative program. It has to have sufficient, I think, initial term for us to get going because utilization is going to matter. And I think that the Onyx is one of them. I think, at least probably 2 rigs that I'd call top of mind for us as we think about reactivation. I'd put both the Onyx and the Endeavor probably in a top of mind kind of class. But clearly, the utilization of those assets will matter a lot. So we'll make those reactivation choices here with great care. But right now, we do think that for those, I think, desirable kind of moored rigs, the Onyx is a good example. An operator who has either some efficient kind of exploration needs or good conventional development programs, the Onyx is a very good tool. The Endeavor, also again top of mind when it comes to reactivation. She's got what I'd call high-capacity drilling capability, large deck space. We're having what I'd described as sustained interest from operators in her status. So the reactivation choice is one that we'll make with for a great care when it comes to the utilization and the cost of bringing them back online.

And gentlemen, let's not forget that uniquely in our industry today, we sit here with all of our sixth-generation assets contracted at very good day rates. So when it comes to the sixth-generation feet, reactivation at this stage is not an issue for us because they're all already working.

Yes. So I guess, Ron, if I could follow up on that. So as you kind of outlined your criteria and as you're thinking about it, do you think it -- based on what you're hearing from customers and seeing in the market, do you think the Onyx and the Endeavor would have a reasonable possibility of getting reactivated based on what your criteria is and what you're hearing from customers?

Yes. So we're not, of course, announcing a reactivation sort of choice today or even a schedule for that. But I would put them at sort of the front of the queue for us as we think about rigs that have a long-term future, have reasonable reactivation sort of costs and as well as a combination of high desirability from operators. Those 2 rigs are, what I'd call, top of mind.

Okay. All right, great. And if I could, my follow-up would be for Kelly. I think, Kelly, you guided on OpEx, I think, $205 million to $210 million and that includes the 2 mobilizations. Can you give us a sense of what kind of dollar impact of the 2 mobs are? And how, I guess, transitory in nature some of the moving pieces are for the fourth quarter cost guidance?

Right. So Jud, there's actually 3 moving parts there. I mean, I would say, the cost that's driving a large percentage of that increase quarter-over-quarter is the Patriot. The survey cost because we expensed that cost. And that's going to be, without giving specifics, kind of $5 million to $10 million range, somewhere in that area. The 2 mobilizations, if you look at those 2 combined, it's going to be in a similar cost to what the Patriot special survey cost will be. So I think that will get you in the ballpark.

And our next question comes from Sean Meakim from JPMorgan.

Marc, can you give a sense of the 2 wins during the quarter? Those were negotiated directly or if they're part of a (inaudible) process?

They were negotiated directly based on performance of those 2 assets.

Okay. And then thinking about prospects for some of the moored ships, the Valiant, the Guardian and the Apex. Can you talk about the opportunities there? Is it mostly well to well work that you're expecting? Or you mentioned some operators being more opportunistic on something of a more multi-year fashion. Have you seen kind of those opportunities as well?

This is Ron. So the rigs you mentioned there, Apex, Valiant, Guardian, those certainly are rigs that we're pretty, I think, strongly focused on for recontracting. In terms of the nature of the work that we see, the nature of the opportunity that we see ahead for those rigs, all those rigs have, what I'd call, sort of live opportunities that we're examining for them. And I think it's a combination. I would describe the opportunity set as bimodal. On the one hand, you have some shorter-term programs that are just looked at as short-term efficient opportunities for those rigs. On the flip side, on the other end of the curve, you do see some operators looking at 2017 day rates and thinking, "This would be a good time to lock in a long-term program." And so then you have longer-term scope, kind of get that locked down with the 2017 rates. You see a couple of different sort of behavior types. But certainly, in the Apex, the Guardian, the Valiant, those are 3 rigs with a lot of effort being spent on them. And candidly, they come off, all of them, with good resumes, good experiences, good references from customers on the work they've done. So we are pretty optimistic that we'll see more term on those 3 rigs.

And our next question comes from the line of Greg Lewis from Crédit Suisse.

Ron, just as you look at the Endeavor and, I guess, all your stacked rigs for that matter are North Sea capable. Is there any thought of just looking at how the North Sea fleet, your fleet, is positioned? Is there any thoughts beyond the Onyx and the Endeavor about squeezing in some more rigs into the North Sea just given the fact that pricing is -- that's the strongest mark that we're seeing in offshore?

Yes, it's a fair question. I like it. So we're not going to get into of course on this call kind of our fleet strategy moves ahead of time. But I think the point is as we look to rigs getting contracted, we'll look at sort of what's soaked up in the market versus what kind of capacity we'd like to have in the market to pursue new work. So as we lock up additional terms, additional rigs, I think the question of moving other rigs from out of the market into the North Sea is one that we kind of actively think about. And so the sequence of moves makes a lot of sense. I won't telegraph ahead kind of what rigs and when, but that dynamic is one we think a lot about. In the North Sea, I think, right now, compared to other markets offers a relative strength of contracting. And again, that's a relative term. But it is, I think, relatively better than other markets today.

Okay. Okay, great. And then, just, I guess, I'll just ask on the decision to move the Scepter back to the Gulf of Mexico, out of Mexico. Is -- could you remind me, is there any reason why that rig couldn't just be parked in Mexico for a little while, just given that it seems like that's where it's been pretty successful since it's been here?

Yes. This is Ron again. It's a question around cost efficiency, kind of where is the right place to have her sort of set up. Right now, she's doing well for Fieldwood here, but there's no, I think, follow-on work plan right there. And that's a pretty -- talk about rig surplus in the jack-up space in Mexico. There's a lot going on there. We think from a cost standpoint, it'd make more sense to have her sit tight on the U.S. side.

And our next question comes from the line of Haithum Nokta from Clarksons.

Marc, in the last conference call, you mentioned a pickup in term opportunities in deepwater that were starting in kind of late 2018 or early 2019. I was wondering kind of how that trend has played out over the last quarter, especially kind of with Brent now at $60, above $60 a barrel. How did those conversations kind of played out?

Good question. From our perspective, we haven't seen any change. We haven't seen a pickup in the number of term activities that we were talking about at the end of Q2. Those are still there. But again, it's -- from our perspective, it's nothing like we used to see. And any new term that's been put on the table, I think, in the last quarter, has been relatively short term and on a well-by-well basis. So there's no new significant opportunities just to specifically answer your question, that we're chasing right now that has term on it, understanding that majority of our fleet certainly -- or all of our sixth-gen assets are already contracted for another 2 years. So I don't think we've seen a material pickup in conversations that I'm having with clients around the world. Their objective remains the same in that current Brent is now close to $60. But they're looking to see some stability as it relates to -- and where you can, an element of predictability, too, in terms of where the oil price is, but it -- this is going to be a slow recovery that materializes over a number of years. It's not going to bounce back quickly in the next few quarters, that's for sure.

Okay. That's fair. And I guess just on the moored side, (inaudible) that there are still more opportunities there. How is the competitive landscape for that class of rig? I mean, obviously, there's been tons of scrapping in that market, but I mean, do you see a lot of competition from the smaller players or is it just kind of you and maybe 1 or 2 other big players that kind of hold (inaudible)?

Yes, this is Ron. In terms of the moored side, the competition is still pretty stiff. Even though I think, the surplus is probably stronger on the DP side. But there's no easy day on the moored side by comparison. And you look at -- although there may be, I think, fewer brands out there based on some post-M&A consolidation, but it's still the same rigs that we're competing against. So I can't say that we feel like we have an easy time in any market on the moored side. Pricing is still very competitive. You're seeing some deals done kind of at or around breakeven levels. Operators know they can get rigs cheap for long periods of time. So the surplus is not quite as strong, but still every job is one that's hard-fought along the way.

And our next question comes from the line of Eduardo Royes from Jefferies.

Marc, this one is for you. I'm curious to see how you can answer it. You guys for a while, I think, have sort of been the only one addressing the elephant in the room, which is that there's just way too many ultra-deepwater ships. I guess, I'd be curious if you fast-forward a couple of years, I'm sure you guys do a lot of market outlook and forecasting, recognizing you're not going to give away all the secrets. But I'd be curious, if you'd have to take a guess, how much of that ultra-deepwater drillship capacity probably doesn't come back? The market's obviously, I mean, the number of rigs is way bigger than even the total floater market today. So some perspective on how much of that you think ultimately ends up having to go.

Sure. So every year, we undertake a very detailed analysis of strategic options moving forward and, of course, incumbent upon that, we actually do quite a bit of crystal balling around utilization and day rates moving forward. And without giving too much away, we do think that the moored fleet or the moored cash (inaudible) does come back in terms of pricing before the ultra-deepwater fleet. Now come back, it does. There's no doubt in our mind. Demand for deepwater and ultra-deepwater, when you look at the supply and demand stacks for hydrocarbons, means that irrespective of where shale goes, there is an ultra-deepwater market. It's a question of timing as to when that comes back. And we don't think that it's, let's say, around the corner. Can we see it over the horizon? Yes, but it's not around the corner. Now that addresses the demand side of the equation, you've also got to address the supply side, of course. And we continue to maintain and always have done, that as assets sit, sea water is perhaps one of the most corrosive environments to store steel, we believe that the costs of reactivating a certain sixth-generation DP asset, certainly the earlier ones, that have to go through a 5-year [surveying] and have to, for example, have their riser recertified. The cost of recertified -- certifying riser is significant. It's in the tens of millions of dollars. And I don't think people are looking at that when they're looking at pure reactivation statistics so -- or costs. So we do see that it's certainly not exponential but it's probably linear, that for every year an asset sits there, being cold-stacked, the cost substantially goes up. So that it is ultimately a barrier to reentry. And this talks to the bifurcation that I've been speaking about in the market. And also, there's a client reluctance to the cost of -- to the client or the risk to the client of bringing an asset back that's been cold-stacked for 3 or 4 years is significant. The rig acceptance testing requirements, not just around the drilling package, but other elements of the vessel, past systems, PP systems, et cetera, et cetera, are not insignificant. And then, of course, you have to get through the rig acceptance testing as it relates to a BOP stack that's basically been sitting on the stump of a rig for 4 years. And of course, you can test the BOP stack on the stump of a rig. But when you actually submerge it and drop it down 3,000, 4,000 feet and then try and get a test on it there, it's a very different environment. And so you have to ask the question, is the client prepared to take on that risk when, for example, there might be another asset available that has either coming off a contract or came off a contract in the last 6 months or so. And from a client perspective, I know where I'd put my money and what rig I would contract. So I think ultimately, it's a no-brainer. Sixth-generation assets are going to be scrapped. And if you look at a couple of the vessels that went on the block over a year ago, it's very hard to see how those assets will actually go back into the market and drill and [angle] again.

Just a follow-up, maybe more, I guess either for you, Marc, or maybe Ron. I'm curious if for some of these contracts you've gotten maybe in the last year or so where, obviously, margins are pretty slim. I know you emphasized they're cash positive, but they're probably not that cash positive. Are we at a point now or could you argue maybe if nothing else with a slightly healthier oil price out there where you guys can -- if a customer really likes the rig, he's been impressed with it and he has an additional well or 2, is there any scenario under which you can try to at least push pricing a little bit and say, look, "You're not going to go get another guy's rig maybe for $10,000 less a day, It just doesn't make sense." I guess, the point is, is there any sort -- is it poor form, does it not work, are we not there yet? Do we really need to see a much tighter utilization in the market before you can even push pricing a little bit if it's just, like I said, one guy who likes the rig and he wants to do one more well or something like that?

Yes. This is Ron. Yes, the phrase kind of push pricing is one that's hard to get your head around in this market. I would say that part of what we saw here with the 2 contracts we talked about, in fact, I think, speaks to some of the same dynamics in your question, which is you have an operator that liked the rig, knew it performed. There is a switching cost, which operators comprehend. There's a performance sort of risk, which they comprehend. So there is some value beyond lowest-priced paid in the market for rigs, which they know and trust with a crew they know and trust and with a brand -- and a management they know and trust. So I think all those add up to -- it's worth something in the contracting process. I wouldn't say we push pricing as a result, but I think there is recognition that operators don't want to gamble their programs on unproven rigs, unproven crews and with companies that have gone through any number of different kinds of sort of strategic distractions. So I think for a lot of reasons, I think Diamond is a good selection for operators that know and have worked with us.

And our next question comes from the line of Rob MacKenzie of Iberia Capital.

I guess my question here is regarding the Ocean Valor. In the prepared remarks, you mentioned disclosing -- discussing a win-win outcome with a customer there, which, I think, one would normally take to mean (inaudible) to extend, but with the rig on a standby rate right now, that would seemingly, to me, be a little less likely. Can you comment on what kind of the win-win outcome there might look like for that rig?

I think in any conversations we have with our clients, what we look at are a long-term relationship, especially as it relates to Petrobras. We do know that Petrobras, having shrunk their fleet considerably, will be one of the largest deepwater players moving into the future for a considerable period of time. So it's always in our interest to work with our clients as it relates to optionality on certain contracts. Now having said that, it's important that any negotiation does include a win for us and our shareholders. So suffice to say, we're just negotiating with Petrobras at this moment in time as it relates to something that could extend the validity of the Valor contract. But it's too early, it's very early days, to suggest that we're close to a final resolution in that regard. So you'll get an update on that in the next earnings call or possibly before.

This concludes today's Q&A question. I would now like to turn the call back over to Marc Edwards for closing remarks.

So thank you for participating in the call today, and we collectively look to speaking with you again early next year.

Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program, and you may all disconnect. Everyone, have a great day.