Diamond Offshore Drilling Inc (DO) 2017 Q2 法說會逐字稿

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

I would now like to turn the call over to your host for today's conference, Samir Ali, Senior Director of Investor Relations and Corporate Development. Sir, you may begin.

Thank you, Bridget. 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 this 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 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 are covered by that disclosure.

We'll be referencing non-GAAP figures on our call today. Please find the reconciliation to GAAP financial on our website.

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

Thank you, Samir. Good morning, everyone, and thank you for joining us today.

For the second quarter of 2017, Diamond Offshore announced earnings per share of $0.12, which includes a $71 million impairment charge. Excluding this noncash charge, earnings per share for the quarter were $0.45. This compares to adjusted earnings per share of $0.16 in the second quarter of 2016. The year-over-year increase is driven primarily by new contracts that ramped up earlier this year, a substantial improvement in our operating performance and our continued focus on cost management.

The improvement in operational performance was seen across the fleet; however, I would like to highlight the 4 Black ships operating in the Gulf of Mexico. Recall that these rigs are under our unique-to-the-industry Pressure Control by the Hour construct initiated just over a year ago, the benefits of which are now beginning to kick in.

For example, the revenue efficiency on the Black ships has increased by over 300 basis points quarter-over-quarter, with BOP performance being a significant contributor. During the past quarter, we drilled a well in the Gulf of Mexico to 31,000 feet, 30% faster than the planned drilling schedule. Part of this efficiency increase is a result of the ongoing reliability improvement we are witnessing because of Pressure Control by the Hour.

The relationship with our partner, GE, continues to mature, and we are beginning to realize the benefits of the design-for-reliability ethos with critical component and system upgrades. Recall that when we decided to take the industry down this path, oil and gas operators applauded our unique efforts to innovate and drive efficiency gains in deepwater drilling. We are in the early innings of the partnership and although we are now seeing the value of these process enhancements through the high-grading of componentry, there's still room for improvement. We expect the uptime of our subsea stacks to further increase as the partnership matures in the coming years.

Now turning to our active fleet. We are pleased to announce that we have secured 2 new contracts for the Ocean Guardian. The first is with Azinor Catalyst in the North Sea beginning in August this year. After this contract, the rig will have a short break before it begins a new contract for Decipher Energy in February 2018. Both of these contracts, though modest in scope, demonstrate our ability to secure work for our early-generation rigs even in such a challenged contracting environment.

Moving across the globe, the Ocean Monarch recently completed her special survey ahead of schedule. In early June, the rig began her plug and abandonment program for BHP Billiton on the northwest shelf of Australia. After the rig completes its current program, it will be mobilized to the Bass Strait to begin working for Cooper Energy and then Origin Energy. The Monarch has consistently proven her ability to secure work in Australia, and we expect this trend to continue as the year progresses.

Lastly, in our fleet status report issued earlier today, we announced the decision to retire 5 rigs this quarter, of which 4 are moored rigs and 1 is dynamically positioned. Although we believe the moored rigs segment to be less distressed than the DP segment, we have further reviewed the useful life of the Princess, the Nomad, the Vanguard, the Baroness and the Alliance, and do not believe that the size of the future reactivation costs warrants keeping these assets in the fleet.

These rigs have been cold-stacked for some time now and although the holding costs are minimal, the combination of special surveys, required regulatory upgrades and other increasing reactivation costs imply that our future capital is best deployed elsewhere.

Before I move on to market commentary, I would like to highlight a few factors that differentiate Diamond Offshore. Our active fleet age of 10 years is well below the industry average of 14 years. Since 2010, we have spent over $6 billion on renewing the fleet and will continue to look for ways to deploy capital to the benefit of our customers and to maximize shareholder return. Diamond Offshore has no new build capital expenditures for the foreseeable future. Additionally, we were the first in the industry to recognize the coming downturn and took proactive steps to lower costs. And we remain committed to disciplined financial management.

So now allow me to give further color on the offshore drilling market. Our views on the market have not substantially changed since last quarter. However, although we are not calling a bottom, we do think that signs of a market inflection are close. We are witnessing an uptick in the number of contracting prospects, with certain clients offering term contracting opportunities, the likes of which have been absent from the market for a number of years. We have been consistent in our messaging that the asset category that is most distressed are the sixth-generation drillships, and we believe that this remains the case. Uniquely, however, all of our sixth-gen drillships are on long-term contracts through 2019 and beyond.

Since 2014, approximately 84 floaters have been scrapped, of which only 13 have been dynamically-positioned drillships. Nevertheless, we believe that the incremental cost of recontracting a long-term, cold-stacked drillship will help pricing recover for hot rigs in what will be, effectively, a bifurcated market between those rigs that are working and those that are cold-stacked.

We continue to spend a considerable amount of time and effort evaluating various strategic opportunities, including the acquisition of rigs and companies. However, at current prices, deal economics simply don't work for us. A top priority is to enhance our fleet, and we will continue to evaluate ways to accomplish this, but will act only when it is in the best interest of our stakeholders.

Additionally, we remain focused on exploring ways to lower total well cost for customers through industry-leading technology and processes. Necessity is the mother of innovation, and the fluid nature of oil prices has further reinforced the need to innovate. Bringing down the cost of offshore wells can be done by becoming more efficient with the rigs we have and the rigs of the future. Diamond Offshore is at the forefront of both of these trends, has become more efficient with our existing fleet, while also looking at new rig technologies to ensure we maintain our position as a premier deepwater driller.

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

Thanks, Marc. Before reviewing our quarterly results, I would like to begin by highlighting our strong balance sheet and liquidity position. Although it's not new information, I think it's worth reminding everyone of a few key points.

First, all of our sixth-generation fleet is under contract at rates $400,000 or more per day, resulting in almost $3 billion of backlog. Next, we have been very diligent in managing our operating cost, where we have seen a 50% reduction since 2014. We have no remaining new build CapEx commitments, and our maintenance CapEx continues to trend lower without compromising operational efficiency, where we have actually seen significant improvement.

Our undrawn revolving credit facility of $1.5 billion does not expire until 2020. And finally, our next debt maturity of $500 million is due in 2019, followed by a $250 million maturity in 2023. Altogether, we believe we are in a very enviable position when compared to our peer group.

Now moving on to our second quarter 2017 results. As Marc mentioned earlier, during the quarter, we took further actions to rationalize our fleet, allowing us to increase focus on our higher-quality deepwater assets. As a result, we elected to scrap 5 rigs this quarter and record a pretax noncash impairment charge of $71 million related specifically to 2 of our rigs. Although these rigs generated outstanding returns for the company historically, we believe it's not in the best interest of our shareholders to allocate any new capital towards their reactivation.

On a GAAP basis, we reported after tax net income of $16 million or $0.12 per share for the second quarter of 2017. Excluding the impairment charge, adjusted net income was $62 million or $0.45 per share compared to our first quarter 2017 results of $24 million or $0.17 per share.

Contract drilling revenues of $392 million for the second quarter represented a sequential increase of 8%, driven by a full operational quarter for the Ocean GreatWhite, Ocean BlackRhino and Ocean Scepter, all of which went on contract during Q1.

Additionally, our results benefited from the best operational efficiency quarter that we've seen in over a year. And although the Ocean Victory contract ended during Q2, it was finalized in early June compared to our previous expectation of late May.

The contract drilling expenses of $196 million came in slightly lower than our guidance primarily as a result of the delay in the demobilization of the Ocean Victory. The demobe, which completed in July, lowered our expected cost for the second quarter. Also, lower-than-expected repair cost and our relentless focus on cost management continues to favorably lower our run rate.

Depreciation, G&A cost and interest expense were all within the range of our previous guidance. We experienced a tax benefit during the quarter of $23 million, which was the net result of a favorable geographic mix of earnings and the tax benefit associated with the impairment charge taken this quarter.

Now allow me to provide some thoughts on a few key factors affecting our outlook for the rest of 2017. First, the Ocean Patriot will have a special survey in the fourth quarter of 2017. We are undertaking the survey in preparation for the rig's 2-year term contract with Apache beginning in June of 2018.

Next, we are currently scheduled to upgrade the BOP on the Ocean Courage in the third quarter. This will require approximately 45 days of our-of-service time for the rig, which is reflected on our rigs status report. I would note that this is a standard contractual requirement for legacy contracts in Brazil. 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.

Moving on to more specific items for the third quarter. We have a few moving parts affecting operating expense in the third quarter. The Ocean Guardian will begin a new contract with Azinor Catalyst, and we will incur a new amortization related to the recent mobilization of the Ocean Monarch. Mostly offsetting these increases will be lower costs related to the cold stacking of the Ocean Victory. So all in, we expect cost to be modestly higher than our current expense run rate.

We estimate depreciation expense to be approximately $85 million for the third quarter of 2017, consistent with the second quarter. G&A costs are expected to be approximately $17 million to $19 million in the third quarter, 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 $27 million in the third quarter.

We anticipate our effective tax rate to remain low for the remainder of the year, likely coming in at single-digit percentages 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 movement in exchange rates.

We continue to expect our capital expenditures to be approximately $145 million for the year. Although our run rate suggests a lower number, we have many expenditures weighted to the second half of the year, which is not uncommon. So we will continue to explore ways to maximize our best-in-class position as well as our financial strength, ensuring that Diamond is well placed for the eventual recovery.

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

Thank you, Kelly. Before we turn the call over for questions, I'd like to reiterate that there has been no change to our forward capital allocation strategy. We will continue to evaluate distressed asset purchases, consolidation opportunities and/or build the floating factory. Efficient capital allocation remains our core focus irrespective of market conditions, and we have not seen opportunities to date that would cause us to pull any levers at this stage.

We at Diamond offshore remain committed to disciplined financial management. In the last few years, Diamond Offshore has demonstrated our ability to innovate and drive thought leadership with a goal to improve efficiency and lower the cost of deepwater drilling.

And with that, I will open the call for questions.

(Operator Instructions) Our first question comes from the line of Gregory Lewis with Credit Suisse.

Marc, could you talk a little bit more about the progress you made with Pressure Control by the Hour this quarter? And just as we think about this going forward, are we kind of hitting our stride here? Or could this be something where you take a couple of steps forward and then you take a step or 2 backwards?

Sure. Good question, Greg. So we instituted the program on the Black ships. We started about a year ago. It was a stepped buildup. And as we transitioned across those 4 ships, all 4 at the beginning of this year, were then effectively into this program. It was a learning curve. It was a learning curve for the original equipment manufacturer, being GE. It was a learning curve for us as we transitioned some of the responsibilities over to them. We had dual backup on maintenance stock on the rig, et cetera, et cetera, as we transitioned. But it really was a new start for the original equipment manufacturer. So they had to pick up from effectively ground zero to be able to run with the systems and the capital upgrades, the equipment upgrades that we required from them. So there was a big learning curve on both sides. But nevertheless, I think we're through the -- that incubation period. And we're now moving forward, where we're truly seeing the benefits of this program materialize in terms of uptime. I'm not going to go into the specifics for competitive reasons as to what we're truly seeing here or indeed what kind of upgrades we've been doing, suffice to say that the numbers prove themselves out. Now at the same time, I think that there may be 2 steps forward, 1 step back as we transition -- as we further transition. But we're still in the early innings of the benefits that we've seen from this program. So I think we're going to see further improvements rolling out over the course of the next few years. The -- this is a 10-year agreement. It's a 10-year partnership that we have with GE here. And our expectations are that uptime will continue to improve moving forward because, of course, this is the first time in the history of the industry that the original equipment manufacturer has financial skin in the game. So that when we sit across from the table with the end user being the client, we're all aligned from not only just an effort to improve reliability and, hence, reduce the cost of deepwater drilling, but we're also aligned financially. All 3 of us have true skin in the game.

Okay, great. And then just on the Ocean Valor. It looks like that rig went back to work. If you can provide any update on that. And is that rig now back to earning full-day rate?

So the Valor itself is not back to work, but it remains on contract with Petrobras at a stand-by rate that's got a 4-handle in front of it. So just to further give color on that, the rig has remained on contract since we announced news regarding its contract status last summer. And the -- as it's progressed through the courts, it's gone through various appeal panels, which have all decided in the favor of Diamond Offshore. And we are expecting it to remain on contract throughout its contract term. There is one appeal that remains to be -- that's available to Petrobras. It's at the Supreme Court level, and we are unsure at this time whether they are going to indeed progress with that appeal or not.

Okay. But that rig was -- did it -- my understanding was Petrobras had moved that rig a couple of weeks ago?

So Petrobras did move the rig, but it was not onto a drilling location.

Our next question comes from the line of James West with Evercore ISI.

So Marc, recognizing that your capital allocation strategy hasn't changed and most likely won't change, however, the market is dynamic, the market is adjusting and it's changing as we speak here and I'm not suggesting we're at the bottom yet. But does that change kind of the rank order of where you would put capital? Does it change, I guess, what looks more attractive to you? For example, the distressed assets become less attractive because there's more hope in the market, and so, therefore, you look more at the floating factory or vice versa?

So, James, we have no single preference here. What the team is truly focused on is the efficient use of capital moving forward. And as it relates to capital allocation, as we've previously explained, we've got various strategies. We've got perhaps strategies that are more diverse than our peers, and that's predicated of course by our liquidity and our backlog, and our balance sheet gives us a few more options. But as it relates to moving forward, we're in no rush to transact. One of the basic principles of value creation is knowing the true value of an asset and being prepared to take action when the time is right. And we don't think we're at that point right now. So all of the levers remain open to us. We continually review opportunities whether it's consolidation, whether it's picking up assets that are available in the market or indeed taking innovation to a new level and moving forward with the floating factory. We're not wedded to any one of those 3. But as we move through the cycle and we look at stakeholder returns, then we will act when we feel that the moment is right. But right now, James, we're still in a holding pattern, so to speak.

Okay, got it. And with respect to the floating factory design, I mean, I know that there was some additional innovation underway when you and I visited the facilities in Holland. Has this innovation taken place? Do you have a -- is there an actionable rig design or rig design that you could take action on today that has all the full capabilities that the Diamond Offshore or really your customer would want if you were [to lower] one?

So as I mentioned, we're not particularly wedded to the floating factory strategy. But nevertheless, as we've developed the option over the course of the past 2 years, we are now at a stage where we have a final design in place that includes the hull, that includes the drilling package and the ancillary stuff that goes around it. So effectively, conceptually, it's moved from concept to existing on paper. So as we look at the cycle and how it progresses, we are effectively in a position that we're very comfortable with. But James, just to reiterate once more, it's all about the efficient use of forward capital, stakeholder returns, shareholder returns and looking at all the options that are on the table. Traditionally, we've been very conservative with our capital in the past and that's not going to change. We're just going to look at opportunities moving forward and make sure that when we pull the trigger that we've very comfortable about how we see the cycle playing out. We've done a lot of research on that. And so we feel we're in a very comfortable position. We've got the backlog, we've got liquidity and we've got the horsepower back to, when the moment is right, pull what various levers we have that are available to us. So no specific plans at this moment in time. It's just that we are watching the market, we are watching what will inevitably be a recovery in our space. We have no doubt about that. And like I say, when it -- with respect to our focus here as a management team, it's all about the future allocation of capital and maximizing shareholder returns and efficiency from them.

And our next question comes from Sean Meakim with JPMorgan.

So something is -- to maybe clarify a couple of things with respect to some of the moving pieces in the quarter. Can we talk about...

Sean, can we ask you just to speak up a little bit? It's a little bit muffled.

Sure. Is this better?

Yes, slightly.

Okay. So just on the Victory, you had more days on rate that you expected during the quarter, it sounds like, so that maybe helps the topline. And then the mobe flipped into the current quarter. I was hoping you could just maybe help us quantify some of those moving parts between 2Q and 3Q.

Yes, Sean. So -- no, you're exactly right. We originally anticipated, like I said in my prepared remarks, that the demobe would occur all in the second quarter. That actually shifted into the third quarter, which meant a lot of the cost actually shifted along with that. It was a fairly expensive demobe back to the Gulf of Mexico, and they're -- that's driving a lot of the variances that we're talking about from Q2 to Q3, as I've put in my scripted comments.

Okay, fair enough. And then I thought maybe we could get a little more color on the Ocean GreatWhite's OpEx, how that kind of performed in the quarter relative to what you guys were expecting.

It's exactly -- was right in line with what we guided to.

Our next question comes from Eduardo Royes with Jefferies.

So thinking about your fleet now, obviously, you guys cut the number of floaters, I guess, the uncommitted floaters in half, right? Sort of taking a bigger picture of you and recognizing the North Sea rigs, well, I guess, the North Sea rigs or some of those other floaters won't go back to work. At the same time, you got the -- on the other end of the spectrum, you've got the floating factory, like you said, sort of from concept to being on paper. I guess, if I think about your overall fleet view and go somewhere in between that, at the sort of half a dozen rig you guys have retained, may there be some views to spend -- some opportunities to spend some all-dollar figures? Not a new rig, but at the same time, bringing some of these rigs back and making them a little bit more diversified with smaller, tens of million dollars or $50 million of upgrades. I'm just wondering about sort of your -- you guys like to focus on the niche assets and sort of the ability to differentiate some of those rigs that you've retained that are still cold-stacked, and maybe that's where you spend some money to bring those things back out. Are there unique opportunities there to make them maybe just a little bit more marketable, I guess?

Yes, sure. That's -- I mean, that's a good question. Naturally, as we're looking at our fleet moving forward, we're very comfortable in our -- in the diversity of the fleet. We -- I said in my scripted comments here that the sixth-generation drillships is the one that is perhaps best described as being oversupplied. So over the last 7 or so years, again, as I mentioned in my scripted comments, we've invested over $6 billion in the fleet, that's spread out through new builds, but also includes upgrades to various semis: the Apex, the Onyx, the Confidence and so on. And so what we're doing is we're actually updating our fleet. We're bringing it up to spec in terms of technology, but we're also differentiating it. And moving forward, it's not just a case of saying, "No, we're not going to upgrade or we're not going to continue to upgrade the assets that we've got in place." For example, we'll be -- just to throw some examples out there, we're looking at putting offline capability on the Apex, upgrading, the drilling package on the [per-ship] moving forward. So we will continue to invest on what is smaller amounts on the fleet itself. So when we say we're scrapping these 5 assets that's not to suggest that we won't invest in the fleet that we've currently got. That will be a standard, of course, moving forward.

Great. And I guess -- probably also for you, Marc. I'm curious, at this point, we've heard about the new commercial models are working more with the customers to align with them a little bit better now for, really, I guess the last 12 to 18 months. I guess, I'd be curious, what's the uptake been there? So it's not like there's been a ton of rigs winning contracts, but you guys have certain rigs that have obviously done very, very well. And I think you guys have pushed above your own way. Curious for how much you're really seeing that play out, which one thing to offer them to guys? It's obvious now that I see that they're going. Or do you find that there's maybe some more of the typical customer model of, "Hey, this guy gave me the lowest price, that's the way I'm going." So just some perspective on how the adoption has been there over the last call-it 12 months or so as you bid rigs and win work.

Eduardo, this is Ron. Let me take that question, if you don't mind. So we have seen, I think, customers embrace in different commercial models, just as a feature of kind of where we are in the market cycle right now. And I think what we see a couple things worth noting. Given to how oversupplied the market is, with some of the longer bids that are out there, locking in sort of a fixed number for a long term, of course, is difficult to do. We've seen some customers embrace the notion of linking some with the out-year pricing to Brent or other kind of indices for the market just as acknowledgment that a contract could breathe in and out without the -- as the market kind of rolls back and forth. So we've seen that. As you'd expect, we've seen more emphasis on performance in contracts. So less about just a flat day rates. And some of the more, I think, contemporary customers do embrace the notion that performance matters and they'll pay for performance where it occurs. And at that same time, put the responsibility on the driller where it should be for our own performance. Then you've got some other, I think, more traditional operators that just want the flat out sort of cheapest day rate and go with that low first price paid. So I think it's a matter of us sort of knowing the customer, knowing what levers to pull that make the deal work for them and then being comfortable with that. So we've got to be, I think, pretty flexible to find the right model in this market.

Our next question comes from Waqar Syed with Goldman Sachs.

Marc, the Pressure Control by the Hour model, is -- can that be applied to some the additional rigs as well in your portfolio? Or for the moment, you're going to stick with the Black series rigs?

Waqar, for the moment, we're going to stick with the Black ships. And one of the reasons that Pressure Control by the Hour has been so successful is because, of course, we sold back the BOPs on those 4 drillships for $210 million back to the original equipment supplier. And the reason -- the manufacturer. The reason we could do that, of course, was because, effectively, they were all new. The Black ships were all new. The BOPs had only just literally been splashed. So there were in new condition. And one of the reasons we did that was because we wanted to maximize the penalty, the cost penalty to GE for when the subsea stack was actually not available. In other words, when we had to do an unplanned stack pull. If we were just -- if GE were just losing, let's say, a maintenance fee for the stack, it wasn't, in our opinion, material enough. So we also wanted them to lose the finance fee on the BOPs as well. So as a result of that, the total financial penalty is significantly higher. Now if we look back at the other fleet, I think, in reality, it would be hard for us to sell back the BOPs to GE that were 5, 10 years old. The concept doesn't quite work. So it was specific to the new additions to our fleet that we were able to go down specifically this path. I think that others in the industry will be looking at, as we move forward, switching the maintenance over to the OEM. But I think few will be able to switch or sell back the BOPs themselves and maximize the financial penalty to GE when that stack goes down. So that's, specifically, why we focused on the new drillships at that time.

Makes sense. Now another topic. You mentioned that some -- it seems like some bottoming of floater demand as well. If oil prices stay at this level of around close to $50 a barrel, let's say, in 12 to 18 months' time, where you think the active rig count, deepwater rig count, could go? There's about 135 rigs contracted today, maybe 115 are working, where do you think that could go to?

Waqar, we've got our models, we put a lot of time and effort into establishing where utilization will be over the out-years. We look at what the contracted fleet would possibly be. But I think it's -- I'm not going to put a number on the table at this moment in time. The -- we're looking at a recovery that is probably the back end of '19 in terms of not only utilization ticking back up but also looking at a time when pricing power might return in our space. One of the things I alluded to, again, in my prepared remarks is we do have a belief that more rigs will be scrapped as this downturn progresses, in that the marginal cost of bringing a rig back into the market will eventually get so high that, I think, some of the operators will struggle in terms of further investing into an asset that doesn't have a contract in place from a manner of not just reactivation cost but also the OpEx associated with bringing the rig back into its marketed state, as well as upgrading the rig due to regulatory reasons and so on and so forth. So we do think the market will bifurcate. Now I do know that we've seen in the last couple of weeks 2 or 3 rigs come back to the cold stack, but I suggest that both rigs were less -- cold-stacked for less than 2 years. One rig had actually been in an ongoing discussion with the eventual client for a good period of time. And the other rig was cold-stacked for less than 18 months. And of course, those rigs, you can bring them back for what is relatively low reactivation costs. But once the rigs pass 2 years, move into 3 years or 4 years, that reactivation cost becomes a barrier to reentry and could be quite significant. So we do believe that the market will bifurcate and that those rigs that are active will be recontracted ahead of those that are cold-stacked.

Our next question comes from Jud Bailey with Wells Fargo.

Question, I think, for you Kelly. Just wanted to clarify a couple of points around the guidance. I think you said you expected third quarter operating cost modestly higher than the run rate. And I just wanted to make sure you're just referencing that simply off of the 2Q reported number when you referenced the run rate there?

Yes, Jud, that'll get you in the ballpark. We think with everything that's netting out, with the Victory coming off and then the new contract for the Guardian is going to be kicking in, we'll end up somewhere around that similar run rate as what we had in Q2. Definitely (inaudible).

Okay. Okay. And then, Marc, just to follow up on the last line of questioning in terms of -- you commented on seeing potentially an infection for the industry. I appreciate you don't want to try to pinpoint where the floater count may be in 12 or 18 months. But I'd be curious, based on the conversations and some of the opportunities that you're seeing, do you think you see much more downside from here on the floating rig count? Or do you take another step down later in the year and then stabilize? I'd just be curious if you have any thoughts perhaps just on the general trajectory of the floater count over, say, back half of this year or early '18?

Sure. No, I think the overall trend, if you look at the number of rigs that are coming off of contract and the contracting opportunities out there, I think it will track down slightly over the next 6 or so months. The uptick in contracting opportunities is certainly observable and is moving in the right direction. I'm choosing my words carefully here because I don't want to put too much optimism back into the market when we've still got a little bit of a runway ahead of us in terms of a potential recovery. But we're starting to see term contracts come back into the market, and I think that's an important sign. Much of the contracting that's happened over the past 2 years, being for short-term work, being on a rig -- sorry, a well-by-well basis, and now we're starting to see contracts that have terms of 2 years, potentially 3 years moving forward. So that's definitely a good sign. But I'm not calling a bottom, I'm saying we're seeing signs of an inflection. And as it relates or translates into contracted rig count, I think it's probably too early to put a number out there, and so I'm going to avoid doing that. I'm just going to really stick to the commentary around we do see a point of inflection approaching.

Okay. And I guess the -- also, in response to the last question, the day rate improvement you thought could materialize, that's more of a 2019 event? I just want to make sure I heard you correctly.

Yes, that's correct. I don't think we're going to substantially see any movement to the upside on day rates for at least another 18 months.

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

Marc, could you update us on GreatWhite and what the status is with BP? Are you collaborating with them on sub-let opportunities? Or do you envision them finding an alternate plan for the rig at some point, whether it's early next year or otherwise? Or if you think that status quo is the most likely path forward as far as you can see?

So, as you would expect, we're actively engaged with BP and looking at opportunities for the Ocean GreatWhite to put it back to work either internally within BP or externally with other opportunities. And in fact, as we kind of market our fleet, we go back to BP with leads that we have from their peers. So the intent is to get the rig back to work. But from a contractual perspective, the contract itself is sound. We have, over the past couple of years, done a very effective job of protecting the sanctity of our contracts. And moving forward, we'll keep working with BP so that, that rig can start drilling wells in anger, so to speak.

Okay. And then you mentioned a couple of questions back we were discussing the capital barriers to industry fleet reactivation, and that threshold of 2 to 3 or 4 years before reactivations become entirely different proposition from an investment standpoint. I would presume that you would, at least, somewhat exempt the Onyx from that comment based on it being a more modern rig, it's moored -- would you say that, that is a rig that would be a fairly easy reactivation at this point? And that, that would not change materially if it's second half of '19 when its next contract might materialize?

So the Onyx is a rig that was upgraded a couple of years ago. It doesn't have the complete cyber-chair electronics on it. It's a moored rig. And naturally, one can draw a conclusion from that, that the reactivation costs of the moored semis would be less than many of the DP rigs -- the more complex DP rigs that are out there. So we're very optimistic and hopeful that the Onyx will reenter the market, in an asset class that, frankly, has seen the majority of the scrapping. Just to use numbers that I've spoken to already, 84 rigs have been scrapped so far in this cycle. Of which, only 13 were DP drillships. So that sector is fixing itself perhaps faster than the DP segment is in terms of supply and demand economics. And many of the opportunities that we're seeing are related to the moored fleet. For example, Australia, for example, the North Sea. And although the Onyx isn't over in either of those locations at this moment in time, we are expecting moored asset class to somewhat recover a little bit faster than the DP asset class. So we remain optimistic that the investment that we've put into the Onyx will actually mean that when it's time to bring her back to the market, it will be less than perhaps some of the rigs that are out there specifically relating to her own capabilities.

Our next question comes from the line of the Haithum Nokta with Clarksons.

Marc, I wanted to dig a little further more on your comments of being a little bit more constructive on the floater demand side. You mentioned multiyear contracts being available now and -- or kind of back in the market. I was curious, is that based on the contracts that we've seen announced in industry recently? Or is that based on kind of new opportunities that you're starting to see with commencements, extensively '18 or '19?

Sure. No, that's a good question. No, it's work that's in the pipeline right now. So in other words, it's discussions that we are having with various operators around the world as it relates to new contracts that will be sanctioned in the out-years. So I'm talking about at the end of '18, beginning of '19. It's contacted and yet to be announced in the market that we're seeing these opportunities materialize. Now on the back of that, I mean, sanctioning of these contracts is also a little bit, perhaps, more visible in the market space. If you look at, for example, Mad Dog 2 and others that are out there, so Mad Dog will require 6 or 7 rig years. Those haven't been announced yet. So there's opportunities around the world that we are beginning to see, term contracts of 2 to 3 years, put on the table. And obviously, when you go back and price those, you do try and get some kind of indexing with the price of oil into those long-term contracts at this moment of time. So it's a trend that perhaps isn't in the public domain, but it's something we're definitely seeing from the -- from a rig contractor perspective.

And I guess, just kind of piggybacking off of Ron's earlier comments about kind of the (inaudible) of pricing especially in the out-years. Is there kind of any difference that you can discern between kind of different operator groups, majors versus independents or NOCs? Or is it kind of just varied by project or opportunity.

Yes, this is Ron. I think operators are -- there are some, I think, definite contracting sort of personalities about different groups of operators. And as a general notion, the NOCs tend to be sort of more, I think, focused on headline day rate, less around the more, I think, creative commercial models. I think some of the larger IOCs, of course, are switched on to sort of the more advanced offshore modeling and contacting techniques. I think amongst the independents, you see kind of spread of range, some are a bit more advanced, some just want something very simple and easy to execute. I think that we're pretty good, though, at matching the offer and the commercial design to the customer. So we know our customers well enough to figure out sort of what do they need to make the program go. And that's an important part of our (inaudible) commercial process to match our offer to those needs. But you're right, there is a wide range of different, I think, contracting preferences, and we're pretty switched on to who needs what.

And our next question is from Kurt Hallead with RBC.

So Marc, I always kind of viewed your comments and Diamond's viewpoint of the market as being very pragmatic. And it did strike me, today, in particular, that you talk about an inflection potentially looming. I know you referenced some things about what's giving you some indications of that, obviously, a bidding activity and some term contracting. I think what I was looking for was a little bit more clarity on your view on the day rate dynamics. I think I might have heard in a prior questioner about day rate potentially moving higher 18 months from now. Just wonder if you'd put some additional color behind that for us.

Sure. So although we're getting close to this point of inflection, at the end of the day, it's supply and demand, it's economics 101. And this downturn, we've been hit particularly hard. Because it's not just a supply-induced downturn or a demand-induced downturn, it's a combination of both. So what has to happen first is demand has to fix itself. On the back, concurrently, of supply somewhat fixing itself. And the -- between demand picking up and rigs starting to drill and therefore go on contract, the governor has to spin up. And so there's this kind of pricing lag that inherently sits in our business. Now we think that the pricing lag is there, that it's an 18-month window, or close to 18 months, before we see pricing start to move up. But once it starts to move up or once demand starts to fix itself, we believe that pricing recovery will somewhat be accelerated by the fact that the market will bifurcate. And so, it's going to be a long, long time before -- or very a different marketplace for us to be in before some of the early generation sixth-gen DP assets will be reactivated, those that have been stacked now maybe 2 or 3 years. And therefore, we do see that pricing will recover at some time, let's say, late '19 or start to inflect back upwards -- along with utilization or marketed utilization. And we should see pricing recover in the -- well, as I said earlier, the late '19s and early into the next decade. So it will be a somewhat a slow recovery. But once it materializes, we think it will accelerate.

Okay, great. And then maybe on a specific note. As it relates to the contract opportunities in Australia that you have, the contracts that you have in Australia, is there any potential to fill that gap between Cooper and Origin? Or is it just too tight to make that happen?

This is Ron. Yes, that's a great question. We think about that a lot ourselves and are into -- first up, between BHP and then Cooper and Origin, we've got a pretty good mobe in the northwest side down to the southeast side of Australia. So that will take priority and make sure we'll arrive on time and ready to drill for our customer. We've looked at some things between Cooper and Origin, but candidly, we'd rather execute the work that we have, do so sort of with a high degree of confidence and not squeeze in too much work in too tight a time frame. Once you're on a well, you can never quite be sure when you get off that well. And we want to do nothing that would sort of imperil the committed work. So at this point, we're going to focus on both delivering on BHP, preparing for a good commencement for Cooper and Origin. And I think that once we're down though, I think, on that southeast side, it wouldn't surprise me if other operators though approach us on work while that rig is in a less-traveled part of the drilling world.

And our next question comes from the line of Praveen Narra with Raymond James.

Just a couple of quick ones from me. On the retired rigs and the reactivation cost you were expecting to see. If -- could you give us a ballpark of what you're expecting on the those retirements? And if you could differentiate the alliance from the other moored guys?

This is Ron. If you can just kind of clarify that question. You say what we expect in the way of those retirements, of course those are held for sale. Are you asking about what we think they'll sell for?

Well, I guess, what you thought the reactivation cost may have been?

Oh, I see what you're saying. Okay. Yes, that makes sense. This is Ron again. So we've done some rough estimates on those. Those are some pretty high numbers that really have failed almost any economic test that we ran on what kind of day rates you'd have to earn. If I answered it a little bit differently, the day rates you'd have to earn to make their reactivation affordable was almost sort of 2x where the market is today for that rig class, at least on the moored side. And so that was just beyond reach. You could do the math on an index card, it wasn't hard to figure out. So I won't get into how much it cost to reactivate, but the day rates to support that were just unachievable. Right you...

That's perfect, yes. And then, I guess, on the Black rigs, in terms of their operational efficiencies, were those accretive to the ultra-deepwater rate, the 97.1% from the press release?

I'm not sure exactly what you're asking there. Say that one more time for...

Were the Black -- were the operational efficiencies on the Black rigs accretive to the operational efficiency rate for the ultra-deepwater floaters as a whole?

Oh yes, definitely. Yes. (inaudible)

And I'm not showing any further questions. I'll now turn the call back over to Marc Edwards for closing remarks.

So thank you very much for your attendance today, and we look forward to chatting with you in the Q3 call.

Ladies and gentlemen, this does conclude the program, and You may now disconnect. Everyone, have a great day.