Sean Patrick O'Neill - Vice President-Investor Relations & Communications Carl Trowell - President, Chief Executive Officer & Director David Hensel - Senior Vice President-Marketing Jay W. Swent III - Chief Financial Officer & Executive Vice President.

David C. Smith - Heikkinen Energy Advisors Judson E. Bailey - Wells Fargo Securities LLC J.B. Lowe - Cowen & Co. LLC Gregory Lewis - Credit Suisse Securities (USA) LLC (Broker) Praveen Narra - Raymond James & Associates, Inc. Sean C. Meakim - JPMorgan Securities LLC.

Good day, everyone, and welcome to Ensco Plc's Third Quarter 2015 Financial Results Conference Call. All participants will be in listen-only mode. After today's presentation, there will be an opportunity to ask questions. Please note, this event is being recorded. I would now like to turn the call over to Mr.

Sean O'Neill, Vice President of Investor Relations, who will moderate the call. Please go ahead, sir..

Welcome, everyone, to Ensco's third quarter 2015 conference call. With me today are Carl Trowell, CEO; Mark Burns, our Chief Operating Officer; Carey Lowe, EVP; Jay Swent, CFO; David Hensel, our Senior Vice President of Marketing; as well as other members of our executive management team.

We issued our earnings release which is available on our website at enscoplc.com. Any comments we make about expectations are forward-looking statements and are subject to risks and uncertainties. Many factors could cause actual results to differ materially.

Please refer to our earnings release and SEC filings on our website that define forward-looking statements and list risk factors and other events that could impact future results. Also, please note that the company undertakes no duty to update forward-looking statements. Now, let me turn the call over to Carl Trowell, CEO and President..

Thanks, Sean, and good morning, everyone. During the third quarter, our sector has continued to experience challenges from the cyclical downturn. Additional announcements of incremental CapEx cuts by customers will further reduced rig demand in 2016, and coupled with newbuild deliveries, add pressure to utilization and day rates.

Our response has been decisive action in terms of further expense reductions, streamlining our business unit reporting structure, strong operational performance and several contracting wins with customers. As previously announced, during the third quarter, we took additional steps to reduce expenses in line with our fleet restructuring.

We consolidated our business unit reporting structure from five business units to three, centralized onshore support functions and reduced head count accordingly. As a result, onshore support cost savings now total $57 million annually.

We also made further adjustments to supplemental compensation that will now bring offshore unit labor cost savings to 15% compared with 2014 levels. And finally, we have significantly reduced daily operating costs for stacked rigs.

Third quarter contract drilling expense came in even better than our revised outlook, and we expect further improvements in the fourth quarter as Jay will describe in a moment.

These expense management actions coupled with our strong financial position, including no debt maturities until second quarter 2019, $1.1 billion of cash and short-term securities, a fully available $2.25 billion revolver, and $6.6 billion of revenue backlog, puts us in a solid competitive position.

While Moody's recently downgraded several offshore drillers, Ensco's investment grade rating of Baa2 stands above most of the drillers. Operational performance during the third quarter continued to be positive with a record 99.8% operational utilization for jackups, and 95.4% for floaters, with continued strong safety performance.

Our drill ship performance was particularly strong whilst our semis performance was challenged by loop currents that were experienced in the U.S. Gulf of Mexico during the third quarter.

Given our strong operational and safety performance, something that is even more critical during market downcycles, we've been able to secure additional business with customers as highlighted in our most recent fleet status report. David will review full details of these new contracts.

But briefly, let me underscore that ENSCO 8505 earned new work in the U.S. Gulf, and we were awarded multiple jackup contracts in various regions including the U.S. Gulf, Asia and the North Sea, including ENSCO 71 and ENSCO 72 that recently had their contracts finalized. In total, these contracts represent $400 million of additional revenue backlog.

While some of these contracts are for shorter terms, they showed the teamwork between our marketing operations and engineering teams to keep rigs working as much as possible despite challenging market conditions. We are pleased by the market response to our upgrade of the 8500 series that allows them to work in moored and DP modes.

And we currently plan to convert a third rig during 2016. Our long established strategy of being a hybrid driller with both floaters and jackups has been a positive during the downturn. And we believe jackup demand will ultimately lead to recovery due to lower breakeven commodity price levels for shallow water programs.

Turning now to our newbuild rigs. ENSCO DS-8 is completing customer acceptance testing and is on schedule to commence its initial contract with Total in mid-November. As previously reported, ENSCO DS-9, that was delivered earlier this year, is earning its daily rate for two years in accordance with the early termination provision of the contract.

Jackup rigs ENSCO 140 and ENSCO 141 remain on schedule for mid-2016 deliveries and we are actively marketing these rigs in the Middle East, in particular, where they are being built. As mentioned on our last call, we continue to evaluate our options for ENSCO 123 which is currently scheduled for a mid-2016 delivery.

ENSCO DS-10 has already been delayed and is now scheduled for an early 2017 delivery. Jay will expand on our CapEx outlook but in short, our CapEx will peak in 2015 at $1.65 billion and then decline significantly in future years. We currently forecast 2016 CapEx to be $625 million.

In summary, I think we've done a good job of building a solid bridge in terms of bolstering our financial position, deferring CapEx payments, streamlining costs, consolidating business unit reporting and capitalizing on pockets of customer demand, to not only create a safe path to the future recovery, but also to increase our flexibility to capitalize on opportunities along the way.

In the meantime, as we look across our market, other players are also doing their part. Customers are reengineering projects and driving cost efficiencies, including standardization, to lower the breakeven commodity price level for their offshore programs.

Major offshore builders in South Korea have agreed to work together to standardize materials, designs and procedures for offshore facilities to better control costs and limit project delays.

Service companies are joining forces to leverage vertical integration and investments in new innovation to improve overall project management and to drive costs out of the system, and other drillers have joined in scrapping older rigs to help improve supply/demand dynamics.

Deep water remains critically important to super majors and national oil companies, as well as the service companies that support them. And we've seen large acquisitions by both operators and service companies in our space, underscoring their commitment to the offshore market despite the current downturn.

Each group of market participants is taking positive steps in their own way to improve the economics of the deep water sector. And the combined impacts of these actions will be meaningful to our industry.

Before I hand it over to David, I've noted in our most recent fleet status report, our five rigs contracted with Petrobras continue to operate and earn day rate under their existing contracts. Similar to last quarter, you may find a recap regarding this matter on our 10-Q that we filed this morning.

Finally, our succession process for our new CFO is going well. And as Jay retires, I'm confident that we'll have a smooth transition due in large part to the strong bench of financial talent within our organization. Now I will turn the call over to David..

Thanks, Carl. As Carl mentioned, customer demand remains at lower levels driven by the cyclical downturn in the offshore drilling markets. Nevertheless, our marketing and operations teams have capitalized on pockets of customer demand around the world that have resulted in several new contracts for Ensco.

For example, we recently contracted ENSCO 8505 for a multi-year contract in the U.S. Gulf of Mexico. We were able to win this work because of the versatility that the 8500 series offers to customers and the high levels of operational performance that these rigs have delivered to our customers.

Similar to its sister rig, ENSCO 8503, ENSCO 8505, will use a hybrid moored-DP configuration under its new contract. The mooring upgrade is currently underway and is scheduled to be completed before the rig commences its new contract in December.

This moored-DP configuration is a major advantage for customers who need to drill well programs that straddle both shallow and deepwater, offering them added flexibility, as well as our 8500 Series drilling efficiencies and capabilities such as a 2 million-pound derrick and a deck configuration well suited for plug-and-abandon and intervention work.

We continue to have conversations with additional customers for well programs that sync up with the unique advantages of our 8500 Series rigs with upgraded mooring packages. During the third quarter, ENSCO 8500 and 8506 also won short-term contract extensions in the U.S. Gulf of Mexico.

Moving to jackups, we finalized three-year contracts for both ENSCO 71 and ENSCO 72 in Denmark that are expected to keep the rigs working into 2018. The North Sea is a particularly strong market for Ensco where we have nine rigs under contract, and we are having active discussions with customers for our two available rigs in the region.

Additionally, we contracted ENSCO 107 for 100 days in New Zealand and ENSCO 68 in the U.S. Gulf of Mexico for six wells. Both rigs are expected to begin their contracts during the fourth quarter. Our excellent uptime performance and, in many cases, prior experience with customers were integral in securing these new contracts.

Ensco's operational and safety track record and technology continue to differentiate our rigs from the competition. In total, the new contracts I have just outlined are expected to add more than nine rig-years of work and help to bridge us to better market conditions in the future.

We will continue to leverage our experience as an international driller with established operational and safety management systems, differentiated technology, well-trained rig crews, and a strong reputation among customers to continue winning new work and retaining our existing customers. Now, looking at global rig supply.

In terms of newbuild rigs, 46 floaters were scheduled to be delivered by year-end 2017. Half of these rigs are contracted, including 15 rigs that are being built in Brazil, several of which have already experienced delays in their expected delivery dates due to financial, shipyard, and other issues.

In anticipation of a better contracting environment in the future, many of the remaining uncontracted deliveries have already been delayed. Additionally, some drillers have recently shown a willingness to refuse floater deliveries were contractually permitted. We have also seen some planned orders canceled.

These newbuild delays and cancelations are positive developments for reducing global floater supply and additional delays or cancelations would be another positive for rebalancing floater supply and demand more quickly. Moving to the order book for competitive jackups.

There are approximately 105 uncontracted newbuilds showing delivery dates by year-end 2017. Most of these uncontracted deliveries are with speculators that have never operated a rig, and it remains to be seen whether these units will be able to compete effectively.

We have already seen the cancellation of six jackup orders and we may see additional units canceled given current market conditions. Other newbuild rigs have been subject to repeated delivery delays, especially, jackups being built by speculators.

In fact, based on original scheduled delivery dates, 20 of these speculative rigs should have already been delivered but have been delayed by nearly a year on average and up to 18 months in some cases.

We expect these delays to continue, especially for the 24 speculative newbuilds scheduled for delivery before year-end 2015 as companies who ordered these rigs need to put off large milestone CapEx payments given limited contracting and rig sale opportunities.

With regard to speculators, representing 60% of newbuilds under construction and many of whom have committed only small down payments for their rigs, the shipyards will have to determine whether further investment in partially completed rigs is prudent. Turning now to scrapping and cold stacking of floaters and jackups.

While the pace of scrapping and stacking slowed in the third quarter, we expect a pickup in the coming months as offshore drillers continue to rationalize their fleets and evaluate the go-forward competitiveness of older rigs that would require significant CapEx to stay certified to work.

In a market with limited contracting opportunities, it may not make economic sense for drillers to invest in these older, less capable assets. And some drillers have already telegraphed that more scrapping is ahead due in part to their focus on reducing expenses and preserving capital during the downturn.

Since last September, offshore drillers have announced they will scrap 42 floaters. Over the same period, an additional 27 floaters have been cold-stacked, and we believe that the majority of these stacked rigs will also be scrapped. In total, these 69 rigs represent more than 20% of competitive global supply a year ago.

Additionally, 24 floaters older than 30 years of age are currently idle without follow-on work, and incremental 59 floaters greater than 30 years old. We'll see their contracts expire by year-end 2017. All will be likely candidates for scrapping and/or cold stacking.

And as a group, they are nearly double the number of floaters currently scheduled to enter the market before the end of 2017. Similarly, on the jackup side, we expect stacking to accelerate.

Here is the picture for competitive jackups defined as independent leg cantilever rigs, roughly 70 are stacked or idled without follow-on work and older than 30 years of age. Another 90 rigs, that are 30 years of age or older have contracts expiring by the end of 2017.

Major regulatory surveys to re-certify these older rigs, which must take place every five years, involve significant capital investment.

In a tight cash flow environment and faced with uncertain re-contracting prospects, drillers may choose to cold stack or, in many cases, retire these older units rather than spend tens of millions of dollars in upgrades. Additional information on the global supply of rigs is provided in the investor presentation on our website.

In closing, as evidenced by several new contract awards since our last call, we are well positioned to capitalize on pockets of customer demand around the world as we navigate through the downturn. While the market remains challenging in the near term, there are several factors that will help to support rig demand in the medium to long term.

First, it has been encouraging to see a year-to-date pickup in offshore exploration success as compared to last year, including a significant recent discovery in the Mediterranean.

Second, lease sales in frontier plays and established basins have continued to draw interest from several major customers as they look through the short-term noise in the commodity markets to the longer-term potential of offshore reserves.

Third, while participation in recent lease sales have been weaker than expected in Brazil and Mexico, we continue to see both markets becoming more diversified from a customer standpoint. And we expect that this will lead to opportunities on the floater side, in particular, in the future.

Appraisal and development of newly discovered reserves and eventual exploration of recently acquired leases will require drilling rigs. And Ensco's rig fleet, geographical presence and customer relationships put us in a great position to participate in the eventual market upturn. Now, let me turn the call over to Jay..

Thanks, David. Today, I will start with our third quarter financial results, our outlook for the fourth quarter and then I'll wrap up with a discussion of our financial position and some closing comments. As noted in our press release, earnings from continuing operations were $1.34 compared to $1.79 last year.

Total third quarter revenue was $1.01 billion versus $1.20 billion a year ago.

Lower utilization was partially offset by the addition of two newbuild jackups to the active fleet; the reactivation of two upgraded floaters, ENSCO 5004 and 5006; an early termination fee for ENSCO DS-4 plus ENSCO DS-9 earning day rates sooner than scheduled due to the customer's early termination for convenience.

Floater segment revenue was $646 million compared to $704 million a year ago, primarily due to lower utilization of 59% compared to 82% a year ago and a decline in the average day rate to $422,000 from $451,000 last year.

Operational utilization for the floater segment, which adjusts for uncontracted days and planned downtime, was 95.4%, up from 94.2% a year ago. Our drillships had an exceptional quarter with 100% operational utilization. Jackup segment revenue was $326 million compared to $481 million a year ago, as utilization declined to 64% from 92% last year.

The average day rate declined 5% to $134,000. These factors were partially offset by the addition of two high specification jackups, ENSCO 122 and ENSCO 110 to the active fleet.

Operational utilization for the total jackup fleet was 99.8%, an all-time high for our jackups, reflecting the continued focus of our offshore crews on delivering high levels of uptime performance to our customers.

We reduced total contract drilling expense to $434 million, well below our initial estimate and even lower than our revised outlook of $450 million to $455 million that we provided in early September. Year-to-year, we reduced contract drilling expense by 13% from $500 million in the third quarter of 2014.

Proactive expense management more than offset the incremental costs of adding DS-9 and two newbuild jackups to the active fleet, the reactivation of ENSCO 5004 and 5006, $6 million in upfront stacking costs, plus $4 million of severance and related costs associated with the streamlining of our business unit reporting structure and onshore support functions.

Depreciation expense increased $10 million to $145 million, in line with our expectations, due to the operating fleet growth that I just mentioned. Disciplined expense management including centralizing certain support functions, reduced general and administrative expense to $28 million.

As detailed in our press release, other expense increased to $52 million from $38 million a year ago, as interest expense was $17 million higher year-to-year mostly due to our $1.25 billion debt offering during third quarter 2014 and our debt refinancing completed in the first quarter of 2015.

Our effective tax rate was 9.5% compared to an adjusted tax rate of 15% a year ago. Excluding discrete items such as the early contract termination for ENSCO DS-4, the effective tax rate was 12.6% compared to 13.9% a year ago. Our fourth quarter tax rate is expected to be approximately 15%. Now, let's turn to our outlook for the fourth quarter.

Due principally to the $111 million DS-4 termination revenue that was recognized in the third quarter, total revenues are expected to decline on a sequential quarterly basis. Average day rates are projected to decline by approximately 5% from the third quarter levels of $232,000.

We expect reported utilization for the fleet to be in the low 60% range, in line with third quarter utilization. These projections include ENSCO DS-8 that is scheduled to commence its initial contract next month.

As Carl mentioned, we anticipate a further reduction in contract drilling expense during the fourth quarter as we continue to actively manage our cost base. Fourth quarter contract drilling expense is expected to decline $15 million to $20 million from the $434 million in the third quarter.

This includes approximately $5 million of office consolidation restructuring costs for the organizational streamlining we announced in September.

We expect lower contract drilling expense despite the office consolidation charges and the projected increase in rig operating days for ENSCO DS-8 joining the active fleet, and more contracted days for our 8500-Series rigs.

Please note that this updated outlook for the fourth quarter is an improvement from the initial outlook we provided in early September of $435 million to $440 million. Depreciation expense is expected to increase to $149 million as ENSCO DS-8 joins the active fleet. We expect fourth quarter G&A expenses to be in line with third quarter.

In total, other expense is estimated to be $59 million in the fourth quarter, mostly due to lower capitalized interest as DS-8 commences its initial contract. Now, I'll provide an update on our cost reduction plans.

The decisive actions that we've taken will reduce the average offshore unit labor cost by 15% compared to 2014 levels, which translates into meaningful cost savings since offshore compensation is roughly half of total contract drilling expense. The full run rate impact of this reduction will begin in the first quarter of 2016.

We have streamlined our global operations reporting structure from five to three business units and raised our estimated annual run rate savings to $57 million, beginning in the fourth quarter, by right-sizing onshore support functions. In addition, we have continued to expedite the cold stacking of rigs without near-term contracting opportunities.

On the floater side, ENSCO 8501, ENSCO 8502, and ENSCO DS-1 are now fully cold stacked and cash costs for these rigs are now less than $10,000 per day. We have cold stacked five jackups and we are in the process of cold stacking another jackup in the U.S. Gulf. Cash costs for these rigs are expected to be less than $5,000 per day.

We will continue to proactively manage costs in line with market conditions throughout this cycle. So let's wrap up with a review of our financial position. We have $6.6 billion in revenue backlog based on contracts in place. At September 30, we had a net debt to capital ratio of 32%, and $1.1 billion in cash and short-term investments.

Since the end of the third quarter, we received a $146 million termination payment for DS-4, that will further bolster our cash position. We have a fully available $2.25 billion revolving credit facility giving us significant liquidity and capital management flexibility. As a reminder, we have no debt maturities until 2019.

Recently, as part of an overall sector review that resulted in downgrades from many offshore drillers, Moody's downgraded our credit rating by one notch to BAA2. We are rated the equivalent of one notch higher or BBB+ by S&P.

We remain firmly investment grade with both rating agencies, and this action will have no direct impact to borrowing cost for our fixed cost debt obligations. Ensco's commercial paper rating was reaffirmed by Moody's at P2.

The rating action will also have no impact to our revolver, however, a further one notch downgrade would cause a very slight increase in our quarterly commitment fee and the applicable margin rate on any borrowings under our revolving credit facility. Year-to-date through September 30, capital investments in the fleet totaled $1.45 billion.

For the fourth quarter, we anticipate CapEx to be approximately $200 million. Based on a detailed review, we have reduced our total CapEx budget for 2016 to $625 million of which $475 million is for newbuild construction.

In terms of rig enhancement CapEx, given our fleet upgrades over the past few years, including major upgrades to several floaters, our only expected rig enhancement project in 2016 is adding a mooring package to another 8500-Series rig.

CapEx for minor upgrades and improvements in 2016 will decline relative to 2015 levels due to a smaller active fleet. In closing, we have aggressively managed our expenses and CapEx in response to the downturn in the offshore drilling markets, and we will continue to do so.

Our strong liquidity and capital position give us greater flexibility to navigate the downturn. Our actions over the past year, from accessing the capital markets to streamlining our organizational and fleet structure, have all been done with an eye towards improving our competitiveness.

These actions allow us to focus on areas within our control during the downturn, improving operational and safety results while optimizing financial performance which will better position Ensco for both the near term and the long term. So, with that, I'll the turn the call back over to Sean..

Thanks, Jay. And now, operator, please open up the line for questions..

Thank you. And our first question today will come from David Smith of Heikkinen Energy Advisor..

Hi. Thanks for taking my question. I wanted to ask something you alluded to earlier, and just studying prior downcycles, there's plenty of negative outcomes, but also some really positive ones, particularly for the buyers of distressed assets.

Wanted to ask about your outlook for the opportunity to consolidate assets at distressed valuations, and specifically about the challenges to value an uncontracted drillship particularly if you think it might be idle for a while..

Good morning, David. So, first, let me start by saying we're just beginning to see the start of this cycle with distressed assets coming available, but it's important also to recognize that actually a lot of those assets that you might be thinking of as yet are not unencumbered.

There are some complexities around contract positions and arbitration around a lot of them. So, the number of assets at the moment that are – distressed assets that are available is still quite limited, but of course, building.

I think there is clearly an opportunity there to look at distressed assets that you will be able to pick up at a discounted rate.

The question that I think everyone needs to ask is and are certainly asking themselves is – does that investment balance makes sense in the current market conditions where certainly something like a semi or a new drillship could be idle for several years because if you start to add in the cost of financing, the higher cost of stacking over the number of years that it might be idle, even at a discounted price, the economics don't always work out.

So, I think that what's going to happen is there's going to be probably a lot of tire kicking, and a little bit of exploration on the first assets. And some people may sit on the sidelines during those first – the first asset sales. So, I don't think when we see the results of some of these first sales, we should read too much into it.

I don't think it establishes necessarily a market precedent of what everyone is going to do. We are certainly going to look at it, but we are not rushing to do anything. We have the liquidity to act if we see the right opportunities.

But what we don't want to do is do something precipitive that doesn't make a sensible investment criteria and actually blow a lot of the liquidity cushion that we have early in the cycle..

That makes a lot of sense. Thank you.

And sorry if I missed this, but what is your targeted cost level for drillships when they're un-contracted?.

Sorry.

You mean, it that's stacked, warm or cold stacked?.

Yeah. I guess there's different levels of stacking, but for....

Yes..

...something like the DS-4, for example..

In September, what we announced is based on the plans that we've worked up is that we can long-term warm stack a drillship for $40,000 a day or we can bring it back in the 60- to 90-day timeframe..

Great. Thank you.

And would that be a reasonable level to think about for assets that are kept – drillships that are kept idle for much longer periods of time? Or could this cost get even lower?.

I don't think at this stage. It depends. I mean, if you completely cold stacked it out, you could maybe take it lower. But with a drillship, then that's a careful consideration because the timeframe and the cost to bring it back is much higher, and its ability to be marketed is reduced.

So, at this stage, our intention would be to warm stack the drillships which do not have activity, and then we would review that depending on how we saw the long-term market opportunities developing.

So, I think it's a reasonable estimate at this point, but to my point early, you can take it down lower if you completely cold stack the rig, but that comes with consequences..

Thank you very much..

And the next question comes from Judson Bailey of Wells Fargo..

Thank you. Good morning. I wanted to follow up on some of the operating cost commentary. You guys have been very aggressive, very proactive in cutting costs, and you've still got a lot of initiatives that you're working as you've highlighted. You're seeing a nice step-down in operating cost again in the fourth quarter.

Maybe towards Jay, Jay, can we think about cost stepping down again in the first quarter of 2016, because it sounds like you still haven't felt the benefit of all the things that you're working on, so we're just trying to think about maybe how the rest of your cost-cutting initiatives play out into 2016..

I think, Jud, probably at this point, we're not really giving first quarter or first half guidance for 2016, so it would be a little premature to say anything. We're still working on internal budgets and really nailing things down. As you said, there's a lot of moving pieces right now.

But as I said in my comments, I mean we've always managed costs, and we're going to continue to manage costs. So, I think you can make some assumptions about which direction we're moving in. But on the next call, we'll probably be a little more forthcoming on how you ought to think about first and second quarter..

Okay. All right. I appreciate it. And my follow-up is....

Jud, Jud, can I just jump in. There's another bit I'd add to that, which is – as you've seen, we were quite early to this, and we've done a lot of cost-cutting exercises and structure changes as we've gone through the last 12 and maybe even 18 months.

But the big thing to remember is the other lever that we've got to pull is if we see that market conditions are weaker than we currently forecast, and some of the opportunities for which we are warm stacking and holding rigs ready don't develop, then going to warm stack or cold stack on additional rigs is also a big lever for cost.

So, we can also adjust cost levels if we see conditions different than we see them today..

Okay. That's good color. Thank you. And my follow-up, I wanted to just ask you about a specific market but kind of extrapolate it maybe a little more broadly for next year.

In Angola, there's been a lot of talk recently of Total maybe trying to renegotiate a number of their service and rig commitments because of, I don't know, some issues with the government.

Can you comment if that's been impacting you guys and your contracts? And is this – are we going to see another kind of wave of this do you think in 2016, as the budget for the majors continue to come under pressure next year and now for national oil companies as well?.

So, as a rule, we don't talk about specific negotiations or situations or issues with clients. And I really don't want to break that now other than just to say that the DS-8 is still on track for starting work in November with Total in Angola. It's most of its way through its acceptance testing, and we're looking forward to working with them.

And that contract comes with the usual type of terms and protections that we have for our high-value contracts. If I expand it out a little bit wider, so now I'm not talking about Angola specifically, but the general market conditions, given where we are in the market, there is still a further risk of being asked for concessions by various customers.

And as we have done – where we have good contracts and strong contracts in place which is the majority of our high-value, high-backlog contract, we are prepared to work with customers if we can get something in return.

If we can get contract extensions, if we can get other contract awards or things that can help us reduce our cost of risk, then we will work with our long-standing customers to put something in place where we can both gain and try and manage through the current situations.

What, of course, we're loathe to do and that we'll resist as much as we can is something that's completely unilateral.

But the point I was really trying to make is that in the current market environment, this has not gone away and it's something that will carry forward, I think, until we see some form of stabilization on, and maybe slight uptick in oil price and people begin – and our major customers have brought their spending back within their cash flow..

Got it. Appreciate the color. Thank you..

And the next question is from J.B. Lowe of Cowen and Company. Mr. Lowe, your line has been opened. Is it possible your phone is....

Hi.

Can you hear me? Hello? Hello? Can you hear me?.

Yes, we can hear you..

Okay. Thanks. Sorry about that. I just had a quick question on kind of following up to David's question. You guys have been very successful in reducing costs on warm and cold stacked rigs.

Is there a concern that between you guys and the rest of the market in general that the ability to reduce these costs on the idle or stacked side is going to allow some of these rigs to maybe stick around longer than they normally would have in the sense that instead of scrapping them, you can keep them on the books for such a low cost that you might as well keep them around until the market improves? Is there a concern that that would temper the recovery in the market once it does come around?.

I think that there's a big difference in how certainly we and a lot of our competitors, our peer group competitors, are viewing what to do with newer, more capable rigs versus the older rigs.

I think the key issue is that for lower – if I take floaters, particularly – if you take the lower gen floater, 25, 30, 35 years old with very limited market outlook and potential to recontract, then the decision is much more biased towards stack retire or scrap.

And we've seen a number of these scrapped already, and as we've said in the prepared comments, we think that although that's been relatively modest as far as announcements go in Q3, we do think there'll be a step-up as we go through the next couple of quarters.

So the decision as to whether to put in to warm stack like I described for $40,000 a day for a drillship, for example, it's very different between a new asset and an older asset. So I think we will see and continue to see the retirement of the older assets.

And I think it's going to be – certainly given the near-term market outlook now, it's going to be more aggressive than some people may be taking into appreciation..

Okay. Great. Thanks.

Just as a quick follow-up, on the third mooring system that you're installing, is that – does that rig have a – do you have a contract in mind that you're going towards with adding that mooring system, or is it more just the case that you've been so successful with the rigs that you have added and that it increases their competitiveness to such a degree that you're going to go ahead and do it anyway with hopes that that increased competitiveness will make it get a contract more easily?.

So, if I jump back to what I said, we have been pleased by the market uptake of this hybrid DP mooring system. The fact that the rigs can work in multiple water depths, on multiple program types.

So, for example, to be able to swing between drilling a deepwater well, going and doing an intervention, doing a sidetrack then swing and do a P&A, then go back and do an intervention; that type of program we are seeing some reasonable opportunities for because a lot of our customer base don't have the CapEx commitments or the sanctions to be able to go off and do a year or two-year – just development drilling, for example.

What they do have is very mixed programs that involve P&A and intervention and maybe drilling an out-step well or a tie-back well. And these rigs are really well-suited to that. And the 8500s are well-suited to that anyway. But with the mooring upgrade, they're even better.

So, with that in mind, we have preordered and actually bought the equipment for the upgrade with the intention of doing it, partially because we think it's – without a particular single contract in mind but recognizing a market need. Now, we haven't 100% committed to do it.

If we see that the market is not there, we can always pull back and we'll save that CapEx for next year's plan. But at this stage, we feel sufficiently confident in it that we're planning to go ahead..

Okay. Great. Thanks so much.

And our next question comes from Gregory Lewis of Credit Suisse..

Yes. Thank you and good morning..

Good morning, Greg..

Jay, as I look at the balance sheet, I noticed that account receivables kind of picked up a little bit despite revenues moving down sequentially.

Is that a function of customers just being – slowing down in their payments to you guys or is that more just of a timing issue?.

I think it's a little bit of both, Greg, really. I mean, we do have a few customers that have slowed down a little bit in the third quarter. We received some payments early in the fourth quarter in some cases.

So, I wouldn't be surprised to see the day sales receivable outstanding at year-end be a little higher than usual, but I don't think dramatically so..

Okay.

And then in terms of – I know it's still early days on the DS-9, but in terms of the termination payment, is there any thought from the customer about potentially just getting a lump sum payment to move – just moving forward or do you think it really just kind of filters in over the next couple of years?.

What I think I'd say at this point, Greg, we're in discussion with the customer and probably premature to say very much about it. At the moment, we're talking about how we deal with it on a monthly basis. I'm sure at some point in the future, the customer can always change that view, but I think right now, we're probably on a month-to-month basis..

Okay, guys. Hey, thank you very much for the time..

Thank you..

And our next question is from Praveen Narra of Raymond James..

Hi. Good morning, guys.

On the ENSCO 8505, the day rate was obviously low but given the scope of work, I was curious if you could comment on whether that is earning a cash margin, and, I guess on that same note, kind of the willingness to enter into long-term contracts at these kind of rates?.

Good morning, Praveen. So, first of all, let me start just by reiterating that the – it's worth remembering that the 8500-Series rigs were very economical to build and they're very efficient and economical to run. So, their day operating costs are lower than a comparable-type semi anyway. So, we're starting from that benchmark.

But the nature of the work on these long-term contracts where it's going to move between intervention, drilling, work and abandonment, it's going to do some work with the riser, some without the riser and some on mooring. When it's working in some of these configurations, we can reduce the cost base even further.

On top of the cost reductions we have done across the whole company, there are specifics of how we can reduce the operating cost on the operation of these contracts. So, it will be earning cash margin. And based on that, we would be prepared to enter into similar long-term contracts on the 8500-Series rigs if they came up within this pricing range..

Perfect.

And then, you guys mentioned on M&A, and you guys do seem to be one of the ones that would be capable of being an acquirer of distressed assets, but you mentioned still a little bit early, how wide do you think that bid/ask spread is now, is it narrowing and I guess how far away do you think we are?.

To be perfectly honest, Praveen, I don't know because we haven't seen the results of the first offers for sale at the moment, which is partially why I alluded to the fact there might a lot of people who stay to the sidelines and watch to see where it clears at.

And as you can imagine, it's relatively complex because for a lot of these assets, particularly those that were done under a secured financing, there's a lot of different players between bank groups and bondholders, and things who have to come up with an agreed price. So, we haven't landed there any way in the market and we haven't seen any clear.

So, I just don't know exactly where we are on the bid/ask but I think it's probably going to be lower than some of the debt holders feel comfortable with at the moment to get someone to take it at this stage and put it and, basically, stack the rig out like that idle for a while..

That's fair. If I could squeeze one more in.

In terms of that, do you see any kind of non-traditional players or do you think it's the legacy guys that are likely to be the bidders on these distressed sales?.

I think we'll just have to see..

Sure. Perfect. Thank you very much..

The issue for a lot of players is its debt and taking on further debt which will make a lot of the existing drillers very careful, I think..

Perfect. Thank you very much, guys..

Our next question is a follow-up from Gregory Lewis..

Yeah. Thanks. Sorry to hop on. I was hoping actually someone else is going to ask this question. But on the ENSCO 84 in Saudi Arabia, saw that you got the notice of termination. Was that a function of performance, a function of potentially a little bit of hole in their drilling program? If you could just provide any color on that, that will be fabulous..

Yeah. Greg, again, as I've said, we're always really cautious about going into specifics, but I can appreciate there's a lot of interest in this. The – it was not for performance. It was basically a review of immediate drilling needs by Saudi Aramco..

Okay. Thank you very much..

And the next question is from Sean Meakim of JPMorgan..

Hi. Thank you.

Just had a question about – just thinking about the 8500 Series, opportunities outside of Gulf of Mexico, can you give us maybe a little bit of a sense of what the market looks like for P&A work, workover trends, just things that are – what opportunities could exist outside of Gulf of Mexico?.

So, Sean, there are several opportunities out there that we see today to which the 8500-Series are well-suited.

And in the immediate – in the near term, we feel a little bit more comfortable – careful how I say this, but we feel that there are more opportunities for us to put the 8500-Series into some contracts than maybe some other rig fleet or rig assets. And that's partially because of their flexibility and their cost to run.

On second issue, there is a reasonable amount of P&A and intervention work happening as customers take advantage of rig rates and service rates. So, there is – it's the one part in the market where there's a little bit of elasticity to pricing.

And the other thing to understand is that depending on the regime and the accounting regime, there are several customers out there, who actually can release crude amounts because the cost to actually P&A a well at the moment is lower than the amount they've accrued if they take advantage of the current pricing.

So, we're actually seeing some customers actively trying to do it during the current market conditions..

That's very interesting. Yeah. Thank you for that.

And just one more, just to think about the ENSCO 120, 121 and 122, the roll-offs from contract in 2016, can you talk a little bit about kind of how you think about strategy in terms of pursuing opportunities for those rigs?.

Yes. The first thing is just to say that those rigs have been really good performing rigs. Now that we've really bedded in how we operate those rigs, we're very pleased with them. They've had some really good customer feedback. So, I think that we feel that we have a very good chance of re-contracting them.

I think quite clearly, pricing is going to be lower than it has been. And our aim will be to be able to get them extension contracts or new contracts to keep them working, to keep them working in the North Sea area where we think it will bridge through to other activity down the line..

And is there a preference kind of prioritizing the newbuild versus the other, is there anything to that nature as you think about your strategy?.

A little bit, but it's a little bit horses for courses. There are wells to which the 120 Series are very well suited and only they can do.

And there are wells to which some of our standard duty rigs in the North Sea – take, for example, doing intervention work, infill drilling in the Southern North Sea, for example, to which our standard duty, some of our older rigs that are in the North Sea are well suited, and we're in conversations with clients about..

That's great. Yeah. Thanks for all the color. I appreciate it..

Okay..

And this concludes our question-and-answer session. I would like to turn the conference back over to Sean O'Neill for any closing remarks..

Well, thank you, operator, and thank you, everyone, for your interest in Ensco. Have a great day..

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect..