Diamond Offshore Drilling Inc (DO) 2016 Q2 法說會逐字稿

Welcome to Diamond Offshore's second-quarter 2016 earnings conference call. (Operator Instructions). I will now hand the call over to Samir Ali, Director of Investor Relations and Corporate Development, to begin. Please go ahead, sir.

Thank you, Maria. 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. Following our prepared remarks this morning, we will have a question-and-answer session.

Before we begin our remarks, I remind you that the information reported today speaks only as of today and therefore, you are 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 are 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 today are covered by that disclosure. And now, I will turn the call over to Marc.

Thank you, Samir. Good morning, everyone, and thank you for joining us today. Allow me to start by summarizing our second-quarter financial results, which were impacted by a special charge, and then I will provide some highlights from the quarter.

Diamond Offshore posted a loss of $4.30 per share, including special charges of $612 million. Adjusting for these items, earnings per share were $0.16 in the second quarter. Kelly will address the special items in his prepared remarks. This compares to $0.64 reported in the first quarter of 2016. Earnings during the quarter were significantly impacted by four unscheduled subsea stack pulls on three of our blackships currently operating in the Gulf of Mexico. Unplanned subsea stack pulls are the major contributor to a deepwater rig's nonproductive time resulting in a material loss of revenue for the drilling company and significant additional costs for the oil and gas operator.

Under our new Pressure Control by the Hour service model, we now have the original equipment manufacturer, or OEM, at the table with us and our clients discussing upgrades to their equipment with a renewed design for reliability ethos. Unique to the industry, the OEM is now financially incentivized by Diamond Offshore to minimize non-productive time and maximize equipment availability.

Of the four unplanned stack pulls this past quarter, three were related to the same OEMs bolt recall safety bulletin, and the fourth was a failure relating to a non-maintenance assembly issue. To this point, I would like to make it clear that these stack pulls were not maintenance-related nor were they due to the transition to this new concept as of course in the short term we continue to have duplicate Diamond and GE maintenance crews on each rig.

Indeed, by having the OEM's rig-based personnel overseeing stack performance 24/7, along with the new industrial Internet connectivity to their logistics, engineering support and design teams, we believe we were able to return the rigs to drilling operations faster than has typically been the case. However, the real benefit of the new model will be the reduction in unplanned stack pulls over time as the design for reliability ethos gains traction.

Recall that the OEM is responsible for on-rig service personnel, management of parts, overhaul and repair, continuous certification, data monitoring and the management of change. Three of our four sixth-generation drill ships have now switched to this model with the fourth, the Ocean BlackRhino, transitioning as it commenced its contract with Hess in the Gulf of Mexico at the beginning of next year.

During this past quarter, we received $52.5 million from the OEM as payment for the BOP system on the Ocean BlackLion. As I continue to visit with current and prospective clients throughout the world, without exception, they applaud Diamond's thought leadership in this regard and in the severely oversupplied subsector of sixth-generation assets, we believe our four drillships have consequently been elevated to the top of the list of desirability for when they will need to be re-contracted in 2019.

However, the thought leadership we are bringing to the industry does not stop at Pressure Control by the Hour. During the quarter, we announced a joint development agreement with Trelleborg on our new, innovative Helical Riser Buoyancy design. Under this agreement, Diamond has licensed the technology to Trelleborg and in return, we will work with them to further develop, test, manufacture and market the Buoyancy Riser technology. This new buoyancy design will reduce riser drag and help mitigate vortex-induced vibrations, which is common in high current environments such as the Gulf of Mexico. It also eliminates the need for our clients to install fairings or strakes to the drilling riser, which importantly reduces the time it takes to deploy the riser and so decrease overall operating expense.

Not only is the new design expected to cut the number of days it takes to run a riser by up to 50%, it also improves safety as personnel would no longer need to work over water, below the drill floor while running or pulling riser. We intend to deploy the first systems to the Ocean BlackLion and Ocean BlackRhino drillships towards the end of the year.

After the Pressure Control by the Hour construct, this is the second tangible example of how we are helping our customers make offshore drilling more competitive by driving efficiency gains and removing flat spots throughout offshore drilling operations. Despite the continued headwinds prevalent in our industry, we have not lost sight of the need to lower cost through efficiency gains, and we are continuing to develop the floating factory concept about which I have previously spoken.

So now turning to our current fleet, the Ocean Apex recently began its 18-month program in Australia working for Woodside at a contracted rate of $285,000 per day. We also have recently secured a three-month extension on the rig at $205,000 per day. The rig is now contracted through February 2018. You will recall that the Apex is an extensively upgraded Victory Class vessel that was delivered to the market in 2014.

We also recently took delivery of the harsh environment ultra-deepwater semi, the Ocean GreatWhite. The rig has arrived in Singapore where it is undergoing contract preparations before being wet-towed to the Great Australian Bight to begin a drilling campaign for BP in late Q4 2016 at a rate of $585,000 per day. The Ocean GreatWhite is a unique rig that is purpose-built to drill in some of the most challenging regions of the world, and it is for this reason we believe she will have a strong competitive position relative to the oversupplied sixth-generation floater market. When the rig is presented to BP in Australia during Q3, it will meet and in some cases exceed all design and required operational expectations relating to the original Moss design. The yard that built the unit is stating that this is the largest semi-submersible yet delivered to the market.

Allow me now to provide some commentary on the market itself. Clearly, our customers continue to curtail offshore capital expenditures. In this past week alone, two large offshore players have further reduced 2016 investment spend, and we are estimating that our clients' 2017 CapEx will further decline. This is an addition to the approximate 40% reduction that we experienced from 2012 to 2016. In conjunction with newbuilds continuing to enter the market and contracted rigs rolling off contract, this has created the perfect storm for the drillers who are overexposed to the sixth-gen asset class.

We may have seen a bottom in the oil price, but it is clear that volatility will be with us for some time to come. Some of the larger diversified oilfield service providers have declared a bottom in activity and are suggesting that a recovery is imminent. While this may be the case for certain onshore basins, it is not so for deepwater drilling. Utilization is still declining at almost 5% per quarter and contracting is essentially next to zero. Before we can declare a bottom, we at least need to see a level of fixture awards that matches the number of contracts that are reaching the end of their term and for our industry sector, this has yet to happen.

Of course, we all know that our industry is cyclical and we will see a recovery. However, this time, it is likely to be slow and protracted. Our clients will first have to fix their cash wheels and then eliminate the partner drag that is holding back much of the current deepwater activity. Nevertheless, we believe that future hydrocarbon demand and the commensurate supply stack required to meet this demand suggests that as we move into the next decade, deepwater will have to deliver a level of incremental production that is equivalent to the entire portfolio that is currently produced from North American unconventionals today.

Simply put, the long-term fundamentals for our business are and will remain intact. Now I will turn the call over to Kelly to discuss the financials and then I will have some closing remarks. Kelly.

Thanks, Marc. I will begin with an overview of the second-quarter results followed by our current expectations for the coming quarter. As Marc just discussed, we have seen industry fundamentals continue to deteriorate in the first half of 2016 and we anticipate continuing headwinds in our near-term outlook. As a result, we recorded an after-tax net charge during the quarter of $612 million or $4.46 per share primarily related to the impairment of eight of our semi-submersibles and associated inventory.

Also included in the special charge were certain discrete income tax adjustments primarily related to valuation allowances for current and prior-year tax assets. As part of our analysis, we have also decided to scrap the Ocean Star and Ocean Quest. Including the special charges, we reported an after-tax net loss of $4.30 per share for the second quarter. Excluding the charge, we earned adjusted net income of $22 million or $0.16 per share compared to net income of $87 million or $0.64 per share reported in the first quarter of 2016.

Contract drilling revenues of $357 million was a sequential decrease of 19% primarily resulting from mobilization revenue reported in the first quarter for the Ocean Endeavor. Additionally, during the first quarter, the Ocean Rover, Ocean Onyx and Ocean BlackRhino completed their contracts. As a reminder, the Ocean BlackRhino is currently warm stacked and undergoing rig enhancements prior to commencing her three-year contract for Hess in early 2017.

Additionally, as Marc mentioned, during the quarter, we also incurred significant unplanned downtime primarily related to BOP stack pulls on our blackships resulting from a boat-related safety notice from the manufacturer. Partially offsetting these decreases were additional revenues related to the Ocean Apex, which began a new term contract during the second quarter along with a full-quarter benefit of the Ocean Guardian, which returned to work at the end of the first quarter.

Other notable items that are unique to the second quarter include the following. First, our operating income benefited from a net profit of $15 million in reimbursable items. As you know, our reimbursable revenues and expenses normally offset. However, we previously negotiated a fee with our customer to assume responsibility for certain construction and subsequent reconstruction efforts related to the demobilization of the Ocean Endeavor from the Black Sea.

And finally, we incurred a $12 million loss during the quarter related to the sale of a marketable security. With the exception of taxes, the remaining income statement line items were within guidance we provided on our first-quarter call. Contract drilling expense of $198 million was at the lower end of our previous guidance of $195 million to $215 million. Contributing to our lower costs for the quarter were reduced BOP rental charges for the unplanned stack pulls on our blackships, an advantage we have from the Pressure Control by the Hour arrangement with the OEM.

Depreciation, G&A and interest expense all came in at the midpoint of our previous guidance. Our effective tax rate for the second quarter was 11% resulting in a tax benefit of $76 million when applied against our reported pre-tax loss. Excluding special charges during the quarter, we had a tax benefit of $10 million driven primarily by our foreign and domestic earnings mix.

Now, let me provide some thoughts about the third quarter. Consistent with commentary from our last conference call, we have no special surveys for rigs scheduled for the remainder of 2016. To see projections of currently scheduled downtime, please refer to our quarterly rig status report that we filed this morning. We expect rig operating costs for the third quarter reported in the line contract drilling expense to come in at a similar range as last quarter of approximately $195 million to $215 million. This guidance is specific to contract drilling expenses on our income statement, which does not include costs report in reimbursable expenses.

Although we had a net profit in the second quarter for reimbursable items, we do not expect for this to repeat going forward, meaning the revenues and expenses should net to zero. As a result of the impairment charge taken during the quarter, we will see a reduction in depreciation expense going forward. We are now estimating our full-year depreciation expense to be in the range of $400 million with the third quarter coming in between $85 million and $90 million. As a reminder, when the Ocean GreatWhite goes into service towards the end of this year, we will see a slight increase in our run rate.

G&A costs are still expected to average around $15 million to $20 million per quarter for the remainder of the year. Interest expense on our current debt and expected borrowings on our bank line of credit net of capitalized interest is projected to average around $28 million per quarter for the rest of 2016. In the second half of 2016, we anticipate our effective tax rate to run in the 27% to 29% range. Of course, the rate may fluctuate up or down based on a variety of factors to include, but not limited to, changes of geographic mix of earnings, as well as tax assessments, settlements or movements in exchange rates.

Moving to our capital expenditure guidance, reflecting decreased rig activity, we believe that we will incur maintenance capital cost of approximately $140 million for the full year of 2016, which is down compared to our prior-year spend of $215 million. Newbuild capital expenditures for 2016 are expected to be approximately $510 million, which includes the second-quarter payment for the delivery of the Ocean GreatWhite. So in total, we are expecting our capital expenditures to be approximately $650 million in 2016.

And finally, I would like to make a few comments about our liquidity. Over the last few weeks, S&P has cut the rating for the majority of the offshore drillers. Most of our peers were reduced by two notches to non-investment grade. We were not immune to the rating change, but we were only taken down one notch by S&P to a new rating of BBB, which is still investment grade and now the best overall rating among our peer group. Our next debt maturity is $500 million and not due until May of 2019, and these bonds are currently trading above par value.

And finally, during the second quarter, we used our revolver to help fund the last payment on the Ocean GreatWhite, but we expect to pay down this balance in the coming quarters. And with that, I will turn it back to Marc.

Thank you, Kelly. So, irrespective as to which part of the cycle we are in, capital allocation will always remain the most fundamental responsibility of the management team here at Diamond Offshore. We will also continue to manage costs down without comprising safety, maintenance or training. When the safety bulletin on the subsea stacks was issued by the original equipment manufacturer, an immediate stack pull was not mandated. However, we had an adult conversation with our clients and elected to pull. We will always put the safety of our crews and operations ahead of financial gain.

We have demonstrated our ability to drive thought leadership into the industry and differentiate the Diamond brand. We are continuing to investigate opportunities around driving further efficiency gains into deepwater drilling that will be unique to Diamond Offshore. The floating factory is one such option. However, the proper goal of capital allocation is to build long-term value per share. We have the liquidity and balance sheet that presents us with perhaps a more complete portfolio of strategic options than have our peers and, as Kelly has just mentioned, we uniquely retain the highest credit rating from both S&P and Moody's.

Yet, as we move forward, it is important to remember that one of the basic principles of value creation includes knowing the true value of assets and being prepared to take action only when the time is right. And with that, let's take some of your questions.

Thank you. (Operator Instructions). Sean Meakim, JPMorgan.

So I was hoping to start off if we could maybe quantify a little bit more the impact of the agreement with GE. I know for competitive reasons previously you elected to not give us too much detail, but given that we've had a pretty early on example of how it works, can you give us a little more granularity of the puts and takes of that agreement now that you've got three of the four drillships up and running?

I'm not going to go into the financial details because of competitive reasons, but basically we are paying GE a financing cost and a service cost on a daily basis for stack availability. In other words, when it is providing what we ask it to do, we pay GE. When we have an unplanned stack pull, then both the finance payment and the service payment goes to zero. There is also on top of that a bonus malice payment that incentivizes GE on an annual basis to maximize the availability, and likewise, if they drop below a pre-determined percentage in terms of availability, then the malice kicks in.

So, as it relates to the financial aspects of the transaction of the construct, that's where we are. But at the same time, as I mentioned in my statements, they are responsible for on-rig personnel, for changing out parts. They are responsible for real-time certification and so on and so forth, so that when new elements of the stack are designed on a reliability basis, they are incentivized to bring them to our operation and install them. So that's basically the construct that we went to.

I've actually had conversations with the Chairman of one of the major airlines here in the US and the analogy really is the Power by the Hour model that GE already went to and Rolls-Royce as it relates to the aviation turbines and the improvement in the reliability. So that's where we are trying to get to. We are trying to adopt a similar success in the deepwater drilling space as to what was definitely seen and was material in the aviation industry as it relates to reliability.

Thank you for that. And then just thinking about the Apex extension and opportunities in that market, particularly with Woodside, does the extension give you any better line of sight, things beyond what was being contracted? And then just thinking about in that part of the world are there any capital upgrades or other ways in which you'd think about better positioning yourself for new opportunities in that region?

Clearly, I think Diamond has a pretty good reputation with operators that work with us that generally want to work more with us and that was certainly proved here with the Apex. And there's no doubt that it certainly gives us a better line of sight to upcoming opportunities if we are there and operating and on the inside. So we like that position I think for sure. And I think overall Diamond has a strong brand in Australia, including the Apex, the Monarch and previous history. So that's a market that we intend to stay in and continue to market in and we see as part of our future portfolio.

Okay. Fair enough. Thanks for the detail.

Jud Bailey, Wells Fargo.

Maybe a broad question. You commented on your outlook and still obviously the industry is still under some pressure. Some competitors have talked about seeing an increase in inquiries and opportunities. I'd be curious to know what you are hearing from customers. Are you seeing any bright spots at all for 2017, any markets, whether that be mid-water or ultra-deepwater, or any conversations starting to pick up in your mind as you look into next year?

Appreciate the question and I love the optimism with the bright spot comment, but candidly I think it's still a pretty tough market, I think, for us overall and for our peers. I think what we see happening is, in certain markets, we are seeing a slight uptick in some of the P&A activity. I think that's just a function of low rig rates and probably some good, I think, probably tax policy that might influence some thinking, but I wouldn't extrapolate too far from that. P&A, those are obligations that have to get retired. This is probably a good time, I think, for operators to do just that.

If you move beyond the plug and abandonment piece of the market, I think we do see some operators re-running their model looking at low rig rates, looking at where commodity pricing is, what the production revenues are going to be. But I'd be careful -- those conversations, although they certainly are interesting and we welcome them to have with operators -- an operator re-running a model is not the same thing as a signed contract. And so I think I'd separate activity from results in that regard. So I do see some operators, I think, stirring the pot on their analysis, but I wouldn't extrapolate too far from that to an uptick in signed contracts.

All right. I appreciate the color on that. And my next question is on Brazil. A twofold question. I guess, number one, there's been a lot of talk of Petrobras trying to continue to put more pressure on service providers down there. You guys have already renegotiated contracts as have a lot of drilling contractors. Is there more pressure coming from Petrobras potentially given their budget remains under pressure?

And then the second side of that is -- on the flipside is there seems to be some opportunities for non-Petrobras operators in Brazil. So could you maybe just talk a little bit about what you are seeing between Petrobras and some of the non-Petrobras operators down in Brazil and just your overall thoughts on that market?

Yes, I will start and then I'll maybe flip it to Ron just to give some detailed color on Brazil. There's still pressure in the market from all operators to renegotiate rig rates. I think many of our clients are long on rigs. That does include Petrobras. Remember, at the peak, they had 72 rigs. They currently have 33, of which I believe 13 are currently on contract, but are not drilling.

So the pressure is there. Whoever you go and talk to amongst the large offshore drillers, I think they have more rigs today than they would like. So you have to be especially careful around the sanctity of contracts. There's more onus on performance than perhaps there was in the past, but I don't think it's specifically a Brazil issue. During the course of the year, we've seen at least 21 contracts that have been terminated in some shape, manner or form, and I believe only in the last 24 hours we've seen another operator cancel a sixth-generation drillship, which I think was only delivered in 2014. So the pressure is still there. Ron, Brazil color?

Yes, so I think long term Brazil clearly matters when you are talking deep and ultra-deep, and no doubt the legislation working its way through that would open up the markets beyond Petrobras I think is long term I think very exciting. And there's a number of the larger operators here that have their eyes clearly trained on that market and we have some I would call it informal, I think, conversations about that. Obviously our long experience in Brazil matters, and operators that look at entering that market would prefer to do so with a drilling partner that's been there and done that. And so we certainly fit that persona. So I think there's some good early conversations, but, to Marc's point, there's still a good supply of rigs in that market and that oversupply has to get sponged up, I think, before any real aggressive contracting takes hold.

All right. Great. I appreciate the color. I will turn it back. Thanks, guys.

Gregory Lewis, Credit Suisse.

So in the press release on the BOP initially, you talked about the different ranges of days where the stack was out before it was put back to work. Was there any progression and improvement in efficiency? In other words, did the first stack pull take longer than the last stack pull?

Well, good question. Again, I mentioned it in my prepared remarks. I think over the course of the four stack pulls, did we find that we had returned the equipment to work and therefore had less MPT than otherwise, I think on the overall perspective, yes, indeed, that was the case. And that was driven by having the GE personnel already on the rig. As soon as we realized we had to do a stack pull, the GE folk were mobilizing their logistics. They were in contact with their design team.

On one of the stack pulls, we had a problem going back down again and we had to pull the stack back up and that was when you have a failure for an unknown reason. When that happens, having the GE personnel already on the rig figuring out the likely mode of failure, preparing to repair the stack once it's back on the rig, pre-ordering the logistics around getting whatever spare parts are required onto the rig -- remember, in this particular case, we had an issue that the stack was probably, when we realized the issue, 36 hours from getting back to surface and we didn't know what the issue was. But having those GE folk on the rig, looking at all the various modes of failures and preparing to replace the unit and get it back down certainly speeded up and made things more efficient. So, yes, we did see an improvement.

As it related to the four stack pulls individually, did we get better? I think it's hard to quantify that at this moment in time. But this isn't -- Pressure Control by the Hour isn't about efficient stack pulls and return to work consequently. It's about preventing the stack pulls in the first place.

Okay. That's great. That actually leads me into my follow-up. Clearly, bolt issues seem like -- they've been a problem for a while, to the point where it sounds like we could potentially see the BOPs be designed to try to eliminate the bolts that have been causing issues. Is that something that you are hearing about? Is it something that you will be able to help work on, or is that just something that is so far out on the horizon that it doesn't really make sense to even be talking about yet?

No, it makes absolute sense. The BSEE are putting together a working group to actually understand the issues better, but a different OEM had bolt failures just over five years ago. There were some issues two years ago that were not related specifically to the rams on the stack. This one is related to the way the cutters are attached to the body of the ram assembly itself. And absolutely, what is the next stage? Design the equipment so that the attachment of the cutters to the ram itself does not require bolts and that's something that we are already in discussions with GE around.

Okay, guys. Thank you very much for the time.

Ian Macpherson, Simmons.

Ron, looks like your current well on Valiant with Premier has stretched a little bit into August. Are there other options beyond that? Is there any visibility for Valiant beyond third quarter at this point?

Certainly Valiant has done well with Premier, but I think she's running to the natural close of that program. Premier has given us good marks on what she's done, but their program is coming to a natural conclusion. We have a bid to Valiant into several other opportunities in the same market. We are not announcing anything today, but I think we are fairly, I think, optimistic about her chances. Her good reputation in the market, good weather-handling characteristics, a crew that's been together for a long time, all that adds up. Operators take note of that. And although I wouldn't guide you towards work in direct continuation, but I think the things that we do have on our radar are not too far beyond the Premier program. So we've got a degree of optimism that she will keep going beyond Premier.

Okay. Good. With regard to leading-edge day rates overall, certainly there have been numerous instances where rates have either not been published and they've presumably been very low, or we've seen published rates that have been at around cash breakeven levels. But I'm surprised that still this late into the downturn we are still seeing a lot of contracts that are well above cash breakeven. I think it looks like your extension on Apex is in that bucket at $205,000 a day. Can you comment on the profitability at that day rate level for Apex and what enables a contractor to continue to get what seemed like pretty premium day rates in certain instances right now?

Yes, fair question. So we do like the day rate of course on the Apex, and I think overall we've seen, I think, rates successively with each new fixture get pulled progressively lower and that rate there on Apex is actually higher than some others have earned in the same market. So we certainly like where that is.

I guess I'd say overall it's related to, I think, the value that the operator can get back in return. So an operator that knows us, knows the rig and we can deliver on those high expectations, there's probably a greater chance we can deliver some value. I think on a relative scheme of things by contrast, P&A is harder for an operator to get value from. That'll be priced I think sort of lower on a pound-for-pound basis. But I will tell you that the low volume of fixtures just create a real -- it's really hard to describe where a typical market is given there are so few data points that get released. And like you, we see many that get not named in terms of that day rate.

I would say that, without a doubt, rig pricing power resides with the operator today. There's no question about that. We think long and hard about asset utilization, so we will price to that. And one of the advantages of having the financial strength that we do is we can price to the market and keep that asset utilization where it has to be. So we are able to bid using different techniques depending where the customer is and where the market is. But like you, with each successive announcement of fixtures, we see those numbers going lower and lower, so that's something we have to manage and balance against asset utilization.

That's helpful. Thanks, Ron.

Kurt Hallead, RBC.

Marc, I'm curious, if I count correctly, you have 15 stacked rigs remaining in your fleet, it looks like 10 floaters and 5 jackups and I know everybody knows that the near-term dynamics of the industry are very challenged. So the next part of the equation of trying to find value is determining what number of rigs that could be part of your fleet once you get back into, quote/unquote, a midcycle period whenever that midcycle may be. So of those 15 stacked rigs, Marc, how many of those do you think are ultimately going to be part of the long-term Diamond fleet?

I'm not going to speculate on that on this call, Kurt. We do, on a quarterly basis, take a look at the fleet and do an impairment analysis, and the market has tracked down since the beginning of the year. You look at the number of floaters that have had their contracts canceled. I think the outlook is not showing any signs of improvement. As Ron has only just spoken to, there's extreme pressure on pricing that remains in place.

Just adding a little bit of color to the previous question, a lot of it -- Australia we got a good rate -- but that's really specific to a certain geomarket where you're not having to mobilize rigs in and therefore pricing could be slightly higher. But overall let's not forget that the floater utilization is still falling at 5% per quarter and is showing no signs of hitting a bottom as yet.

So we will look at our fleet on a quarterly basis moving forward and look and see if we have to take any further action. Is the fleet size getting too small? At this stage, we are comfortable with where we are at. We've got our sixth-generation assets currently fully contracted through to 2019, and we are very comfortable with our third and fourth-generation fleet. Many of the contracts that we've announced over the last 12 months are in that space. We are not overly exposed in the fifth-generation fleet, which is highly challenged because the sixth gens will drop down, but the sixth gens won't be able to drop down into the moored asset class and compete effectively there. So we think that we've got a good balance in our fleet. We just announced two further rigs that will be scrapped, but that's all I'm going to say at this stage.

Marc, that's good color. I do appreciate it. Thanks.

Timna Tanners, Bank of America Merrill Lynch.

Wanted to follow up on the last question and just ask you how you would characterize the market for distressed rigs and when and how you would think about your appetite for this.

That's a great question, actually. And I'm sure there's a lot of people that are looking into that and needing an answer. It really takes a leap of faith to go into the market at this moment in time and pick up a distressed asset when we really don't have any visibility as to when the eventual recovery will materialize from a timing perspective. So what is the carrying cost on that option that you are purchasing? And you've got to look at a whole series of issues around having to cold stack and then reactivate an asset that you are bringing into your fleet right now, however distressed that pricing may be.

And there's a combination of several factors that guide an economic outlook for purchasing an asset, cold stacking it and then reactivating it. And you are not going to reactivate a cold stacked rig without a contract in place because the hurdle rates are simply too high. Depending on how long a rig has been cold stacked, you are looking at reactivation rates -- my last call I said anything from $60 million to $90 million. It actually could be higher than that. If you purchase a sixth-generation asset, it's only got one BOP. It might have to go through a special survey and you might have to do various upgrades to the unit, especially on some of the earlier sixth-generation assets.

So, in that regard, there's no real simple answer, but there's a lot to consider before you bring additional assets into the fleet and expand the number of assets you might have let's say in the sixth-generation fleet, which is going to be heavily oversubscribed for a considerable period of time to come just on a demand/supply perspective.

So it's a combination of timing, it's a combination of the asset itself, it's a combination of your other assets. Is that a fair characterization?

Absolutely. And as I said in my closing remarks in the summary there, one of the basic principles, and I keep talking about value creation because it so important in our space, includes knowing the true value of the asset, but equally importantly being prepared to take action only when the time is right, and frankly, we are not kicking the can down the road, but in terms of deferring, pulling any of your strategic options, if you don't do it today and you do it tomorrow that means you're one day closer to the recovery. And we feel no pressure right now to go into the market and declare on any strategy, at least for the near term. Our space is still highly challenged moving forward.

Got it. No hurry. All right, thanks so much.

Jeffrey Campbell, Tuohy Brothers.

My first question was regarding the two rigs that you scrapped. How much was that decision based purely on the cost to maintain the rigs maybe regarding their age versus your view, which you've been talking about quite a bit, on the future prospects of work and the water depths in which those rigs operated?

I think it's a combination of factors, but if you certainly start from the customer voice on this one, you look at the surplus of rigs in the marketplace and you look at how far into a recovery would we have to get for other rigs to get sponged up and get contracted before those rigs would be next in line, if you will. That's quite a ways down. That's part of the decision. I think certainly the cost to bring them back to active fighting status is part of the calculus as well. But you look at where the market is and what you'd have to believe for those rigs to come back soon, it's just too hard to glue that together. So I think that was a decision that makes a lot of sense from the market, customer as well as capital allocation perspective.

Ron, I don't want to put words in your mouth, but it sounds like you are also looking at it tangentially with some of the other remarks that are being made. It almost sounds as if the quality of the fleet is actually going up because there's such a surplus of sixth-gen rigs and they are going to be the ones to get, as you just put it, to get in the line first before some of these older guys. Is that a fair way to think of what we are going through in this cycle?

No, I can understand how that conclusion might be reached, but, at the end of the day, as I mentioned earlier, the sixth-gen assets are significantly oversubscribed. There's still some in the pipeline that are yet to be delivered, but those sixth-gen assets will compete and displace the fifth-gen assets, but they are not going to compete and displace many of the higher-spec moored assets.

So in terms of mid, deepwater and ultra-deepwater, I think we've got to really look at this from a new perspective and the real -- you can carve this up into basically two categories. You've got DP rigs and you've got moored rigs, and the DP rigs for the most part will not compete down into the niche place that exists for moored assets, and I'm talking about Australia; I'm talking about the North Sea and other certain parts of the world.

So, yes to your question have we upgraded our fleet. Absolutely. I spoke about the Apex. It's currently working at $285,000 a day. We got an extension over $200,000 a day. That's a new rig that was delivered in 2014 from Singapore. I crawled all over that rig when it was being rebuilt. The steel, the bolts, the accommodation, the wiring, the derrick, everything about that rig is new to the extent that it doesn't even look anything like the original hull. We've expanded the deck space and variable deck load. This is a new rig that's being delivered in the moored market that is a very, very capable asset. So have we upgraded our fleet? Absolutely. Are we comfortable with where our fleet exists today in terms of having a broad portfolio? Absolutely. And are we preparing the Company for the eventual recovery in our space? Yes.

Okay. Thanks very much. I appreciate that added color. I just wanted to also ask about the Helical Buoyancy initiative, if you could add a little color to it and really what I was wondering is how we should really think about the effect of it on your rigs and on the market. Is this mainly a potential cost savings for Diamond that's going to make it easier for you to make it through in the current day rate environment, or does this potentially translate into something superior on an operating capability that operators would eventually pay for?

Too early to make the call. I will be honest, this is not going to be material to our earnings or to your models, but what it does do is it makes our fleet more attractive than everybody else's out there, which is half of the battle. It's about providing differentiation. It's about providing or proving to our clients that we are in it with them as it relates to lowering costs to make deepwater competitive against the other capital options they have.

And as it relates specifically to this particular initiative and the work that we've done to basically address one of the flat spots that exists in deepwater drilling and our relationship with Trelleborg, we are not a manufacturer of riser buoyancy, so we have to partner up with somebody who is. And we've spent a while doing a lot of modeling and computer analysis in order to drive efficiency gains and to running the risers. So we've basically completed the heavy lifting as it relates to the innovation and the design behind the project, but we did have to go to a manufacturer and get them onboard to actually produce and manufacture this new riser.

Clearly we don't have the volume requirement that would cover the fixed costs, so somewhat in an altruistic manner we are licensing Trelleborg to build and sell the product to third parties and we get a 5% royalty fee. But from the client perspective, once again, we've shown tangible differentiation. There's not much going on in our space, and our clients like what we are doing and therefore we believe we are building a reputation that is somewhat differentiated moving forward and so should become a little bit more attractive to clients knowing that we are all in as it relates to lowering offshore drilling costs and driving efficiencies.

Okay. So the message is not just sitting there and wringing your hands, but trying to do innovative things as you wait out the cycle?

Absolutely. And for your own models, this really isn't material. It just makes our fleet more attractive to others. If you look at our drillships in 2019 when we have to recontract them -- and let's face it, 2019 is not too far away -- we've differentiated them from a Pressure Control by the Hour perspective. We will be putting this riser buoyancy on them. And of course, they will be hot when they come up for contract. So will they be elevated in the list of desirability? I believe they will be. And this is something that we need to focus and concentrate on in a space that will be very competitive and oversupplied for a good number of years into the future.

Thanks very much. That was great color.

Eduardo Royes, Jefferies.

So my question is, assuming that you start to get some steady demand growth in the deepwater in 2018 or whatever, unless it really takes off, at least on my math, I can see how you still have 40, 50, I don't know, 60, too many ultra-deepwater sixth gen, fifth generation by the end of the decade. Obviously, at that point, you'd probably have some rigs going on four, five, six years stacked, so I know that these rigs are a low-cost option today, but realistically at that point they haven't worked in a pretty long time. So bearing in mind that they are only seven, eight, or nine years old, at what point do you think guys in the industry start doing the math and saying this thing just isn't economic and when do you finally get some ultra-deepwater rig stacking [step] to help in that piece of the balancing out of the market?

That is an excellent question and that's something that we've been looking at ourselves. I think the sixth/fifth-generation fleet will be oversupplied at least through the end of this decade and so some of the assets that are being cold stacked today will have a significant period of not working. And one could argue, are we bifurcating that asset class by cold stacking rigs today that effectively will not come back to work for four, five, maybe even six years, and then look at that as de facto scrapping because the cost goes up every year and there will be rigs that will be more desirable than others. We are already seeing some of our clients refuse to consider in a tender or an RFQ cold stacked rigs. In other words, they are stating they will only consider hot or recently warm stacked rigs.

And then if you look at some of the technical barriers that have to be overcome, if you've got, for example, a BOP that's been sitting on the stump for four or five years without being splashed, there is actually no wellhead that you can sail up to, put this BOP on and test it prior to going on contract. So anybody that contracts that rig is going to be well-aware that getting the BOP back into pass the BSEE requirements or whatever it may be, wherever it is anywhere in the world, is going to have a little bit of a task at hand as it relates to getting the BOP up to standard and tested because there's no wellhead sitting out there that you can actually take a cold stacked rig and spend the consequent time testing the rig or testing the stack in the environment in which it's used. You can test it all you want to on the stump, but let me tell you that there's a big difference between pressure testing a BOP stack on the stump and pressure testing it in 5,000, 10,000 feet of water actually attached to a wellhead.

So I think you are going to see bifurcation of the market. I think you'll see basically rigs that are getting stacked today eventually possibly being scrapped moving forward. And there's a barrier to re-entry. So in other words, if you've got a $100 million reactivation fee, are you actually going to spend that without a contract knowing that there is hot rigs that are coming up for contract further down the road. So I think your question was very pertinent and I think you are on the right track.

Thank you very much. This is just a quick final follow-up. The BlackRhino, while it's not working, is that on a reduced cost, or is that rig fully crewed up?

No, we have de-manned the crew. It is on a reduced cost, but we are also doing specific upgrades for Hess that relate to the requirements on the contract. So, no, we haven't taken it down to full warm stacking cost. It's probably lukewarm. The critical people on the rig are still there. We are doing the necessary upgrades to make the rig even better than what it already was, and we will be going into a final acceptance testing in the not-so-distant future. So it will be pretty quick before we've got a full complement of crew back on that rig.

All right. Thank you very much. I will turn it over.

So thank you for participating in today's call, and we look forward to speaking with you again in the next quarter.

Thank you, ladies and gentlemen. This does conclude today's conference call. You may now disconnect.