Diamond Offshore Drilling Inc (DO) 2016 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Diamond Offshore Drilling Inc. Q4 2016 conference call.

(Operator Instructions)

As a reminder, today's conference is being recorded. I would now like to introduce your host for today's conference call Mr. Samir Ali, Director of Investor Relations and Corporate Development. You may begin, sir.

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

Before we begin our remarks I remind you that the information reported today only speaks 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 for any future results or performance expressed or implied by these statements.

These risks and uncertainties include the risk factors disclosed in our filing with the SEC included in our 10-K and 10-Q filings. Further, we expressly disclaim any obligation to update or revise 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.

Now I will turn the call over to Marc.

Thank you, Samir. Hello everyone and thank you for joining us this morning.

I will start by going straight to the headline numbers for this past quarter. As you have seen we announced earnings per share for the fourth quarter of 2016 of $0.53. This includes a $0.26 benefit arising from the settlement of a contractual dispute with a client in the North Sea.

Diamond's adjusted earnings per share for the full year of 2016 was $1.43, which compares to an adjusted $3.10 per share in 2015. The year-over-year decrease was primarily driven by the continuing reduction in the demand for offshore drilling rigs and the lower dayrates for those rigs that were re-contracted during the year. Offshore drilling is cyclical in nature, and despite some stabilization in the price of oil we have yet to see a floor in the declining demand of deepwater assets.

I will speak further to the market in a moment, but first allow me to discuss some fleet highlights. Recall that we have completed our fleet renewal program and have taken delivery of all five of our newbuild sixth-generation assets. With the addition of the Ocean GreatWhite, Diamond now has one of the youngest active fleets with an adjusted age of approximately 10 years, well below the industry average of 14 years.

Diamond does not have any assets delayed in shipyards with deliveries pushed out multiple years, nor as of today do we have any sixth-generation assets that are uncontracted. All of our sixth-generation fleet, the asset class which I consider to be the most distressed, are contracted through 2019 and beyond at solid dayrates. In this respect we are unique amongst our peers.

During the summer of 2016, we took delivery of the world's largest harsh environment sixth-generation semisubmersible drilling rig, the Ocean GreatWhite. The rig had been commissioned and contracted by BP to undertake its exploration program in the Great Australian Bight. Following the subsequent cancellation of this program, the rig will remain on contract, having been placed into service following its successful rig acceptance test.

For the immediate future the decision has been made to place the rig into an extended standby period during which alternative drilling opportunities for the rig will be considered. This extended standby period with the asset moored in Malaysia keeps key personnel on the rig at a lower operating cost than what we would have experienced operating in the harsh environment of the Great Australian Bight.

As a result, we have worked with BP to lower the rig operating expense and to pass cost savings over to them in the form of a new standby rate. This revised rate still enables Diamond to maintain the same operating margin and cash flows of the original contract. We view this structure as beneficial to both Diamond Offshore and BP as it allows Diamond to keep the rig partially crewed under contract and maintained with the same operating margins while our partner is able to reduce expenditures as they source other work for the rig.

This is a win-win for both parties. And we now have the only Moss CS60 design harsh-environment semi that is being delivered from a shipyard. In summary, the Ocean GreatWhite has commenced a three-year contract at a revised dayrate that protects our original contract margins.

So moving on to our sixth-generation drillships, the Ocean BlackRhino, in the coming days this drillship will go on hire at a dayrate of $400,000 per day, joining its sister rig, the Ocean BlackLion, on a three-year contract for Hess' Stampede project in the Gulf of Mexico.

And turning to Brazil the Ocean Valor remains on a standby rate as we progress our dispute with Petrobras. We announced last August that Petrobras had notified us of the cancellation of the contract. However, we were successful in obtaining injunctive relief against contract cancellation and a court order remains in place today upholding the contract.

Last quarter, Petrobras lodged an appeal against the injunction which is still progressing through the Brazilian courts. As it relates to our other in-country operations and opportunities, our working relationship with Petrobras remains sound.

Now I will switch to recent contractual activity amongst the rest of the fleet, highlighting the previously announced awards on the Ocean Valiant which is on contract and the Ocean Scepter which will go on contract imminently. The Ocean Scepter allows us to maintain a presence in Mexico while at the same time laying the groundwork for the contracting opportunities that will be presented in Mexico's deepwater basins. Also during the quarter we extended the Ocean Valiant contract by an additional four months.

And today we announced a contract commencing in June 2017 for the Ocean Monarch for BHP Billiton Australia. The Monarch is currently undergoing a special survey in Singapore prior to commencing the contract. It is one of the largest, most capable rigs with an Australian safety case and we are optimistic that she will continue to win work in Australia over the coming years.

So let me now return to general market commentary. Our views have not changed from previous calls in that the offshore drilling market continues to be oversupplied in the near-term. Deepwater fleet utilization continues to decline, and we have yet to find a floor that will lead to an eventual recovery.

We are now entering an unprecedented third consecutive year of declining investment in offshore spend. According to the International Energy Agency, however, demand growth for hydrocarbon remains robust and in order to meet this demand we will need an additional investment every year through 2040 that is at least 70% on average above current levels.

Even allowing for the growth of unconventional shale production, we estimate that the markets will need to find an additional 10 million barrels of new deepwater supply over the next decade and a half. This is a larger amount than what is currently produced from deepwater today.

Although the next few years will be challenging for offshore drillers, we have uniquely positioned Diamond Offshore to take best advantage of a recovery either in 2019 or 2020. For example, our sixth-generation fleet is contracted through 2019. Our clients have a strong preference for rigs that have recently completed other work; in other words, rigs that are hot.

They do not want to take the financial or time risk of qualifying a rig which has been stacked for a lengthy period. We are already seeing some tenders illustrate a strong preference for rigs that are hot. As the market recovers our rigs will be finishing up their contracts and will, therefore, be the most attractive to our clients.

And we continue to drive thought leadership in the industry from both a technology and process basis. Necessity is the mother of innovation and we continue to discuss with clients opportunities around the Floating Factory concept. The design is complete and with our partner we are progressing full-scale testing of the drilling package.

Certain IOCs and NOCs are engaging resources with us as it relates to understanding the technology and the efficiency, safety and reliability improvements this new rig brings as they themselves start to consider a time when they have to return to deepwater exploration and development. Also our Pressure control by the Hour construct is now fully implemented on our four drillships and the original equipment manufacturer is committed through financial incentives to improve BOP uptime.

While we are not expecting to see immediate binary improvements in subsea MPT, the journey has begun and the design for reliability ethos is in place. We are already discussing multiple component upgrades with the OEM as we monitor and digitally evaluate current reliability issues. Although we are starting to see similar deals introduced by our peers, we remain the only driller that returned the ownership of the BOP back to the OEM and then consequently leased it based on uptime availability.

Now I will return the call over to Kelly to discuss the financials for the quarter and then I will have some closing remarks. Kelly?

Thanks, Marc. We reported after-tax net income of $73 million, or $0.53 per share, for the fourth quarter of 2016 compared to third-quarter results of $14 million or $0.10 per share.

Our net income in the fourth quarter benefited from a $36 million, or $0.26 per share, settlement agreement that was reached with a North Sea client related to a prior-year contractual dispute. As part of the settlement terms, the client's name will remain confidential.

Other noteworthy items for the quarter include the following. First, contract drilling revenues of $385 million during the quarter represented a sequential increase of 13%, which was largely driven by the customer settlement agreement just discussed. Excluding this item, contract drilling revenue increased approximately 3%, driven by the November start-up of the Ocean Valiant contract with Maersk and improved operating efficiency compared to the prior quarter.

Contract drilling costs came in 7% lower for the fourth quarter compared to the third quarter. As discussed in our third-quarter call we continue to proactively manage our cost structure and are clearly seeing the results of these efforts play out. Driving the improvements for this quarter was a combination of lower personnel cost, reduced shore-based expenses and supply chain optimization efforts all being key focus areas of our recently implemented cost reduction initiatives.

Although we will remain focused on innovative ideas to further streamline the organization, we are not anticipating material changes to our base cost trends in the coming quarters, with the exception of cost movements related to ramping up or winding down contracts as outlined in our rig status report. Depreciation of $86 million and interest expense of $21 million both came in below guidance as a result of the Ocean GreatWhite been placed into service later in the quarter than originally expected, which had delayed the start-up of depreciation expense and allowed us to capitalize a larger portion of interest cost.

Finally, we recognized a loss of $5 million during the quarter related to the scrap sales of the Ocean Quest and Ocean Star and three jack-ups, the Ocean King, the Ocean Summit and Ocean Nugget. Also in the coming days we expect to finalize the sale of the Ocean Spur which is the last remaining rig that we have classified as held for sale.

Now let me provide some thoughts about the first quarter of 2017, and given the fluid nature of the market I will only be providing full-year guidance on select items. First, we have several moving pieces in the first quarter that when netted out point to a flattish revenue quarter in Q1 compared to Q4 2016 after adjusting for a customer settlement that benefited our results in the fourth quarter.

The Ocean GreatWhite, Ocean BlackRhino and Ocean Scepter will all begin new contracts during the first quarter. However, partially offsetting this incremental revenue is the Ocean Monarch that will be off dayrate this quarter, then will be mobilized for a special survey and other contract preparation activities in anticipation of renewed contract that will begin in the second quarter. In addition, although now resolved we had a rough start to the year with some equipment-related downtime with some of our rigs which is reflected on our rig status report.

We expect contract drilling cause for the first quarter to come in between $215 million to $220 million and this sequential increase is driven by the start-up of the Ocean GreatWhite that went on dayrate in mid-January, the ramp-up of the Ocean Scepter and Ocean BlackRhino contracts and special survey-related costs for the Ocean Monarch. We estimate our depreciation expense to be approximately $90 million for the first quarter of 2017. The sequential increase over the fourth quarter is the result of the Ocean GreatWhite being placed into service. For the full-year 2017 we expect depreciation to come in at approximately $340 million.

G&A costs are expected to be around $15 million to $17 million in the first quarter, consistent with our recent run rate. We currently expect for G&A costs to remain at this level for the remaining quarters 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 be approximately $27 million in the first quarter and is expected to be at similar levels for the remainder of the year. We anticipate our effective tax rate to be approximately 20% in the first quarter. Then, of course, the rate may fluctuate up or down based on a variety of factors including but not limited to changes of geographic mix of earnings as well as tax assessments, settlements or movements in exchange rates. For our capital expenditure guidance we estimate that we will incur maintenance capital cost of approximately $135 million for the full-year 2017.

Finally, I would like to briefly address our thoughts around issuing equity or buying back debt. For now, we are comfortable with our balance sheet and liquidity and do not see a need at this time to raise additional equity. Our next debt maturity is May 2019 for $500 million and these bonds are trading at a premium to par. We will continue to monitor the debt markets and industry dynamics as we navigate this downturn, but for the foreseeable future we believe we have ample liquidity from cash and our currently undrawn revolver which is in place through October 2020.

And with that I will turn it back to Marc.

Thank you, Kelly. Without doubt 2016 has been another turbulent year for the industry and 2017 will likely show little if any respite. We cannot control the deepwater market but we can best position Diamond for the eventual recovery.

And before opening it up for questions let me remind everyone on what makes Diamond Offshore best-in-class. Firstly, backlog. We have secured a backlog position that helps us navigate through what will be this protracted downturn. Recall that we secured the last available term contract for sixth-generation assets, enabling us to take delivery of our sixth-generation rigs without having to defer them for multiple years.

Secondly, Pressure Control by the Hour. We have differentiated our drillships by using the Pressure Control by the Hour construct, a model that has since been copied. However, Diamond was the only driller that was able to raise $210 million in the process.

Thirdly, the Floating Factory. We have provided further thought leadership to the industry by bringing lean manufacturing principles to the deepwater well construction process. The Floating Factory design is complete.

Next, cost management. We have reduced costs swiftly and early. In 2016 we were able to lower our operating costs a further 37% over the prior year through fleet rationalization, headcount reductions and supply chain savings.

Lastly, liquidity. We took early steps to strategically position the Company from a liquidity and balance sheet perspective that enables us to best navigate this downturn.

So on that point I will open the call for questions.

(Operator Instructions) Cole Sullivan, Wells Fargo.

Hi, good morning. On the GreatWhite's standby rate I understand the cash flows will be the same as before.

How do we think about the rate level versus the 585 that was originally contracted? And I guess what OpEx was reduced during that standby period?

Good morning this is Ron Woll. I think we should, first, acknowledge that the commercial, technical and operational achievements bring this rig from concept to completion including the Australian safety case.

We all see shipyards with idle rigs that can't get across the finish line. And so we were glad to work with BP collaboratively to figure out what is the right new structure for the contract given their post-Bight plans.

And as Marc mentioned the agreement keeps Diamond margin neutral compared to the operating rig in the Great Australian Bight at 585 a day on. And so although we won't get into the exact details of the agreement or the rate, I think, Cole, if you run the revenue models in the mid-400s I think that will probably serve the analysis pretty well.

Rig maintenance continues, and she's kept in a ready state but as Marc mentioned below full crewing. We are working with BP to look for either potential sublets or other work as both BP and Diamond want the rig to go to work. It is also worth noting that the other operators do maintain leases in the Bight, so we are glad to have the GreatWhite in our fleet and are confident that she will go to work.

All right, thanks. I guess you guys have been successful in Australia with the Monarch contract there. How do you see additional rig demand developing over 2017, particularly for I guess a follow-on on the Monarch and then I guess in the North Sea where you have some availability?

Again, this is Ron here. So the Monarch as we mentioned heading off for surveying and contract prep. We do see her active in our future, and although the overall offshore sector, obviously, has well understood supply-demand pressures, Australia on a relative scale is perhaps a little bit more active than other markets.

So we do see operators continue to express interest in the Monarch and other rigs we have in Australia. So although it's still very tough, rates are still very competitive, but on a comparative basis I think Australia is doing okay in comparison to some other global markets.

All right, thank you. I will turn it back.

James West, Evercore ISI.

Good morning, guys. Marc, as you were talking to your customers about their plans, maybe a little bit further out are they starting to become concerned about their production profile as we get out into 2019, 2020, 2021 given the lack of FIDs that have happened over the last two years and could that lead to at least some FIDs, some additional rig contracts over the next 12, 18 months?

Yes, thanks for the question, James. I think we are starting to see a pivot away from a short-term focus that was driven around cash flows, dividends and expense cutbacks. That's not to suggest, however, that that pivot has been substantial at this moment in time.

But as it relates to, for example, questions about an interest around the Floating Factory concept, we are starting to see some of the larger clients focus on what they think that they will need in their portfolio as it relates to 2020 and beyond. So there is somewhat of a change in our clients' dialogue that we are having with them. But it's still quite a period of time before the dialogue turns from talk through to activity.

Okay, fair enough. And then with respect to pricing at this point, we are hearing from a couple of other drillers that are suggesting that the pricing pressure isn't as, well, I guess it's less than now that we are at -- well kind of close to cash flow breakeven for a lot of rigs. But is that a fair statement to make that there's not a lot of pricing pressure, that there's more just a utilization game at this point?

Well I think you can't separate the two really. When you've got, let's say, 285 floating assets out there, 150 of which are on contract and maybe 110, 111 that are actually drilling, I think it's not a stretch of the imagination to figure out that pricing pressure still continues when you've got utilization that is close to 50% and still tracking downwards.

So I think pricing pressure is going to remain out there for a period of time. And we will continue to see fixtures awarded at what is essentially close to cash breakeven. I can't say at this moment in time that we are seeing any relief in pressure from a pricing perspective.

Okay, got it. Thanks, Marc.

Waqar Syed, Goldman Sachs.

Thank you. Good morning.

First of all, just a question on Valor. Are you now getting paid from Petrobras on the contract or not?

Good morning. Yes, we are. We continue to get paid the standby rate, which is still a number with a 4 in front of it and have been since we filed the 8-K back in August.

In actual fact right now, for what it's worth, the contract is more robust than it was previously because there is a court order in place as it relates to the contract stating that Petrobras must continue with the contract for the time being.

Now as I said in my prepared remarks, that is as the result of injunction that we filed immediately after the notice of cancellation. We were successful in obtaining that injunction and Petrobras subsequently moved forward and appealed the injunction and that is still in progress in the Rio courts.

Okay. Now on the Ocean GreatWhite as you adjust down the dayrates to maybe mid-400s or kind of rate, if the rig starts to work on a sublet, would the OpEx change from the level at which this mid-400 kind of rate is being understood to be?

This is Ron. If and when the rig goes back to work she would have to be up-manned slightly to go from her current posture to the drilling posture. So the OpEx would have to go up, but then the dayrate would also obviously have to match.

I think broadly speaking, though, it would be hard to imagine any headline rate above the 585 level of the contract even for harsh environment rigs. So given that I think the margins will stay inside the perimeter of the original contract no matter what she is doing.

Okay, that's good to know. And then, Marc, on this Floating Factory design, have you got an indication of what the rig would cost?

Yes, we do. So we've been to various shipyards and had the detail quotes back as it relates to the construction cost.

Now it's not for me to share those right now, but suffice to say we would be looking at this somewhat differently than what has been the norm in the industry and that we wouldn't do it turnkey. And, of course, as we look at changing the construct around performance drilling we went to Pressure Control by the Hour with GE.

We would also do a similar construct that would include, let's just say, more components of the rig and the drilling package itself whilst that probably doesn't fit under the Pressure Control by the contract -- sorry, Pressure Control by the Hour construct, there would be performance incentives to our partner on the drilling package itself. So it's not really comparing apples to apples. Perhaps one could look at it the CapEx would be less, the OpEx would be slightly higher, but in that respect with the efficiency, safety and other gains that we would see through this new design we would expect to command a higher dayrate than standard sixth-generation assets.

Would you order the rig without a contract in hand from an operator or would you do that only if you have already secured a contract for the rate?

At this time it would be unlikely that we would order it on spec. Suffice to say that there are a number of large IOCs and NOCs that are taking a hard look at this technology and deciding whether they see it as part of their portfolio post the end of the decade.

The rig itself is a 3.5 year build program. So even if we ordered it today or in the next six months it would not be delivered until the end of 2020. But we would not do that without some commitment from an operator at this particular time.

Thank you very much.

Scott Gruber, Citigroup.

Yes, good morning. Marc, can you just continue on with the floating rig concept and maybe discuss how you think about deploying capital into the program relative to M&A opportunities?

Obviously, valuations will rule the decision process. But as you look at the opportunity set, is the technological progression here, is that potential so significant that it just significantly skews the decision tree towards newbuild over M&A?

Yes, thanks for the question. As always we look at capital efficiency as a priority moving forward. I've been somewhat consistent on that in the past, and we have no particular preference for whatever strategy or options that we are looking at, be it M&A, distressed asset purchase or indeed the Floating Factory, a technology leap or a combination thereof.

The important thing, though, is to look at it from a shareholder return perspective in the long run. And as go through what continues to be a protracted downturn and you look at M&A opportunities or you look at distressed asset purchases or even deploying capital for new technology, you have to look at valuations of both distressed assets where they sit today, valuations of M&A opportunities. You've got to look at liquidity profiles of what may end up being opportunities moving forward.

Then you have got to put that into the boiling pot which is the forward-looking market and make the correct decision. I think there still is so much uncertainty in our marketplace as a deepwater driller today that none of those are rising specifically to the top. However, as I've said in my prepared commentary, necessity is the mother of innovation, and I think the industry has been very successful over the years in bringing the cost of operating whether be it shale or unconventionals or indeed deepwater bringing the cost down, and I think it will happen in our space beyond just the reduction in dayrates and pricing.

I think technology gives us the opportunity to meaningfully lower the cost of deepwater extraction. And whether indeed it's fracking or horizontal drilling, we as an industry have shown that we can innovate to make drilling opportunities that were previously uneconomical economical moving forward.

So I think we will see technology changes. I think we will continue to see process changes as we bring in lean manufacturing principles into this construction of a deepwater well.

But as it relates to which particular strategy stands out at this moment, we are still not there as I have said in previous calls. We have options and what lever we will ultimately pull is undecided at this time.

And so as you think about M&A opportunities, if you are looking at a rig that doesn't have a contract today all the value in that asset is out in the medium and longer term and is really impacted by how you think about rates over the medium and long term. So in that context, do you consider the floating rig concept to be market disruptive, meaning that it would have potentially a negative impact on the rate structure over the long term for sixth- and seventh-gen rigs, so do you take it into account as you think about what you pay for a sixth- or seventh-gen rig taking into account the potential rate impact from this concept?

Well, as we look at the optionality that we have on the table vis-a-vis the strategic options, we've done a lot of hard work around rates moving forward and indeed how they would apply to the Floating Factory. Now the Floating Factory brings significant efficiency gains for the construction of a deepwater well, and we've sat down with clients and we've done a lot of what is called DWOPs, drill the well on paper. And so we've got a good idea of what efficiency gains we can deliver.

And it's not just the reduction in the dayrate of the rig. A bigger saving actually comes from a daily reduction in the time to drill a well and its effect on the spread costs on the rig itself.

Then there is various constructs of how you can market the rig guaranteeing performance or efficiency gains. So I think that it can be a competitive or a Floating Factory can be competitive up against some, let's say, distressed sixth-generation assets. But this time I'm not sure I'm prepared on this call to go into the specific details of what might happen.

I think, though, to get to the basis of your question what is happening with the sixth-generation assets vis-a-vis dayrates, clearly that is the most distressed subsector of deepwater drilling. And I think the moored assets, the third- and fourth-generation have somewhat fixed themselves. And I think that moving forward you will see some sixth-generation assets, some of the earlier sixth-generation assets that are unlikely to return to work.

So you will have assets exiting the market. And the reason I say this is because the barriers to reentry will simply just get too high. And nobody will take, well, I say this, but the owners of these rigs will be taking a large risk to reactivate a rig three, four years down the road without a contract to go to.

So I do think that the sixth-generation fleet will somewhat fix itself and market rates will then generally come back up. And we will see a different period certainly in deepwater drilling, in my opinion, post the end of this decade that will change the supply and demand construct around our space that potentially makes this an attractive proposition.

Great. What I was asking about and you kind of touched on it, but if we see the Floating Factory concept pursued by you and if others try to pursue it as well and we get into a market that still has some excess capacity based on my numbers which are very rough because we don't have the ball, but you could actually pay, you could have a customer pay and support the construction of the floating rig factory rig and end up capping sixth- and seventh-gen rates at around $300,000, which ends up really changing how you think about the value of those assets over the longer term. Is that in the ballpark?

Well, again it's crystal ball gazing. I can't necessarily say that the Floating Factory will cap sixth-generation assets at $300,000. Understand that the capacity to build them right now is only two per year.

That could go up should the demand increase. But I don't think it will be material in terms of capping pricing at $300,000. I think what is going to be more influential in terms of dayrates moving forward is what's actually going to happen to the sixth-generation assets that are currently cold-stacked and whether they actually come back to the market are not in the due course of time.

Great, I appreciate the color.

Anita Sedita, UBS.

Hi, it's Angie. Good morning guys.

Hi, Anita.

Hi, George. So if you think about 2018 and if we're at another year we are in low 50s to mid 50s on oil prices, do you think that demand will be generally flattish with 2017 or that in that environment we could actually see some recover of demand that can be pushed out into 2019, 2020?

Angie, I think it's more than likely to be pushed out into 2019 or 2020. From an operator perspective, they still have choices as to how they deploy their capital. And, of course, I think we all understand that right now competing with the unconventional plays is quite difficult from a deepwater perspective.

If you look at the time horizon of cash flows, for example, now we all know that deepwater projects can compete very effectively on a full life cycle NPV basis where as onshore and unconventional. However, it's just the timing of the cash flows is the issue. So I think for the most part in the short run if oil stays in range bound, let's say, $50 to $55 I think you will see our clients' capital still have a propensity to be deployed to unconventional or light tight oil onshore.

But understand that even that is still a limited resource. And certainly clients don't have a big onshore portfolio, and getting into that portfolio is probably going to get more and more expensive should they so desire moving forward. So they do have to consider their deepwater assets, and a number of companies have hinted at that over the last earnings call cycle that deepwater still remains an important part of their diversified portfolio.

So I think it's going to need more than a range bound of $50 to $55. I think you're going to have to get well over $60 before we see an appreciable change in demand. But in the long run, 2019 and 2020, I don't think is too far beyond the stretch of the imagination to see a good recovery in deepwater drilling.

Fair enough. And we agree.

I guess to that and you touched on it a little bit, for the return in the IOCs and the NOCs do you believe that's going to be more dependent upon seeing that mid $60s or thereabouts oil prices versus their protection to clients, that oil prices be a bigger driver than their production or not necessarily?

Well, obviously, that will be considered by the IOCs and the NOCs but at the same time I think it's a choice of what's in their portfolio. As the costs come down for deepwater drilling, and let's not necessarily just gloss over that, the costs have significantly come down, then certain projects will be FIDed and brought back over the horizon at a price that for some could even be lower than $50.

We've seen Mad Dog 2, we've seen some of the Statoil projects, both locally and in Brazil, be sanctioned at a price that's lower than $50. So much of it depends what's in the client's portfolio.

Petrobras doesn't have a choice. They are a deepwater driller.

Total, again, the competitive advantage is deepwater drilling. So many of those companies will still be looking to sanctioned projects perhaps sooner than the others. Nevertheless we've had some commentary, again, from some of the large IOCs over the past few weeks that are suggesting that they are looking at unconventional in the short term.

But I go back to my previous point. Yes, we are going through a particularly rough and protracted downturn, but one can't escape the fact that oil still is the largest growing component of energy supply today. That's not going to change.

If you look at unconventional, it's mainly US bound and a lot of the leases in unconventional are getting very, very expensive. So our clients still need to look at a balanced portfolio and consider various options. According to our own analysis with some help from consultancies we believe that deepwater over the next 10 to 15 years will have to come to the table with incremental production that is at least as large as what we are currently producing today. And you can't get there without drilling deepwater wells.

That's fair. Very helpful.

And then as an unrelated follow-up, on the stacking/scrapping of rigs how long do you think, have you done any work on how long a rig would be stacked before in essence it becomes scrapped or the capital would be prohibitive to bring that rig back? You started doing any work is it three years, four years, five years or any perspective on that when we think about the rig fleet going into 2020?

Yes, well it depends, Angie. We have done a lot of work on it. We've got a pretty mixed fleet here.

We are very happy with the nature of our fleet. We have got some very good quality moored assets. We've got some recently delivered sixth-generation BP assets.

And really it's on a case-by-case basis because some of the rigs naturally are more complex than others. I think one underestimates the task of bringing a rig back that has been stacked for three years when a lot of the systems are more complicated than they have been in the past. You have got the enhanced electronics and much more complicated BOPs, for example, on the sixth-generation assets and, of course, the most corrosive environment, to store steel, is actually on the ocean itself.

Let me just throw this out. There is no wellhead out there that you can take a sixth-generation asset that has been stacked for three years with its BOP system, splash the BOP, put it on the wellhead and test it as it relates to what's happened in the prior three years. The problem you have in terms of bringing these rigs back is you are going to have to do it on the client's time; in other words, on their wellhead.

And some of these systems are really, really complicated. And if they haven't been tested in their operating environment, which you cannot do on the stump of a rig, I think it would be -- I think it would be more complicated than some people are suggesting in this environment. Stacking a rig could be problematic in the long run.

Great, thanks. I will turn it over.

Kurt Hallead, RBC.

Kurt, we can't hear you. You are very faint.

Do you want me to go ahead and move onto the next question?

Yes, please.

J.B. Lowe, Bank of America.

Good morning guys, can you hear me? Excellent.

First question, I guess, Kelly, did you give guidance for full-year OpEx by any chance? Did I miss that?

We did not. I made a comment that due to the fluid nature of the market right now we just weren't going to give -- we gave it for the first quarter, but not for the full year.

Okay. And I know you said something about you expecting OpEx levels to be around the same level as Q4 going forward as a base. Is that to imply that your cost-cutting measures are nearing an end here in terms of rationalizing your cost structure?

J.B., that's a good question. I think the comment that I made was if you look at the cost-reduction efforts that we've done over the last couple of quarters, obviously, we've been very pleased with what's happened. The trends have continued to go lower, and we've looked at a lot of different things.

We've looked at, obviously, taken more headcount out. We've taken ex-pats out, focused more on nationalization of employees, looked at supply chain efforts. We've done a lot of things to bring that cost down, but I think we've got that built into the run rate at this point.

So if you look at our base cost trend in Q4 I think we are not really expecting a lot more improvement from where we are at there. But when you look going forward be sure, as a reminder, be sure and adjust the rigs that are coming on. We've got three new contracts kicking off here in Q1, there will be higher costs associated with that but that's built into the guidance number that I provided this morning.

Okay, fair enough. Unrelated follow-up, I guess, the Scepter contract in Mexico I think makes sense just on a standalone basis, but you guys have made some comments that you want to maintain a presence there for any potential deepwater tendering in Mexico.

Do you have any timeline on that? The contract runs through October 2017. I imagine there is nothing going to be done on that front by then, but just some commentary on the outlook in Mexico.

J.B., this is Ron. You are right overall that I think having a presence in Mexico makes a lot of sense. I think the time frame with which deepwater may pick up speed I don't think will happen within the Ocean Scepter's contracting horizon, but broadly speaking it does make good sense for us to maintain a presence in Mexico.

If you recall the deepwater auctions were pretty well subscribed end of the last year. And so despite the challenges overall in the sector, a number of IOCs certainly think that long term Mexico deepwater is a good place to be. So us having an ongoing presence there makes just good general sense and we will continue looking for ways to stay active in Mexico because I think that will long term be an important part of both mid and deepwater.

Okay, so no idea on timing really yet?

Well, it's hard to say candidly. I think I don't think anyone expects the leases to move too quickly from auction to action, if you will. I think that will take some time to grind forward.

The time frame, of course, for the Ocean Scepter contract is quite near-term. So I think that there would have to be some other steps between the end of the Scepter contract and the start of any kind of deepwater activity.

Okay, thanks.

Ian Macpherson, Simmons.

Thanks, good morning. I have three questions but they are quick. Ron, could you give us a little color on your expectations for Guardian and Victory which are your, I guess, two of your near-term rollovers in the second quarter?

Good morning, Ian. I was wondering why it took so long for someone to ask that question. So let's talk about the Guardian first.

Of course, she's on contract with Dana right now through the early start of April. She's a well maintained asset delivering good, safe, reliable value. We hear from a number of operators that the value they ascribe to hot rigs as they think about rigs they want on their programs going forward, so Guardian had that going for her in terms of her ability to carry that working status into the spring and summer drilling season.

I would describe my outlook as optimistic that the Guardian, I think, will work further into 2017. We are not going to make an announcement here today, but that's an area that we've put considerable effort into and I think you'll see some activity there.

I guess in contrast to run the opposite way here on the Victory, of course, she will wrap up for work with BP here in the second quarter. We are not announcing anything new beyond that scope of work. So that's one that is, I think, a bit more muted in comparison to the Guardian.

Thanks, Ron. So if Victory is stacked, your stack pool will increase from 10 to 11 rigs. In that pool is Onyx which is a modern moored rig, maybe one or two others that are quasi-modern rigs, but most of that pool is very cold and substantially old rigs.

Marc, how are you thinking about addressing that pile of steel this year? Will you become more interested in just blanket scrapping the lot of them?

No, absolutely not. As I alluded to earlier in the conversation here, we are very comfortable with what is currently sitting on our fleet. We look at the fleet on a quarterly basis and compare that to the market.

But do understand that a number of the moored assets that we recently upgraded do have a future. The most distressed sub-asset class, of course, in my opinion is the DP assets. They are simply too many of them chasing too few work.

But if you look at the third and fourth moored fleet and perhaps even some of the fifth-generation assets that can be converted to moored assets we have quite a bit of optimism. The size of the subsector is much smaller. The scrapping that took place which we led, we started the whole process a number of quarters ago, has moved forward.

Indeed of the 50 or so scrapped assets the majority of them are in the third- and fourth-generation moored asset class. So that's fixing itself.

And so the Onyx no, the Onyx will see the light of day again. We are not even having conversations around whether that asset class should be scrapped. Its sister rig the Apex in Australia is doing well.

And we see that there is a future for some of these assets. Now does the market change moving for, does the recovery take longer than expected, and does the reactivation cost change with time? Yes, it does.

But under no circumstances are we looking at taking the assets that currently aren't working and scrapping them at this moment in time. That's simply not the case.

Okay good. I didn't mean Onyx, I was referring to some of the others but I appreciate that.

My last question is really just trying to frame the baseline OpEx level relative to your guidance for Q1, Kelly. And I wonder if you could talk about what's embedded there for Valor? Is that a rig that's running at full cost structure or more of a warm cost?

And similarly Monarch, if you could provide more color on the survey and what price that entails? And then, finally, whether there will be significant cost reductions for the two Black ships that have downtime in the first quarter?

Okay, that's quite a few. We will start with the Valor. The Valor is fully crewed.

We are on a standby rate, but because of the litigation that we are in with Petrobras we have to keep that rig ready to go to work at a given time. So no change in operating cost there.

I think your next was the Monarch. The Monarch I mentioned I think in the prepared remarks that it's being mobbed right now to Singapore for a special survey, so there's going to be some additional cost related to the Monarch, but that is built into our guidance for Q1 that I provided, that $215 million to $220 million, that additional cost is built in there.

And then, of course, June the rig should be back active in June. Then the other, the Black ships that have had downtime, there's not going to be any reduction in cost related to the downtime that we experienced early this year.

Okay. And you can't provide any numbers around the Monarch for Q1?

I don't want to give that level of detail. But I think you know special surveys what they can cost, so there is going to be -- there is going to be a chunk there.

And if you look, I didn't give full-year guidance but Q2 for the total Company going forward should be a little bit higher in cost. Obviously, we will have a full-quarter run rate of the rigs that are going to work in Q1. But you get towards the end of the year some of the rigs that are dropping off like the Victory, for example, the Patriot, you will start to see more of a decline in operating cost towards the end of the year.

Very helpful. I appreciate all the help. Thanks.

Eduardo Royes, Jefferies.

Hey guys, good morning. Marc or Ron, I guess, this one is for you, and it's drawing a bit on Angie's question. But I'd like a little more perspective on how you think about the competitive positioning of the warm stacked sixth-gen fleet?

So not the rigs that have entirely shut down, but rather this ballooning number of warm stacked good rigs that we are seeing where they are being quote unquote warm stacked for $40,000 a day plus or minus and we are told that it could be years but they could still come back for some rather small amount like a $5 million price tag, not this $50 million to $100 million plus. Obviously, a lot of these rigs are only a few years old. A lot of them are finishing up their maiden three-year jobs and probably go unemployed.

And so I'm just wondering if the reinvestment in these rigs can really remain that minimal. And I ask because I feel like this is a huge piece of the puzzle as you think a few years down the road for pricing power and what that means for the market.

Your Black ships will reprice into and ultimately even the Floating Factory considerations or really not the cold-stacked stuff, not the old stuff but really the sixth-gen rig that got cut loose early and it's sitting there in some sort of preservation ready, whatever you want to call it, stacked mode. Can they come back for such little money? Thanks.

Eduardo, this is Ron. Great question.

You put your finger on a really important, I think, piece of the puzzle. And I've got to tell you I think that these promises or expectations being raised regarding smart stacking or somehow being clever on cost and bring these rigs back at some modest amount in the future, I think that's hopeful at best and perhaps misleading at worst.

We saw some great advertising last night on the Super Bowl. I think what you are seeing here is probably some advertising attempts to explain some modified cost structure decisions. Marc talked about it before, as time goes on these very complex pieces of machinery don't age well or gracefully.

And I think no one has proven to bring these back on a well and easily and sort of a low-cost and quickly. I think we are in for a big surprise at the other end of the story when these rigs try to come back at bargain stacked costs. I think there will be a significant amount of work that isn't planned for. So from our standpoint I think we see that narrative, we view that with great skepticism quite candidly.

I appreciate that, Ron. Thank you.

The second question is much shorter than that one, and this one is for Kelly. Do you have an approximate date for when the GreatWhite was actually handed over to you guys in the fourth quarter?

December 1. You are talking about the service day when we started depreciating the asset?

Yes, yes, exactly. Exactly and to give all of the pieces that will help connect the quarters.

Okay, great. Thank you very much.

But do understand that the revenue didn't start coming in until mid-January.

Yes, I got that. Thanks, Marc.

Appreciate it, guys. I will turn it over.

Haithum Nokta, Clarkson Platou Securities.

Good morning, guys. I appreciate the comments, Marc, around potential reactivation costs and all that and how operators only want units that are warm -- or, sorry, hot.

But you mentioned that things like that are coming up in the tender documents, preference for hot rigs. But can you expand a little bit on what that means in the near-term and what maybe those parameters really are and maybe how long a unit can be idle before it's taken out of contention for contract opportunities?

It depends as to how the various clients look at whether they consider a rig to be hot or not. I think anything that is a gap of six months or longer brings doubt to our clients' minds as to the ongoing serviceability of the rig itself without some kind of compromise that may have happened during that period of time.

But back to the previous question that we just spoke to, it's not just the capital cost of getting the rig back into working condition, it's the OpEx and the time that it takes for the rig to be fully crewed, go through a shakedown, address the various punch items that come out of the shakedown with a crew on board. So it is not just the CapEx program that you have to consider when you bring a rig back. It's the OpEx element of that program that the cost materializes before you go onto dayrate.

So perhaps it's quite ludicrous to suggest that it only costs $5 million to bring a sixth-generation asset back after a significant period of stacking.

And would you say that OpEx period that you just mentioned, could that be as long as six to nine months? Or it is that like only three months? Can you maybe frame an idea for that?

Well, by the time that you've got the signal or you've made the decision to bring a rig back and for it to actually start earning revenue is in my opinion substantially longer than three months. You are going to have to get the crew, you are going to have to get the rig crewed, you are going to have to go through the systems to get them up to date and then, of course, you've got sail to the location, you've got to prepare the BOP, you've got to call BSEE out, the regulator, if you are here in North America or whatever regulator exists around the world and then you're going to have to go through the process of an acceptance testing where the client will require all systems on the rig to be tested, whether it's the power management system, whether it's the BOPs themselves.

And to suggest that you're going to be able to do this without finding some kind of issues on the rig is, I think, misleading. So costs will be incurred, and I would be surprised if you bring a sixth-generation asset back from a cold-stacked condition to earning revenue with anything like a six-month period.

Got it. I'd agree with you there.

Thanks. That's all I had today.

Ladies and gentlemen, this does conclude the Q&A portion of today's conference. I'd like to turn the call back over to Marc for closing comments.

So folks, thank you very much for participating in today's call. And we look forward to speaking with you again next quarter.

Ladies and gentlemen, you may all disconnect and have a wonderful day.