Diamond Offshore Drilling Inc (DO) 2016 Q1 法說會逐字稿

Ladies and gentlemen, thank you for standing by and welcome to Diamond Offshore's first-quarter 2016 earnings conference call. (Operator Instructions)

I will now turn the call over to Darren Daugherty, Director of Investor Relations. Please go ahead.

Thank you. 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; Gary Krenek, Senior Vice President and Chief Financial Officer; and Kelly Youngblood, our incoming 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 information reported on this call 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 the statements. These risks and uncertainties include risk factors disclosed in our filings with the SEC, including 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'll turn the call over to Marc.

Thank you, Darren. Good morning, everyone, and thank you for joining us for today's call. As Darren mentioned, with us this morning is Kelly Youngblood, who will become our new CFO as of tomorrow. Many of you already know Kelly from his previous 28-year finance career spent in oilfield services. Kelly will bring additional valuable insight as we consider both future strategic options and the efficient deployment of capital.

And after a very successful 18 years as Diamond's CFO, this will be Gary's last earnings call. I would like to take a moment to thank him for his significant contributions to both the Company and to our shareholders and wish him well in retirement. Gary will, however, continue in a consulting capacity as Kelly transitions into the role.

In previous earnings calls, I have suggested that capital allocation is one of the most fundamental responsibilities of Diamond Offshore's executive team, and this focus will not change with Kelly's appointment. Remaining on this subject for a few moments more, allow me to make some comments on the subject of equity offerings and debt tenders.

Although Moody's downgraded the entire offshore drilling sector during this past quarter, Diamond Offshore retains the highest credit rating amongst our peers. The next best offshore driller as rated by Moody's is a full two notches below us.

This is not just a reflection of the relative strength of our balance sheet and our liquidity profile. It also takes into account our backlog, our fleet, and our operational excellence.

Our recently announced Pressure Control by the Hour service and outstanding fleet uptime are just two examples of what sets Diamond apart. More on both in a moment.

We have looked at debt tenders and concluded that at this time they don't make sense for us. The only bond we have maturing before 2023 is currently rated BBB+ by S&P and is trading at par value. We have ample liquidity not only to meet our remaining newbuild commitment for the already contracted Ocean GreatWhite semi, but also to navigate an extended market downturn.

Although we did not transition to Pressure Control by the Hour for balance sheet purposes, we are also benefiting from the sale of the BOPs on our sixth- generation assets for $210 million, with $105 million received in Q1 and the remainder to be received later in the year. As a result, we do not have any current plans to pursue a debt tender, nor do we have current plans to initiate an equity offering that ultimately dilutes existing equityholders.

On to the quarter itself. For Q1 of 2016, we reported $0.64 per share on a revenue of $471 million, compared to an adjusted $0.50 in Q1 of 2015, and adjusted $0.89 per share in Q4 of 2015.

Earnings from the quarter benefited from additional revenue related to the demob of the Ocean Endeavor once it had completed its contract in the Black Sea, and a favorable tax rate, along with strong operational performance across the entire fleet. Unscheduled downtime dropped to 1.8%, the best quarterly performance we have delivered since 2009.

During the quarter, we saw five rigs finish their term contracts, these being the Ocean BlackRhino, Ocean Endeavor, Ocean Rover, Ocean Onyx, and the Ocean Ambassador. The Ocean BlackRhino is undergoing certain rig enhancements prior to commencing its three-year contract for Hess at the end of this year; and the Ocean Ambassador has been sold for scrap. The remaining three of these rigs will be cold-stacked.

We have also just received notice of cancellation from PEMEX of the Ocean Scepter jackup contract, resulting in a loss of approximately 0.5% of our backlog.

The above aside, we have also had two rigs commence new contracts during this past quarter. The Ocean BlackLion, our fourth and last to be delivered sixth-generation drillship commenced operations working for Hess here in the Gulf of Mexico on a four-year contract. The Ocean Guardian, a third-generation asset, started its one-year contract in the North Sea with Diamond. Shortly, the Ocean Apex, a fourth-generation asset, will commence operations on its 18-month contract following its imminent arrival in Australia.

The Ocean GreatWhite semi remains on track for a delivery from the shipyard in Q3, allowing time for mobilization and customer acceptance testing. We expect this new harsh-environment ultra-deepwater semi to be on location offshore South Australia during Q4 to commence its three-year contract with BP.

Now let me bring you up to speed on Diamond Offshore's unique and industry-first Pressure Control by the Hour service. Since the press release on this new service model at the beginning of February, we have received plaudits from all of the largest deepwater energy and production companies -- to include operators with which we are not currently working. We have been commended for the thought leadership that we have brought for the industry, along with other initiatives we are sharing with the biggest deepwater players as it relates to innovation and the need to deliver efficiency gains to the deepwater industry.

I have already spoken about this particular new model. But since the service went live for two of our new drillships here in the Gulf of Mexico, we already have an example of how this model benefits Diamond and our clients.

Less than two weeks following launch of the service, we were unable to achieve a pressure test during routine operations on the deployed BOP stack of the Ocean BlackHornet. As a result, we had to retrieve the stack from the wellhead on the ocean floor, return it to the deck of the vessel, and repair the unit before redeploying it.

The original equipment manufacturer now has maintenance personnel permanently stationed on the Ocean BlackHornet who were intimately involved from the moment the issue first materialized through to resolution and recommencement of operations. The unplanned stack pull resulted in nonproductive time for both our client and us but, for the first time in our industry, the OEM shared in the financial loss.

Effectively, all parties were truly aligned in addressing the unplanned nonproductive time. And lessons learned were immediately shared with the OEM's design, logistics, and manufacturing teams.

However, this is not only about unplanned downtime. Most stakeholders focus on the unplanned aspects of availability; but when you look at the planned element, this is also nonproductive time for our clients. We are working with GE to incorporate predictive technologies into this service, using their Industrial Internet along the lines of condition-based monitoring and predictive maintenance.

By providing an evergreen certification of the BOP system, we are eliminating the need to bring the system in every five years for a major overhaul. We are also looking at technologies that have been developed around the concept of equipment fingerprinting and acoustics using subsea sensors.

Diamond Offshore continues to push out the frontiers of technology leadership in our space. We have recently completed the installation of the heaviest casing run to date in the Gulf of Mexico. The Ocean BlackHawk successfully ran a complex large-diameter casing string with a dry weight of over 2.5 million pounds to a depth of nearly 25,000 feet.

Put simply, our clients are telling us that we are differentiating our service offering as it relates to our sixth-generation drillships. This is especially important, as it is this market segment that will likely be the most challenged as the industry inevitably recovers.

Further building on our thought leadership, we have recently negotiated first right of refusal with our technology partner for the advanced automation of the drill floor as it relates to our floating factory concept. It is commonly accepted that robotics have delivered significant efficiency gains to adjacent manufacturing industries, and we are continuing to explore ways of transferring this technology to offshore drilling.

Before I turn the call over to Gary to discuss our financials, let me first return to my earlier commentary. I mentioned that capital allocation is a priority, and that my own and my management team's primary objective is to build long-term value for our shareholders. To this end, it is important for us to consider all available strategic options or a combination of options that enable such.

This includes distressed asset purchases, amongst others. However, not all distressed assets are created equal, so we will be selective as opportunities materialize. Valuation and timing will, of course, be key. Gary?

Thanks, Marc. As always, I'll give a little color on this past quarter's results and then cover what should be expected for the upcoming quarter. For the quarter just ended, we reported after-tax net income of $87 million or $0.64 per share. This net income compares to a net loss of $245 million or $1.79 per share reported in the fourth quarter of 2015. Last quarter's loss was primarily driven by an impairment writedown of $499 million which negatively impacted earnings by $2.68 per share.

Contract drilling revenues decreased $100 million quarter-over-quarter, from $544 million in Q4 of last year to $444 million in Q1, primarily as a result of several rigs that Marc has already mentioned rolling off contract and failing to find follow-on work. Partially offsetting this decrease was additional revenues received from the Ocean BlackLion and Ocean Guardian, both of which began term contracts in mid to late Q1.

Also impacting operating revenue in the current quarter was the $40 million of demob revenue recognized by the Ocean Endeavor as a result of its term contract in the Black Sea concluding in January.

With the exception of taxes, the remaining income statement line items for the most part came in within expectations and within the guidance we gave at last quarter's conference call. Contract drilling expense at $213 million was at the midpoint of our guidance of $205 million to $225 million. Depreciation and interest expense also came in around the midpoint, while G&A expense at $15.4 million was at the low end, but still within the range of our Q1 guidance.

The one outlier was in our income tax rate. Despite recording pretax earnings of $83 million for the quarter, we reported a tax benefit of $4 million in Q1. This compares to our guidance last quarter of a tax rate expense of 10% to 18%.

The mechanics behind this anomaly are complicated. But the simple explanation is, we had operating losses in high-tax-rate jurisdictions which generated significant tax benefits, and operating profits and related tax expense in jurisdictions with lower tax rates which, when combined, netted to a tax benefit.

Now for a look at some of the items that will affect our financial performance in the coming quarter. As I stated in our prior conference call, we have no special surveys for rigs in our fleet scheduled for 2016. We do have several rigs that will be mobbing during the year; and we also have some acceptance testing and modification downtime scheduled -- a small portion, which is expected in the second quarter.

For those details I would refer you to our quarterly rig status report that we filed this morning.

We expect rig operating cost for the second quarter -- as reported in the line Contract Drilling Expense -- to decrease quarter-over-quarter for the seventh consecutive quarter and are estimating they come in between $195 million and $215 million. While part of the decrease in this guidance is activity-related, it also reflects our ongoing efforts to reduce cost while continuing to maintain our rigs for the long term.

As always, I remind everyone that I've been talking about the line Contract Drilling Expenses on our income statement, which does not include cost incurred in the line Reimbursable Expenses.

With regard to other items on the income statement, excluding the income tax rate we are keeping our guidance consistent with what we had said in our prior earnings conference call. Depreciation expense for the full-year 2016 is still estimated to be in the range of $420 million to $440 million, with Q2 depreciation costs to come in at between $100 million and $110 million, and then to increase slightly when we began normal depreciation of the Ocean GreatWhite subsequent to the delivery of the rig from the shipyard.

G&A costs are still expected to total $60 million to $80 million for the year, with approximately $15 million to $20 million incurred during each of the quarters of 2016.

Interest expense on our current debt and expected borrowings on our bank line of credit, net of capitalized interest, is projected to total $105 million to $115 million in 2016. Net interest in Q2 should run close to $25 million for the quarter and then increase slightly to closer to $27 million or $28 million in each of the final two quarters, when we no longer capitalize interest on the GreatWhite.

As for taxes, we are now expecting a tax rate of less than 10% for all the remaining three quarters of 2016. Of course, this will vary up or down based on any future changes of the geographic mix and source of earnings, as well as tax assessments or settlements, or movements in exchange rates.

Moving on to our capital expenditure guidance, that, too, remains unchanged. Reflecting decreased rig activity, we believe that we will incur maintenance capital cost of approximately $150 million for the full-year 2016, which is down from our 2015 maintenance CapEx spend of $215 million.

Newbuild CapEx for 2016 is expected to be $525 million, which includes oversight cost and the final 70% shipyard payment for the GreatWhite. Adding those together, maintenance and newbuild capital expenditures are expected to total approximately $675 million in 2016.

And finally, a word on liquidity. As Marc has pointed out, our balance sheet remains in great shape. Our next debt maturities are $500 million and not due until May of 2019.

During the first quarter, we were able to pay down our revolver. And as of March 31, we had no short-term debt outstanding. However, as Marc has stated, we will most likely need to draw upon that revolver for our final payment on the GreatWhite later this year.

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

Thank you, Gary. Although events of the past few weeks suggest that we may have seen a floor in the price of oil, our clients are still looking at ways to curtail expenditures and further cut CapEx through the remainder of this year and again into 2017. As a result, we have yet to see a floor in utilization rates for offshore rigs.

Overall, floater utilization has fallen this past quarter another 5% to 62% and will likely continue to fall into next year at least. With competing sixth-generation assets still to be delivered from shipyards, no scrapping to speak of, and the fastest declining subsector utilization, the industry's sixth-generation fleet is the most distressed of all asset classes.

We believe that Diamond is best positioned amongst our peers to ride out this super-cycle. Between now and the end of 2019, we are least exposed amongst our peers to the oversupply of the sixth-generation market. We have elevated our drillships to the top of the deli line of desirability with Pressure Control by the Hour and are able to participate in the moored asset class with solid fourth- and fifth-generation upgraded assets that will see activity return first.

We have already taken the difficult decision to retire a large number of assets, rightsize the organization, and continue to enhance our brand by focusing on opportunities to drive efficiency gains for our clients.

So with that, let's take some of your questions.

(Operator Instructions) Robin Shoemaker, KeyBanc Capital Markets.

Thank you. Wanted to start out by asking you in terms -- we see a lot of contract renegotiations and blend-and-extend type of deals; and clearly if you had something to announce you would. But I just wonder if -- what your current thinking is along those lines, and with your customers, with your key contracts in backlog.

Robin, good morning. This is Ron. The market today I think provides ample incentive for operators to renegotiate contracts, and we understand that motivation. We do get that.

On this side we do believe in contract validity. We'll work with customers to find mutually agreeable trades that help both parties. And as you indicated, we're not announcing anything new today in that regard.

We've done some good work before with customers to make those trades for mutual gain. I think we've earned a reputation as a partner that helps solve problems while serving both of our shared interests.

So we understand that motivation, and we certainly have a capacity, I think, to make those mutually agreeable trades, although nothing specific to announce today. But there is no doubt, Robin, that the market today certainly motivates customers to look for those trades and gains.

Okay; thank you. If I may, just one other question. You mentioned that Diamond is capable of making and would be interested in looking at a couple of rig purchases in this downturn, as you have in previous downturns. I wonder if you've looked closely at a couple of rigs that have sold here in recent months, and what your criteria would be.

More specifically, would you look at perhaps purchasing a high-end deepwater asset that does not have a contract for which would be -- for which you do not have a contract lined up upon purchasing it?

Sure, Robin; look, as I mentioned in my prepared remarks, we do not see all potentially distressed assets in the same wide. Specifically, as you are referring to, the two assets that have come to auction so far are not what I would call high-spec when lined up against other drillships, whether it's the hook load, the BOP capability, the draw-work compensator, and even the historical uptime for an asset.

One of these assets that came to market had a 19% nonconstructive time history over the past three years. And a significant amount of that, by the way, is associated with the BOP stack.

So you have to look at the desirability of the vessels that come available and how they will stack against other vessels vying for contracts in the future that will be coming off contract hot, as well as vessels that, for example, will be better equipped that also have been stacked.

Look, first of all, I believe we have to see a floor in the utilization of the offshore fleet. Then we have to see the higher-end vessels and those that are hot be re-contracted.

And this won't happen until, first, the E&P companies start to test the proverbial water with the sanctioning of new projects. And then even before that, we will likely need to see an oil price stability over $60.

Then when you add the cost of stacking and the reactivation costs, it should be easy to understand why we here at Diamond do not see any shareholder benefits to chasing the low-spec sixth-generation assets, irrespective of the price. And I say this as the offshore driller with the best contracted position on sixth-gen assets, as of course all of mine are contracted out to 2019 and beyond at decent dayrates.

Okay. Good; thanks for that explanation.

Ian Macpherson, Simmons.

Thanks; good morning. I wanted to see if I could dig in a little bit on the Pressure Control by the Hour accounting. Was there any -- when you took the first half, I guess the first $105 million in sale proceeds in Q1, was there an associated revenue effect with that? Or was there no effect on the P&L?

And then just timing on the last two throughout this year. And then lastly, is the GreatWhite a candidate for a similar program as well?

Hey, Ian; it's Gary. There was no P&L effect on that in the first quarter.

Okay.

(multiple speakers) balance sheet, but nothing on the P&L. As far as the timing of the next two, we expect one of them at some point in the second quarter, probably the latter part of the second quarter, and then the final one early part of the fourth quarter.

So on to the GreatWhite, I think if you look at the three original equipment manufacturers, clearly one of them, as we know, is prepared to go down this path. The second one is -- well, there is a second one that is also prepared to go down this path.

But the final company I think is somewhat holding back, and that's the company that we have the BOP from as it relates to the Ocean GreatWhite. So at this moment in time, we don't have any plans to take the Ocean GreatWhite down that path.

Okay; thanks. Thanks, Marc.

On the Ocean Scepter, is there a dialogue to renegotiate a new contract for that rig at a lower price for PEMEX? Or is that rig more likely to be stacked?

Ian, hi, it's Ron. The short answer is really there's not an active conversation to try to lower that rate and keep that rig alive. I think we've talked before -- PEMEX has this unique contractual right which they've exercised on termination. It does not exist elsewhere.

Although I think before we would have played, I think, to try to move some rates around and keep some rigs alive, I think we have to acknowledge the market we're in today, where Mexico and PEMEX is today. And I think it's fair to consider that rig will likely I think draw to a close here. So I don't expect any second-bounce announcement on the Scepter with PEMEX.

Okay. Thanks, Ron.

Rob MacKenzie, IBERIA Capital.

Great. Thanks, guys; and congratulations, Kelly, on the new job.

Thanks a lot, Rob. Appreciate it.

Following up on the jackup question with the Scepter, with this being your last active jackup, does this mean you guys are looking to potentially exit the jackup drilling space, and/or are you interested in perhaps adding back some more assets at a later date?

From a jackup perspective, the Scepter is a very, very capable unit, so we'll be hanging on to it. We won't be exiting the jackup space.

Okay. How do you think about critical mass in that space? You have the one rig in Mexico, the rest of them are cold-stacked at this point and largely older assets. Do you feel you need to bulk up in terms of quality assets there, or are you happy just running the one unit?

No, I don't think so. I think whether it's jackups or floaters, we won't necessarily be bulking up on the jackup side. I think the jackup side will end up more distressed than many of the floater -- well, the floater subsector. I think the jackup market will be more distressed.

But this is a very capable unit, and we do see opportunities to bring it back to work as the market turns around.

Okay, thanks. Then would you mind updating us on your thinking on the floating factory concept, and any customer conversations, and where that may stand in terms of building the semi-of-the-future for 2018 or later?

Sure, Rob. Well, there have been two RFIs issued over the last few months, or requests for information, as it relates to the kind of assets at least two of the larger IOCs are considering to, let's say, have contracted in their fleets in the 2020 and beyond time frame. We're not talking about a typical sixth- or seventh-generation asset. In one case, the RFI actually referred to an eighth-generation asset -- I believe a term you may have heard first from us.

But of course we are branding it the floating factory because that is what it is. As I mentioned, Diamond has secured the first right of refusal with our partner for much of the technology that we see can bring material efficiency gains for our clients. And together with these two IOCs, we are performing diligence on that technology.

And I will stop there. I will say no more at this time, other than to suggest that if you look at it from a capital-allocation perspective, it is important as a Company with our balance sheet and our liquidity to have a series of options that can be played off against each other.

I'm not saying that we're going to build a floating factory at this time. But Kelly and I will be looking to have as many options as possible on the table over the future coming quarters, and we will not be declaring on any single one or combination thereof at this time.

Suffice to say that we've got some very capable people here at Diamond Offshore who are working very, very hard on the next innovation that can bring efficiency gains to the end users, to our clients.

Great answer. Thank you. I'll turn it back.

James West, Evercore ISI.

Hey, good morning, guys. Gary, congratulations on your retirement. I'm sure you'll miss talking to all of us. And Kelly, congratulations on your new job.

Thank you.

Thank you, James.

Marc on the floating factory concept that we've been talking about for a while now, it seems like you're shifting a little bit to some of your current rigs in that. You talked a little bit about robotics and trying to enhance the capabilities there.

Could you maybe describe in further detail how you're thinking about the existing assets versus new assets? And perhaps how you can take existing assets and make them into maybe a semi-floating factory, if you will, something like that.

Sure, James. The best solution here, when you take a look at the floating factory concept, is truly to -- from a white sheet of paper, start from scratch. Many of the assets that we've got in play right now are, frankly, onshore rigs that have been put onto a ship.

If you take a look at the floating factory concept, we're looking at lean manufacturing principles applied to every aspect of the deep-water drilling processes. As we talk to our partner of choice around these technologies, there are certain aspects that can be retrofitted onto current assets, such as automated slips, etc., etc.

But the true efficiency gain for something like the floating factory is when you combine everything together into a series of seamless processes that can take flat spots out of the drilling process and deliver substantial efficiency gains. As an industry, we've survived through continuous innovation; and it's times like these, frankly, where we get our best brains focusing on keeping the cost, the BOE cost, of our commodity as low as possible for our clients.

As we talk to many of the larger IOCs, they have traction and interest in what we're trying to bring to the table. Now, I'm not going to sit here and say this is a slam-dunk as it relates to the capital efficiency moving forward. We have a lot of options on the table, to include the acquisition of distressed assets.

It has to be the right distressed assets at the right time. Or we're probably one of the few companies, now that we've locked up first right of refusal on this technology, to consider other things as well that might be out there.

Like I say, this is all about the efficient use of capital and capital allocation moving forward that is in the best interest of my shareholders.

Got you; okay. Okay, that makes sense. Then perhaps for Ron, in terms of customer behavior and what they're doing with your rigs today that are working, is there more of an emphasis on things to enhance recovery, sidetracks, things of that nature, rather than making -- creating new wells? Have you seen any noticeable or discernible difference?

Yes, great question; makes a lot of sense. Right now I think, as a broad trend with customers we do see them looking for ways to get -- to squeeze every last drop of productivity out of those assets any way they can. So they certainly are, I think it's fair to say, very focused on getting that maximum value out of our rigs.

If that means looking at existing wells more thoroughly, that's a very, I think, understandable theme. So they're approaching, I think, each new step with a very mindful and somewhat purposeful attitude that may -- perhaps even in contrast to some time ago.

So I think the theme you are on is real, and we do see that. Because they want to be sure from their standpoint that they certainly get the best value out of each day on our rigs. So I think that theme is really there.

Okay, got it. Thanks, guys.

Greg Lewis, Credit Suisse.

Yes, thank you and good morning. Gary, congratulations; we will definitely miss you. Thanks for all the help over the years.

And, Kelly, congratulations on the new spot.

Ron, I just had a question. It seems like we've heard some noise that Brazil potentially is coming back and looking to renegotiate contracts with service providers. Is that something that is out there in the market? Or is it something that at this point is just more talk than anything else?

Yes, it makes a lot of sense, your question. As a broad theme I think your comments make a lot of sense overall.

Certainly with their large position, with Petrobras, a long position on the rigs, there is certainly a strategy I think to pull back. So overall I think that that comment makes sense.

I think more specific, though, to us, we feel, I think, pretty confident in the high-spec contracts we have today with Petrobras. I think as you saw, previously we did add some term on one of our rigs down there, which I think was a good move, I think, for us overall.

But if I were to score where I see the renegotiation bubble moving along, for us right now I wouldn't describe it as very active with Petrobras. I think we are where we are. We like our contract position of high-spec assets through 2018, and look forward to pass a better market on the other side of where we are today.

So right now, not as most -- not a very active space for us in terms of renegotiation.

Okay, great. Then just one final one for me. Just as we look at the fleet, there is the Valiant and the Endeavor that have the potential -- have open days in 2016. Just as we look at the stacked fleet -- and realizing there is not a whole lot of work going on, but we have seen tenders pop up in the market -- just as we look at the stacked fleet, is there any way to quantify or estimate how many of those rigs are more in the warm-stacked category and can continue to be bid into work?

Yes; thanks for that question. If you look at the Endeavor and the Valiant, those are two rigs where we certainly see, I think, a future ahead in our fleet. Valiant I think has been picked up with some option wells from the customer there a few times because they like the productivity, the relative low cost, I think, of what others can do.

So I think if I look at the Valiant and Endeavor both, I think those are rigs that have good futures. From an asset utilization standpoint, though we have to, I think, be very purposeful in what we do. And although the Endeavor has a good career ahead, without a known contract right in front of her, I think we'll look to take her costs down smartly and quickly.

So I wouldn't model her being in a warm mode. I just don't see it as part of our ongoing approach.

But I do think longer-term you'll find both Endeavor and the Valiant will add to our revenue stream going forward. I think, unlike many, we have the good fortune of having a fairly good contract coverage where we in fact can make those moves: both take care of utilization today but also play for the upside tomorrow.

Perfect. Thank you very much.

Lukas Daul, ABG.

I was asking about -- can you share some of your thoughts on the new regulations in the US Gulf of Mexico? What do you think the impact will be? And how is it going to affect the activity there?

Yes, sure. Well, let's see. The regulations were not quite as onerous as we first feared as an industry, for example. Common sense prevailed on a number of issues.

An example that I'll bring up right now is the five-year inspection of the BOP. That was instead of a five-year one-time strip-down; that got changed to a staggered inspection for each component, which for our working assets in the Gulf of Mexico -- for example, our Black ships -- the OEM will be responsible for that. So not only the inspections but also the ongoing certification; and we'll take care of the documentation and tracking as a result.

On the other hand, the requirement for, let's say, the shear rams, to centralize the pipe during shearing, will require certain upgrades. But in that particular example, the industry has a seven-year compliance period. Whilst not all OEMs currently provide for that feature, it will be, let's say, relatively expensive to upgrade; but we've got a seven-year compliance period on that.

So, much of what was ultimately promulgated is not that different to what API S 53 requires. In this respect we believe the regs have less of an impact on our fleet than what we first feared.

So overall I think from a relative perspective it was an exercise where sense prevailed, and BSEE did indeed listen to and take note of the feedback that the industry gave them over the past 12 months. So it will have an impact, but certainly not nearly the impact that we first feared.

Okay; good color. Then, Gary, you're continuing to guide on a further decline in your OpEx. Some of your peers have mentioned that we have come as far as we could in terms of reductions. Do you think that trend -- how long do you think that trend can continue?

Well, part of the decline, as I pointed out, is activity-related. Therefore I hope we have no more declines based on that.

But for the most part that is true. Most of the reductions that we at least have plans for are in place at this point. Depending on what happens in the industry, the Company certainly can do other things.

But remember, you want to be able to operate these rigs long-term. Therefore you have to do maintenance on those rigs and continue to spend the money to make sure that they do operate for the long term.

So the Company will continue to reduce cost as much as possible, but do it in a very sensible manner.

If I could just come in on that, a significant amount of our expenses are labor-related. As it relates to rigs coming off of contract, you could look at that as somewhat of a variable expense. But as it relates to our fixed overhead costs, we took a large ax to the organization over a year ago now.

And as oil prices have bottomed, we know a recovery will come; we just can't say when that will come. It's very important that at the executive level we look at the organization from a sustainability perspective. If we are to exit this downturns in a very, very strong position, it does mean that we start looking at things like the floating factory and we have the right resources in place to ensure that the fleet is well maintained in preparation for a recovery, and that we consider using our own in-house resources, opportunities that could be unique to us, as we exit the inevitable -- and ride the wave that is inevitable recovery.

So in terms of fixed cost I think we're probably there. In terms of variable cost we still got an opportunity as rigs come off of contract to reduce expenses.

Okay; thanks, Marc. And thanks, Gary, and good luck as a cowboy and a rancher.

Thanks, Lukas.

Darren Gacicia, KLR Group.

Hey, thanks. First, thanks, Gary, for all your help over time. And Kelly, congratulations on the new seat.

I wanted to follow up on Lukas's question with the BOP rules. Does that change -- in terms of some of the older rigs, I know that you mentioned in your answer about the seven-year compliance period. Does that give a window to maybe say that some of those assets [go] because you won't want to pay for the upgrades? Or how does that apply?

Maybe it's just a broader question about some of your stacked rigs as well, in terms of your thought process on the future.

Yes, we've done a lot of work around reactivation cost because that's not immaterial moving forward. We'll watch the clarification on the BSEE rules [did] for us because actually on some of the third- and fourth-generation assets, which I will say many have already been upgraded.

I'll also point out we have a third-generation asset starting work this past quarter. The Ocean Apex, I believe, this morning, 5:20 Singapore time, has just started its transit down to Australia, ready to commence work down there.

So we've got a number of third- and fourth-generation assets that aren't necessarily here in the Gulf of Mexico that will have a life ahead of them. No doubt about that.

As it relates to the Gulf of Mexico, let's talk about the reactivation cost just for a minute. That will, as you suggest, will vary according to asset class.

But when you bring a rig down and you cold-stack it, you could be looking at a special survey, recertification of the BOPs, other equipment, to include not just the drilling kit but of course the marine as well. Then when you bring a rig back up you've got to consider the hiring and training of rig crew and swallowing the cost of, frankly, what could be a significant customer rig acceptance test.

So you could be looking at cost that sometimes could approach $80 million, $90 million and more. This is why a client will always go for a hot rig over one that has been stacked for any period of time.

It relates to the BOP and reliability around the BOP. There's no spare wellheads that you can hook up to, to test the BOP, that has not been splashed for three years. So the client isn't necessarily going to take on that risk.

So many will prefer not to if they have an option. For the offshore drillers we believe that as it relates to the Gulf of Mexico and the backlog we have on our sixth-generation assets, we're actually in a pretty good position, as it relates to bringing cold-stacked rigs back into service here in the Gulf of Mexico. It's an issue that perhaps is less of a problem for us than it is for our peers.

There is something else you've got to consider here as it relates to reactivation costs of cold-stacked rigs, and that really is related to the NPV when you look at the cost of the reactivation itself. Allow me to suggest that if the market is transactional when it first returns, to start with, idle rigs may remain idle until the hotter and more capable rigs have been absorbed and then dayrates have recovered to the appropriate level.

So there's a number of things that come into play here as it relates to stacking and bringing rigs back into the market. But from our fleet, as it relates to the well over $5 billion that we've invested over the last five or so years on upgrading our fourth- and fifth-generation assets and investing in the sixth-generation fleet, we actually believe our fleet is actually very well positioned to ride out this downturn and actually be well placed for any recovery, especially as it may be transactional to start with.

Got you. Going over to the maybe new rig acquisition side, you maybe comments out of the gate about how you're looking at that. Are those conversations now happening more with shipyards? With individual companies?

What's changed in the dialogue around even thinking about that, say, over the last six months?

Well, I think from our perspective, timing on the recovery. You pick up a distressed asset today; you're going to have to cold-stack it. And on a sixth-generation asset, that is not an immaterial daily cost.

Then you've got to look at the reactivation cost to bring it back into the market. As I was alluding to a little bit earlier in my commentary, I think we might actually see pricing recover faster than one might assume right now, and that is because of the cost of bringing a stacked rig back into the market.

For example, you're not going to chase a transactional market if you're looking at a capital investment of, say, anything between $50 million and $90 million for a stacked asset. So if you look at it from a shareholder value perspective, let's say picking up the last -- well, this is one of the primary reasons why there were so few bidders on the two assets that we've seen come to market already. And that is, what kind of cash flow will you receive over the next five or so years from those assets?

I spoke to the fact that they weren't the best. People call them high-spec assets, but you've got to look at it in a relative perspective around the sixth-generation fleet. And, frankly, there are better sixth-generation assets that might come to the market from the shipyards or from a distressed seller, for example.

So it's actually quite a complex process when you go through and you do the diligence around what is available, what price you're going to pay, and how much value you're going to get back from those assets. We looked at the two assets that came available; we did not participate in the auction, unlike some have been suggesting, because we believe there possibly will be better opportunities with better assets that will be more attractive when the market recovers.

So it's all of the above. Yes, it's talking to the shipyards; it's talking to the owners of distressed assets and figuring out the likely shareholder value that you could get in return for that investment.

Well, how do you weigh that out with timing of trying to execute versus maybe other people competing with you for the asset?

Well, you know, we'll always fact that. There will always be competition and others coming into the market. But at the end of the day, you've just got to look -- you've got to be disciplined; you've got to know the true value of the asset that you're chasing.

That's one of the five fundamental components around capital allocation and the efficient use -- of deploying it. So, okay, there might be times when we'll go and chase an asset but others are willing to pay more for it, and we'll just step back and allow them to do so. But at the end of the day, there is limited capital available in the market itself.

Some -- if you look at where we are positioned, as a company compared to our peers, as it relates to the contracted availability of the sixth-gen assets, we are by far the best positioned moving forward. Some companies are still worrying about how they're going to contracts sixth-generation assets that are yet to be delivered. I don't have that problem. We don't have that problem here at Diamond Offshore.

So there might be others that have a similar balance sheet to us, but they've already got uncontracted assets and they're going to be trying to figure out how they're going to put those to work, whereas from the sixth-generation fleet I don't have that problem.

But as I've been -- the theme of my call, it's about maximizing long-term shareholder value. It's about the efficient use of capital and the allocation of that capital moving forward.

So we will be conservative. We will put a lot of diligence around how we spend our money moving forward. But at the same time, we will be prepared to position the Company to exit the downturn and ride the next wave.

Thanks. That's helpful; I appreciate it.

Mark Brown, Seaport Global Securities.

Hi. Congratulations to Gary and Kelly as well. I wanted to ask and just to clarify with the BSEE regulations. I know you've given some great color, but do you expect operators to require the same level of standards in regions outside the Gulf of Mexico on a go-forward basis? And is that of any concern?

We could hypothesize as to how that will develop over the course of the next few years. I think in general you could see a transition to BSEE regulations on a worldwide basis, but with -- when you put a grandfathering of seven years plus on many of these issues, many of the BOPs, for example, will have to be upgraded in the next seven or so years.

I think the market will be very different certainly as it relates to the 2020 time frame. We have seen this floor in the oil price; but for the first time a number of commentators -- and it relates to just some senior people in our industry; for example, a gentleman who is on the Board of Aramco right now, as well as some of the larger consultancy houses and investment houses out there -- are suggesting that we may see, don't be surprised to see, price of oil at $100 and above in the next three and a half, four years' time. And when we're in that time frame, by holding on to assets that we believe have a future, as Ron mentioned earlier in the call, there will be in that market an opportunity to put them back to work at reasonable dayrates that would allow you to spend the investment from a CapEx perspective as, perhaps, these rules and regulations transfer across the world.

So from a BSEE perspective, let me just reiterate here. We have a mixed fleet that has been upgraded. We're very comfortable in the assets that we have.

We are able to put third- and fourth-generation assets to work in this market, as I've already illustrated. And for those that we feel appropriate, we will invest further CapEx keeping these assets working in the future at some stage.

Everyone is focused on the sixth-generation assets -- the DP, ultra-deepwater assets. But there will remain an asset class that is primarily moored basis, Australia being a great example, the North Sea. And we will invest from an appropriate perspective in those assets that will service those particular markets as it relates to the BSEE regulations.

To really sum up the point, the BSEE regulations, as I've already stated, have been issued and they're not as onerous as was feared by the industry, but only a month ago. So from our perspective, they are certainly something that we can work with. But in certain cases, it will make sense to invest the appropriate CapEx to keep these rigs working, moving forward.

Thank you, thank you. Last question is on the three rigs that you sold in the fleet status. Just curious. What sort of value were you able to get for those, either as sales or scrapping?

They were scrap sales, so minimal amounts.

They were -- we had already written the assets down, and we got a very, very small amount to get those. The Titan we sold for -- it did have some residual value about scrapping value. But for the most part we got slightly more than we had written down for.

Thank you.

Okay. Thank you for participating in the call today. As always, we look forward to speaking with you again next quarter, where you'll be hearing a lot more from Kelly.

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