Good day, everyone, and welcome to Ensco Plc's Third Quarter 2017 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 turn the conference over to Mr. Nick Georgas, Director of Investor Relations, who will moderate the call. Please go ahead, sir.

Welcome, everyone, to Ensco's Third Quarter 2017 Conference Call. With me today are Carl Trowell, CEO; Carey Lowe, our Chief Operating Officer; Jon Baksht, CFO; 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. During this call, we will refer to GAAP and non-GAAP financial measures. Please see the earnings release on our website for additional information. As a reminder, we issued our most recent fleet status report on October 19. An updated investor presentation is also available on our website. Now, let me turn the call over to Carl Trowell, CEO and President.

Thanks, Nick, and good morning, everyone. Before Carey takes us through recent contract awards and Jon gives us an overview of our financial results, I will discuss the Atwood acquisition, third quarter highlights, and make some comments on the state of the offshore drilling markets. Starting with our acquisition of Atwood, we are very pleased that our shareholders approved the deal earlier this month and we successfully completed the transaction on October 6. As a result of the acquisition, we have significantly enhanced our fleet capabilities with the addition of 11 high-quality rigs at the bottom of the cycle prices. By acquiring four best-in-class drillships and two versatile semisubmersibles, we solidify our position in the highest-specification ultra-deepwater segment of the market. This acquisition was an important step forward for the company as it strengthens our fleet and enables us to better meet our customers' drilling requirements. Customers have recently demonstrated a preference for high-specification assets that provide efficiencies which help to lower their offshore project costs, and we expect that this trend will continue in the future. Furthermore, by acquiring Atwood at a pivotal time in the market cycle, we have purchased high-quality assets at compelling prices as values for the highest-specification assets are at a critical inflection point. When combined with significant expected synergies from the transaction, we believe this acquisition will generate meaningful long-term value for our shareholders. Importantly, the acquisition also preserves Ensco's financial flexibility. And with pro forma liquidity of $2.9 billion, we have the ability to continue opportunistically investing to drive long-term shareholder value. Our liquidity position was bolstered by the recent extension of our revolving credit facility for two years through September 2022. This extension was obtained on a non-secured basis, which gives us an even greater financial flexibility over the next five years.…

Thanks, Carl. During the third quarter, our offshore crews and onshore personnel continue delivering the highest levels of service quality and operational excellence to our customers. Their dedication to operating rigs safely and efficiently is evident in the continued improvements in our safety metrics and uptime. These outstanding results are the product of multi-year investments in technology and innovation and enhanced safety systems and processes on our rigs. Having an established safety culture and consistently delivering safe operations improves our ability to win new contracts in a competitive environment. As we integrate our newly acquired rigs with Ensco's operating systems and processes, we remain focused on our core values, particularly safety and operational excellence. In terms of contracting, Ensco continues to rank first among all offshore drillers in new contracts awarded year-to-date, capturing more than 20% of total rig years awarded industry-wide, representing almost double the number of rig years awarded to the nearest competitor. We won four drillship contracts during the third quarter alone, the most recent of which will see ENSCO DS-7 drill two wells and complete four production wells at the Leviathan field in the Mediterranean Sea. This contract is expected to commence in March 2018, with the initial well program expected to run until the end of next year, followed by customer options that, if fully exercised, would extend the contract into 2020. As mentioned on our second quarter earnings call, we secured longer-term contracts to offshore West Africa for ENSCO DS-4 and DS-10, and ENSCO DS-4 recently commenced its two-year contract to offshore Nigeria. This was an important operational milestone as DS-4 is the first preservation stacked floater we have returned to the active fleet, and the rig has delivered outstanding performance to our customer. Last month, we accepted delivery of ENSCO DS-10 from the…

Thanks, Carey. Today, I'll cover third quarter 2017 financial results, our outlook for the fourth quarter, a summary of our financial position, and an update on the Atwood integration and our synergy targets. Starting with the third quarter results versus prior year, we reported a loss of $0.08 per share compared to earnings per share of $0.28 in the year-ago period. As detailed in our press release, several items influenced these comparisons, including $6 million of transaction costs related to the Atwood acquisition that are included in third quarter 2017 G&A, $3 million of discrete tax expense in the third quarter 2017 tax provision, an $18 million gain included in third quarter 2016, other income related to the repurchase of senior notes at a discount, $6 million of other discrete tax items that reduced the third quarter 2016 tax provision, and $4 million of severance and other restructuring costs in third quarter 2016 contract drilling expense. Excluding these items, an adjusted loss of $0.05 per share compared to adjusted earnings of $0.21 per share a year ago. Total third quarter revenue was $460 million versus $548 million last year. In the floaters segment, revenue was $292 million compared to $319 million in third quarter 2016, due primarily to a decline in reported utilization to 46% from 48% a year ago, and a decrease in the average day rate to $334,000 from $353,000 last year. Operational utilization for the floaters segment, which adjusts for uncontracted days and planned downtime, was exceptionally strong at 99.6%, up from 98.9% a year ago. In the jackup segment, revenue was $153 million compared to $214 million a year ago due to fewer rig operating days and a decline in average day rate to $88,000 from $109,000 in third quarter 2016. While the total number of…

We will now begin the question-and-answer session.

I think we lost connectivity there through, so I think what we're going to do is – Jon was just finally wrapping up, so I think what we'll do is just loop back on the final end of Jon's prepared comments and then we'll go to Q&A. Jon?

Just to pick up, our banking group also recognize the strength of our rig fleet following the acquisition. And because of this, we were able to extend our revolving credit facility to 2022 and increase our financial flexibility over the next five years. We continue to have one of the strongest liquidity positions in the offshore drilling sector with no debt maturities until second quarter 2019 and less than $1 billion of debt maturing through 2023, providing a competitive advantage during the market recovery. Moving forward, we will remain highly selective as we evaluate opportunities to improve Ensco's competitive position with a focus on achieving the highest returns for our shareholders. Now, we'll turn the call back over to Nick.

Thanks, Jon. Phil, at this time, please open the line for questions.

We will now begin the question-and-answer session. Our first question comes from Greg Lewis from Credit Suisse. Please go ahead. Gregory Lewis - Credit Suisse Securities (USA) LLC: Yes. Thank you and good morning, gentlemen.

Morning, Greg.

Morning. Gregory Lewis - Credit Suisse Securities (USA) LLC: Carl, I guess, first would be a congratulations on completing the acquisition of Atwood. I think that positions the fleet pretty nicely. But just, when you started off, you mentioned you're liquidity road map and you talked about potentially additional opportunistic investing. As there's been some M&A in the space now not only by you, but by some other players, just as you think about the road map forward in the M&A space, should we expect and is there a potential for the acceleration or more M&A, or is it a kind of as we think about Ensco, should we be thinking more about, hey, there might be a good asset here and there that really complements our fleet and that we'd interested in, or could we be thinking about other potential M&A?

Well, Greg, firstly, it's probably a bit premature to start talking about further M&A whilst we're still driving through the synergies and integration from the Atwood acquisition, and we're extremely focused on making sure that we deliver the value that we believe we're going the get from the acquisition. I think it's worth saying that by the Atwood acquisition, we have significantly upgraded and uplifted our fleet, and that was a major strategic goal for us as we went through this cycle, and we believe we've done that at bottom of cycle pricing. So, if we do nothing else then we will have made a material step forward. Now, on the broad commentary, and think we've said this repeatedly, we still believe that consolidation within the offshore drilling sector is required and will be good for the sector as a whole. I think we have the liquidity to be able to look at things opportunistically, and I think that's why maintaining strong liquidity, managing our balance sheet will still be a focus going forward to make sure that we at least have that option. But I think post Atwood, we would be looking at M&A through a slightly different lens and looking at it in a much more individualistic, case-by-case basis. Gregory Lewis - Credit Suisse Securities (USA) LLC: Okay, great. And then just, Jon, just a couple of questions on the balance sheet. I mean, clearly, as we look at – congratulations, you got the revolver in place. As we look ahead, you have a couple of maturities in 2019 and 2020. That being said, the bond markets look to be open. So, as we think about positioning, is there – could there be appetite for Ensco to really push out it's maturity schedule and really create an even bigger runway than you already have, or is it just, hey, these are manageable maturities and we're just going start packing those down?

Yeah, Greg. Thanks for the question and, just to start, we agree, we're very happy with the bank supports on the revolver extension. I think it does provide us with a tremendous amount of financial flexibility through 2022. As I mentioned in my prepared remarks, we do have now one of the longest kind of runway, if you will, in the space, and specifically on the facility. And so, we do have flexibility. I think we continue to monitor the markets. As you've pointed out, there are some constructive elements in the credit markets currently. But we are – we have the flexibility and the optionality at this point that we're not bound to do anything, because we do you feel that with the liquidity position we have today, we're in a strong position. So, we'll continue to watch the markets and go from there.

Yeah. I would add a little bit, Greg. I think the balance sheet that we now have post-Atwood, I think you should view that that isn't frozen in time and that we will continue to look at ways to manage our balance sheet and our liquidity. We still have a number of levers that we could pull and you've alluded to one of them which is doing further liability management on 2019, 2020 to 2021. So, without ever guiding to that what we're going to do I think you'll have seen from how we've managed the balance sheet over the last two, three years, that we have been alive to opportunities when they've developed and we've been agile and moved and we've put balance sheet flexibility and runway quite high on our priority list and I think you should assume that we will continue that approach. Gregory Lewis - Credit Suisse Securities (USA) LLC: Okay, perfect. Thank you for the time.

The next question comes from Haithum Nokta with Clarksons Platou Securities.

Hi. Good morning. I wanted to ask, Carl, at the Analyst Dinner in September, you talked quite a bit about your positioning for the contract of the future, which will include elements of performance risk, and can you just – since there's a bigger form here, can you just talk a little bit more about that. And kind of in line with that, do you see yourself making any kind of external investments to kind of meet that challenge?

Morning, Haithum. So, I'll maybe reiterate a couple of comments I made on previous investor events. So, I think to understand this is to go back and have a look at how we think the broader market is going to evolve. In our view, this downturn is going to be significant enough that it's going to reconfigure the offshore sector, and we're already seeing that happening. We're going to see companies that existed three years ago not existing. We're going to see acquisitions between companies, combinations, and we're seeing new companies that didn't exist emerge and new ownership structures emerge. And in that sectoring, what we think is going to happen is that there is going to be effectively a Tier 1 and a Tier 2 drilling contractor emerge from that. We clearly see ourselves as a Tier 1 contractor. And by that what we mean is that we intend to be working in close partnership with our major customer base, where we're offering more than just simply rentaling (41:40) steel and a crew for whatever the providing day rate is, but we are working with them to improve the efficiency of offshore drilling and the cost of wells offshore. And that means two key things. It means that we are going to be looking to invest in R&D as I said in my prepared statement to helping improve the drilling process. And we are going to be looking, on the back of that, based off the investments we're making in technology and process and systems, to see if there are alternative contracting models that we can offer that may include incentives for performance and may include also the integration of other services on our rig, either stand-alone or in partnership with some of the service providers. And so, we're pursuing all of those, and I think in my prepared comments, I drew some reference to this, and the fact that now post the Atwood transition, where we've I think taken a big step forward in uplifting the fleet, we're going to put on our kind of – on the hierarchy of where we will deploy capital, we're going to put a little bit more emphasis onto these areas of research, engineering, and innovation as we move forward. So, I don't know whether I answered your question directly or whether you have something specific you want to dive into.

On, no, that's fair enough. And then, I did want to ask maybe about the silent attrition that you talked about in the jackup market. Do you think if that is just kind of affecting older rigs or it's just rigs that haven't worked in a particularly long time, or is there a region specific kind of thing? It just seems like there's a lot of supply that – on the numbers, but doesn't necessarily show up to every tender. So, it would be interesting to get your perspective there.

Yeah. I think, as we've said before, there's a very different profile between the floater market and the jackup market, and there's a lot less incentive to necessarily report attrition on the jackup segment. But, first of all, there are just a lot of older rigs there that are not competitive anymore. And once they've gone idle, have been stacked out, I think that they are going to quietly be removed from the global marketed fleet. There's been another tranche of rigs which are – those which are not necessarily 35 years old or plus, but are just less capable, but in the hands of drilling contractors who just don't have the liquidity or the cash to be able to return them back to the competitive fleet. And I think those will also struggle to come back in the next couple of years. Once they've been stacked out for three, four years without any great investment being put in preservation stacking them or maintaining them, then they become even more increasingly difficult to bring back. So, I think there's two – so to reiterate, there's two key things that's driving that silent attrition in the jackup market. First is just the age of some of their rigs that are now being put dockside and the second is the lack of cash and the increased focus on cash across all of the operators. So I think that's was going to drive it. The other bit, from a bigger picture point of view, is that I think if you go back to a year or two ago, there was this tidal wave of new deliveries coming from the jackup market, particularly when you look at all of the rigs that have been build or potentially been built in Asia. I think the reality of that, as we've shown, is that not all those rigs that are normally been built-in Asia will necessarily reach the market. Some of them – a number will, but it's going to be more like a wholesale replacement of a lot of the older jackup fleet over many years, probably a three- to five-year cycle rather than all arriving and won't be waived (45:50). So I think that's probably the way to view it.

Appreciate the thoughts. I'll turn it back.

The next question comes from a J.B. Lowe with Bank of America Merrill Lynch. Please go ahead.

Hi. Good morning. Good afternoon, guys.

Good morning.

Good morning.

I'm just wondering, Jon, if you could give me some clarification on the guidance. I'm sorry if I missed this, but you were guiding to a 3% revenue decline in Q4. Is that exclusive of the $38 million that you are assuming from the Atwood rig? So, it would be more – so we're still going to see an increase quarter-on-quarter?

No. The guidance actually – so let me just be clear a little bit. So, I mentioned a couple of numbers as it relates to Atwood. So, as part of guidance, there's $22 million that is included in that guidance of 3% off of the $460 million. There's a delta between the $22 million and the $38 million and the $16 million there is just intangible asset amortization, which is just part of purchase accounting. And so, the cash we'll receive from that contract – or, I'm sorry, the cash we should receive from the Atwood rigs is $38 million. What we'll be able to recognize as revenue on the income statement is going to be $22 million, and the $22 million is included within the fourth quarter guidance.

Okay, great.

Is that clear?

And then – yeah, yeah, that's clear. And then $335 million OpEx and $30 million SG&A. I think that's what you said.

Correct. And that's all in pro forma, inclusive of Atwood.

Correct.

Yeah. And just to be clear, J.B., the fall-off in that revenue is driven primarily by two contract changes. The first is the DS-7 is coming off contract, completes its contract during the fourth quarter and will go into preparation for its next contract, but won't be revenue earning. And then the other is the ENSCO 109 is going to move on to a standby rate before it moves on to an extended contract next year. And those two contracts are what's driving that initial fall off and that offset them by the extra revenue that we will recognize from Atwood.

Okay, that's very clear. Thank you. And then I guess, just, Carl, you kind of alluded to it answering the last question, but in terms of the un-contracted jackup newbuilds that are kind of sitting in yards, kind of, being delivered not all in one wave. We have seen a couple, I guess, for example, Borr just bought a bunch that they're going to accelerate the deliveries of those. Has that changed your view in terms of that supply coming to the market at all, or is it kind of part and parcel on what you guys are looking at?

No. That's part and parcel. To give you some insight to that, we've been, on a couple of times now, have sent our engineering and asset management teams around all of the yards in China and Asia who actually laid hands on all of the rigs. And we have our own view there of the subset – there is a subset of those rigs that we think will eventually come to market. And the ones that Borr have acquired fall into that that group. So, we always anticipated that at some point, those rigs would come up. So it doesn't change our view. And then just the other comment is that – it will take time for Borr to put those rigs to work, so they will also be a drip feeding in of those rigs into the market consistent with I think the view that I laid out earlier.

Okay. Thanks so much.

The next question comes from Samantha Hoh with Evercore ISI. Please go ahead.

Hey, guys. I wanted to echo the congrats on executing on the Atwood deal. But my question really has to do with just discussions around the floater contracting. We noticed a lot of the some trends, Carl, that there's a good stream of open tenders and also the duration for some of these contracts have kind improved a little bit. And I was wondering if you could help us understand, how the discussion around the day rates go, for contracts that are one to two wells versus longer duration. And then, how do you incorporate the pricing on day rates for options with the view that the market could be tightening, like, 18 months out.?

Okay. Hi, Samantha. Well, the first is to reiterate that we have seen an increase to quarter-on-quarter on the number of both contract awards but also the number of tenders and the number of inquiries we've got coming in. It hasn't change from our previous commentary, which is that we yet – as yet, we haven't seen enough new tenders or new awards derive from those tenders to offset the number of rigs that are coming off contract through Q4 or maybe beginning of the Q1. So, we haven't yet seen a turn in utilization on floater fleets, global floater fleets, which I think we have seen now on the jackup fleet globally. But we do anticipate, if the trend – if the oil prices stays up in the range that it has been and that we see the number of inbound inquires continue, then I think we will be looking for that to happen mid, late of next year. Now, in that context, we are still seeing very fierce competitive environment particularly in the floaters. And as I've said in my prepared statement, that the oversupply of floaters still is making a competitive environment and pricing is currently unsustainable. I think without giving away our full marketing approach, we are still – we have two drillships primarily that we're looking to market that are client-facing that would be DS-11, the ex Atwood rig, and DS-9. I think we would be very competitive about putting those rigs to work in a contract that might be for the next 12 to 24 months, but we'll be much more careful about longer-term on that and how you deal with the price – any kind of pricing options or escalations afterwards. And on most of the contracts that we have won recently, the ones that we announced earlier this year, the drillships, we have – anything that goes out – past the kind of 18-, 24-month period, we do have either inbuilt escalations or we have options which are at elevated pricing. And I think we'd still likely pursue that approach. The other thing that we have been doing is running a portfolio approach by which we are prepared to put some rigs away at lower day rates, but not all. And we will hold back some capacity for a higher price environment and not have everything locked away at low pricing. And that's also why we've been very clear in stating that post the acquisition, we have no intention of bringing out any of our floaters, which are currently in preservation stack until we see a material invest in market.

Okay, that's great. I'm also curious in terms of just the offshore FID projects. Like the list of projects I'm tracking for – potentially, for 2018 approval just seems to keep growing. And I'm just wondering if you guys have seen any change in terms of the cycle times for these projects being shortened? I know one of the equipment providers had mentioned today that, kind of, gone from like, what, three years to within two years now, and I'm just kind of wondering if you guys are having the same sort of conversations with your customers who might be looking to advance projects that they've been working on?

I'm not sure there's a consistent trend. I do think that the overall cycle time has been brought down across the whole of the offshore sector, but it is quite project-specific, and it depends on the intricacies and the type of project and how many wells are going to be drilled. And particularly what tends to drive the cycle time is the scale of the infrastructure rather than the drilling. So they may require a large platforms, pipelines, infrastructure to tie the production into is what – in most offshore projects is what is the long lead time items. What we have seen is an increase in the number of projects being either planned or getting ready for FID that are a lot shorter cycle time and don't require full-cycle investment, as in that they are subsea tiebacks to existing infrastructure or wells around existing known fields, things like that. And we're also seeing some – a little bit of elasticity in the sense that we're seeing customers who want to move to take advantage of current pricing but rigs and for offshore oilfield services to drill, exploration, appraisal and build in for well outside of the bigger FID projects that you're probably tracking.

What I'll also add is that that's true for the deepwater. But in the shallow water, we're seeing a lot of – a lot of the projects we're seeing are people returning to existing fields and existing platforms to add additional producing wells or workover wells that are already there. And those don't go through and don't shell on the normal FID, so the planning cycle or database.

Great. Thank you so much, and congrats again.

Thank you.

The next question comes from Praveen Narra with Raymond James. Please go ahead. Praveen Narra - Raymond James & Associates, Inc.: Hey, good morning, guys. Carl, you mentioned that we're done with in sort of market recovery a little bit more taking rigs out of cod stack. I was just curious, are we at the point in the cycle where it's unlikely that floaters that roll off contract will be put into preservation stacking mode or we still continue to see that occurring?

I think that very much depends on the age and capability of the rigs. As we've said in the prepared comments in the carried section, there are actually quite a significant number of aged floaters that are beginning to come off contract within the next few quarters. We identify at least 55 that are retirement candidates. They are over 30 years of age. They're either currently idle or about to come off contracts through 2018. And I think for those, that segment of the market, there is – a significant number of them are probably going to move to stack or direct scrap just due to the fact that the cost that would be required to put them back on additional contracts or the fact that they're just utterly uncompetitive in the marketplace. The newer rigs, the higher capacity rigs, I think people are going to begin – going to try and keep them warm or semi-warm stacked. And as you've seen probably from some of our highlights, but also what you've seen from other companies in the sector, is that we've moved from an environment a year or two ago where we were seeing the early termination of contracts to now where we're beginning to see well by well extensions of existing contracts become more common, so we may see more of that as well. Praveen Narra - Raymond James & Associates, Inc.: Okay, perfect. And then, I guess, just back to the performance-based contracting a bit, in terms of the types of customers that are accepting or pushing the performance-based, non-traditional contracts, is there a type of customer that's doing that? Or is it kind of across the board you're seeing everybody interested in taking on a different contract?

I'll let Carey answer first and maybe I'll add a little extra.

Yes, this is Carey. I don't think you can attribute it to any one type of customer we have, performance-based contracts with small independents and also with some of the larger IOCs. And these range from beat the curve, BPAC (00:59:00) type of performance to also providing some additional services and, in some cases, performing some services that traditionally would have been done by the oil company or decommissioning crew on a platform and so on, so performance-based contracts are not unique to any particular client.

I think what I'd add is that it's primarily the IOCs and the independent E&Ps, not so much the NOCs. Although, we do know of a few of the offshore NOCs that are looking at or considering doing things like some turnkey or modified turnkey contracts in the future. And so we will look at that and track that very carefully and, of course, that's something that we would probably want to participate on if the risk balance makes sense. Praveen Narra - Raymond James & Associates, Inc.: I guess, I can and you can turn away certainly if necessary, but today, can you say how many of your contracts are what you would consider to be a bit non-traditional?

Yeah, 1 to 10. 5 to 10, at any one time. Praveen Narra - Raymond James & Associates, Inc.: Perfect. Thanks very much.

And I think maybe what's important to add, what's probably important to add on the back of that is that, as we go forward, we're in no way saying that every single contract we do would be performance-based or would be integration of the services. I think it will be very much a case of offering different types of model to different clients. And just an important subset will be performance or integrated contract. But what we do see now is an increasing hope from some of the customers, particularly some of the IOCs who are looking at two things. They are looking at working with a smaller set of service providers to help them be closer integrated with what they're trying to do to drive down their offshore cost. And, secondly, looking to see if the drilling contractor will take on the management of additional services that can help the overall performance of the well.

And I just might add that in cases where we feel like additional services or performance contracts would be interesting, and it's not then proposed or suggested by the client, we might also suggest it to the client and offer it ourselves. Praveen Narra - Raymond James & Associates, Inc.: Right, okay. Perfect. Thank you very much, guys. Great color.

Okay. The next question comes from Colin Davies with Bernstein. Please go ahead. Colin Davies - Sanford C. Bernstein & Co. LLC: Congratulations once again on the transaction. It's great to get that done. So, just in terms of next steps, you'd alluded to a portfolio review. And I think, previously, you talked about taking a hard look at some of the jackup portfolio with the combined assets. Can you, perhaps, give us a little bit more color on the status of that and where you go from here? I mean, particularly interested in the sort of elaboration of the marketing strategy. You'd mentioned focusing on the DS-9, the DS-11. But perhaps, what are you thinking in terms of the 8500s in the Gulf of Mexico, for example, and then across in to the jackup portfolio?

Okay. Well, I think the first one is that review is on going now as we speak and it's been informed by the fact that we're now actually physically on all of the Atwood rigs. So we now have a much more first-hand information and we're going through our own verification of the estimates that we had for the conditions of the rigs and those rigs that are currently not working, what is required to put them back to work? I will just add maybe a little bit of color, which wasn't in your question, but I did see some market commentary around this, which is probably something I'd proactively take, which is there was some commentary that we had actually stack, cold-stacked out some of the Atwood jackups because that was how it was noted in our current fleet status report. Just to be clear, we have not cold stacked them. All we've done is, in our fleet status report, is put something that we think more accurately reflects what state those rigs are currently in rather than us taking them from being warm stack to moving them to cold. What we're currently doing at the moment is doing our full assessment of exactly the readiness of each of those rigs to go back and you may see, as we go forward on our next fleet status report, that some of those positions changed depending on what we ascertain from that assessment on our portfolio review. So what we are doing is we look – sorry, sorry. Colin Davies - Sanford C. Bernstein & Co. LLC: No, go ahead. Go ahead, sorry.

Okay. So what we are doing in the review of the fleet is we are looking first and foremost at which of the – in the combined jackup fleet, in what sequence do we want to start bringing back rigs and in what geographies versus our current marketed fleet. Because I think in the jackup market we feel, unless there's another material downturn in oil prices and sentiment, I think we do feel we are in a recovery market there. And I think for us now a lot more of our decision process is around the right sequence and right – to bring back rigs at what pace and what investment are we prepared to make to do that based around cash outlay and the returns we expect. So I think that's where we are with the jackups and a lot of the assessment that go with that. What we would also look at is maybe looking at now rationalizing that fleet a little bit one way or the other by selling some assets or scrapping some of our aged assets there depending on the outcome of the review, and I don't want to preempt that. On the floater side, I think we've already made one key decision post Atwood, which is that we will not be bringing back the preservation stack floaters, and that includes the ones that we – the three that we have – the four that we have stacked in the Gulf of Mexico. And so we will keep those for the moment stacked, which means that the three 8500s that we have now marketed will remain the only ones that we keep out in the market. And then on the drillships, as we said, our two main market facing drillships now will be DS-9 and DS-11. Colin Davies - Sanford C. Bernstein & Co. LLC: That's extremely helpful. Thank you very much. And just one follow-up on the sort of interesting dialogue we've had on performance-based contracts. Just wanted to try and get a sense of really where this dialogue is being led from. I mean, to what extent are you guys, as owners of the key rig asset, if you like, pushing that dialogue? To what extent is it being pulled by the IOCs or rather – or the other oil companies? And to what extent are the leading service companies trying to propagate some of that thought?

I think there's a little bit from all three of those directions. I think, certainly, for a company like ours, with our performance levels and our confidence in our own management systems, I think that when we – we are looking to do this. In the current market environment, of course, I think what we're prepared – what we're really trying to do is find ways to get extra and additional revenue return from a contract. So we are, in some cases, proposing alternatives as a way to kind of offset some of the pricing. And a lot of that is, if you don't want that to just be sort of wishful thinking or risk-taking, you need to have done a couple of things. You need to have a certain degree – you need to have certain amount of control over certain elements of the contract and you need to have confidence in your own ability to deliver that. But it's also why we're not continuing to make investment and a lot of the technology and innovation and process and systems because what that builds is builds the platform from which you come into these contracts and may be taking another step further in taking some risk, but you're doing it from an engineered calculated point. Colin Davies - Sanford C. Bernstein & Co. LLC: And would that include – I think you said earlier, just full turnkey or is that the step too far for Ensco?

I think full turnkey can only really be in shallow water jackup markets in certain environments and certain well phase. And there's a huge difference between a turnkey, a modified turnkey or something – or a section turnkey. And I think it's actually a very small subset of the offshore drilling could be or should be done under a turnkey model. A lot of people have lost a lot of money doing that. Colin Davies - Sanford C. Bernstein & Co. LLC: Yeah, that's why I asked the question.

I think there may be the old one now and again, but I think what we should be viewing is that there might be a move towards different types of contracting model, but not moving to that type of level. It will be taking some form of performance-based incentive or reward and it will be looking at integrating additional services into the contract that the rig contract that runs or in alliance with a service company. Colin Davies - Sanford C. Bernstein & Co. LLC: That's great. That actually makes a lot of sense. Thanks very much.

Thank you.

This concludes our question-and-answer session. I would like to turn the conference back over to Nick Georgas for any closing remarks.

Thank you, everyone, for your participation on today's call. We look forward to speaking with you again when we report our fourth quarter 2017 results. Have a great day.

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