Good day, everyone, and welcome to Ensco Plc's fourth quarter 2017 financial results conference call. All participants will be in listen-only mode. Please note this event is being recorded. I will now turn the call over to Mr. Nick Georgas, Director of Investor Relations, who will moderate the call. Please go ahead, sir.

Welcome, everyone, to Ensco's fourth 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 and supplement to our fourth quarter and full-year 2017 earnings release on our website for additional information. As a reminder, we issued our most recent Fleet Status Report on February 20. 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 our recent contract awards and Jon gives an overview of our financial results and outlook, I will discuss 2017 highlights and provide some context on the current state of the offshore drilling market. Beginning with highlights from last year, we completed our acquisition of Atwood in October, adding 11 high-specification assets to our fleet at bottom-of-cycle prices. By purchasing Atwood, we took a critical step forward in enhancing the capabilities of our fleet and positioning Ensco to meet future customer demand. Over the past few years, customers have demonstrated a preference for the highest specification assets, particularly when contracting ultra-deepwater floaters. And we expect this trend to continue in the years ahead. With the addition of the Atwood fleet, we are better equipped to meet more stringent technical requirements from customers and, in doing so, solidify our position as a key offshore service provider. Integration efforts continue to progress as planned. And we have completed 80% of our integration work plan. We remain on track to meet our synergy targets of $60 million in 2018 and $80 million annually beginning in 2019. As part of our fleet review following the Atwood transaction, we've decided to retire floater ENSCO 5005 and recognize a noncash impairment charge primarily related to noncore floaters based upon our assessment of the remaining useful lives of these rigs. We will continue evaluating our fleet structure and acting opportunistically to streamline our fleet. During 2017 we improved our operational and safety performance, further differentiating Ensco's service offering from the competition. Operational uptime for the year was 99% for our contracted rigs, the second consecutive year we have performed at this level. With respect to safety, we achieved new company records for total recordable and lost-time incident…

Thanks, Carl. I'd like to start by detailing a couple of points that Carl touched on. 2017 marked another year of significant achievements for Ensco, most notably in operational and safety performance. Our offshore crews and onshore personnel delivered near-perfect operational utilization of 99% across the fleet for a second consecutive year. In addition to high levels of operational performance, our crews continued to be laser-focused on safety, improving our total recordable incident rate by 42%, establishing a new company record and beating the industry average by nearly 60%. Our customers continue to recognize Ensco as the leader in offshore drilling, rating us number one in total satisfaction in the annual EnergyPoint survey for the eighth year in a row. In addition to total satisfaction, customers rated Ensco the top offshore driller in 11 other categories, including safety and environment, performance and reliability, job quality, technology, plus several other technical and geographical categories. In addition to improving our safety and operational performance, we continue to selectively invest in innovations and technologies capable of improving the efficiency of our customers' drilling programs. Recently we expanded our intellectual property library by filing five patent applications for innovative technologies, and we plan to pilot some of our IP on rigs soon, starting with ENSCO 123. We have elected to defer the rig's delivery to first quarter 2019 in order to outfit it with the necessary equipment for this pilot program, which is aimed at reducing the amount of time spent tripping pipe while drilling. We have been encouraged by our progress to-date and expect to provide you with updates on this project later this year. Customers also recognized Ensco by awarding us new contracts during 2017. These contracts and extensions added more than $750 million of backlog during the year as we continued…

Thanks, Carey. Before I begin, I'd like to note that my prepared remarks will be somewhat longer than usual, as in addition to providing a review of our fourth quarter financial results and 2018 outlook, I'll discuss some recent developments, including the Atwood acquisition, enactment of new U.S. tax legislation, and our recent financing transactions. To help facilitate this, we prepared a supplementary slide presentation that I will reference during the call, which provides additional color on these items. This supplement, along with our earnings press release, can be found on the Investor page of our website. As a reminder, we closed the Atwood acquisition on October 6, 2017, and the fourth quarter represents the first quarter of results for the combined company. Starting with fourth quarter results versus prior year, we reported a loss of $0.49 per share compared to earnings per share of $0.13 in the year-ago period. Please refer to our press release and slide 2 of our supplement for a list of the items influencing these comparisons. Excluding these items, an adjusted loss from continuing operations of $0.23 per share compared to adjusted earnings from continuing operations of $0.09 per share a year ago. Total fourth quarter revenue was $454 million versus $505 million last year. In the Floaters segment, revenue was $303 million, equal to a year ago, as the decline in the average day rate to $307,000 from $358,000 was offset by an increase in the number of operating days, primarily due to the acquisition of Atwood. Operational utilization for the Floaters segment, which adjusts for uncontracted days and planned downtime, was 97% compared with 98% a year ago. In the Jackup segment, revenue was $137 million, compared to $187 million a year ago, mostly due to a decline in the average day rate…

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

Thank you. And our first question will come from Gregory Lewis of Credit Suisse. Gregory Lewis - Credit Suisse Securities (USA) LLC: Yes. Thank you and good morning. I guess, Carl – I mean it's been out in the market now for over a month, regarding the DS-8. You kind of laid out pretty clearly what types of options that contract is looking at. Realize that you probably can't say much. Can we think about – is this something that is going to be an overhang for an extended period of time, or is there something where, one way or another, we would expect Total and Ensco to come to a resolution around the DS-8 sooner rather than later?

Yeah. Morning, Greg. I think, first of all, probably to put it in some context, this is not the first time we've been through these conversations. We've entered into discussions with the client in this particular case, and with other ones where we have longstanding relic contracts, quite frequently. So it's not unusual in that context. We specifically called it out because, of course, we were in the capital markets in January, and it was an element that we felt that we needed to disclose. But it wasn't that it was a particularly unique situation. I can't go into the exact details. I think that it will probably be resolved one way or the other during Q2. And I don't think it's out of the ordinary to the type of conversations we've had in the past. And, as we've said before, if there is an agreement to be had here that's mutually beneficial such as a sensible blend-and-extend or some form of extension onto the contract, then we will happily entertain that with the client if we can come up with a win-win. If not, we have good, strong contract protections on that contract, as we've announced. So I think it will be resolved one way or the other within probably the next quarter. Gregory Lewis - Credit Suisse Securities (USA) LLC: Okay, great. And then just – you mentioned that, and clearly this contract was signed in better times – wow, seems like forever ago. As we think about – it clearly sounds like customer inquiries are getting better. You guys on prepared remarks mentioned, hey, maybe we're starting to turn a corner. While pricing still remains something that seems to be in the far-off distance, from a contract negotiation standpoint, is the language in the contracts starting to return maybe to a normal world where the drillers are a little bit more protected? Is that something that's at least starting to take hold in some of these contract negotiations?

No, I think – clearly as we've gone through the cycle the last couple years, and the weight of negotiating position has swung towards the customers, we've seen a deterioration in the protections in the contract, principally around early termination. As we've said before, what we haven't done is had to sacrifice anything around legal protections, transferring excessive risk, or liabilities. But the principal reason has been around, often, termination protection, being paid for mobilization, and in some cases upgrades that's required to get the rigs there. I think what we are seeing – and those haven't materially changed in the contracts that are leading at the moment. What has been changing a bit is our ability to walk away from contracts if we think that they're too onerous, or that we can't get a little bit of better language because the feeling is something else will be coming around the corner. So we haven't seen anything materially change in the current contracts, but what we have seen is a little bit of a change in psychology from ourselves and from some of our competitors about picking and choosing which contracts to enter and under what terms. Gregory Lewis - Credit Suisse Securities (USA) LLC: Okay, perfect. Hey, thank you, guys, very much for the time.

Thanks, Greg.

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

Hi. Good morning, guys. And I want to say congrats on executing with the bond offering and all the financial management you've done recently. I did want to ask on the fleet mix. In prior calls, you've talked about a comprehensive fleet review following the Atwood acquisition. Can you give a status of where we are there? And I guess specifically around your older jackups, do you feel – where do those fit in the Ensco fleet over the coming couple of years?

Okay. So, yes, we did say that post-Atwood, we would sit back and have a look at the broader fleet. We now have 62 rigs in that structure, makes us the largest offshore driller by fleet size, which means that that gives a degree of flexibility about being able to continue to manage the fleet, make changes on the edges without fundamentally changing our platform, our footprint, and the mix of assets that we have. On the back of that, I think, the two major decisions that we did take was to decide to retire 5005. And I think that's indicative of the future of some of these older, less capable floaters that exist out there. And we decided that that was a rig where we couldn't justify any further investment in capital. What we also did, as you saw, is that we took a look at the future life of some of the rigs that we have currently on contract and decided that that was probably shorter and therefore we took an impairment on two other of our older, noncore floaters. With respect to the jackups, we've already taken a lot of hard decisions and removed a lot of the older jackups from the fleet. Ones that we currently have in, we think, have got viability going forward. But clearly, there are several rigs there in the older category which we are going to let run through their current contracts, use them to generate cash, and then when they come to the end of their current contracts, we're going to take very careful, judicial looks at them. And if we can recontract them without them requiring major – further capital spending, then we'll keep running them. Otherwise, some of them we may retire at the end of their contracts. But we're talking about a very small number.

Okay. Thanks for that. And then second question is around the newbuilds DS-13 and DS-14. Just wanted to get a couple of questions related to those rigs. If I understand, are you most likely to take the yard financing that's provided for those rigs? And I'm curious how having those units in the hopper kind of impacts your M&A decisions, and kind of also do you expect to upgrade these units in any way or add different capabilities that you would like to take that opportunity to do?

Maybe I'll answer a little bit on the last questions. And then Jon can talk a little bit on the financing issue. Firstly, those rigs we have a good - [Technical Difficulty] (45:16 – 45:25)

Operator?

Yes. It appears we have lost the connection. I will dial back if you'd like to proceed.

Yes, we'll give a moment for you to dial back because we're having some technical difficulties here. Thank you.

Okay. I'm sorry. I think we lost the line. So let me just backtrack where we were. So I'll just answer a little bit on the ships, and I'll let Jon talk about the financing. So, first of all, just to reiterate, DS-13 and DS-14 are some of the most capable rigs in the entire global fleet. So there is very little that we need to do to actually bring them out. And so at this point there is no major plan to upgrade them in any way. Now, we have talked about some of the technologies we've been trialing. If for instance some of those proved to be really successful, and that we have big client uptake for them, then we could consider retrofitting some of those to DS-13 and -14. But that's not currently in the plans. We also have a strong agreement with the shipyards, which means that we can keep them there at low cost, and we have no intention to market those rigs at this point. So what that means is that our main high-capacity drillships that are market facing at the moment are DS-9 and DS-11 and they're the ones that we are primarily marketing for the current deepwater drillship contracts. Jon?

Yeah. And from a financing standpoint, fortunately we do have a lot of flexibility on those, so we don't have to declare whether we're going to convert those into the promissory notes until those rigs are scheduled to delivery, which is one and two years out, respectively. And so, for the time being, the base case is still that we would pay those, but we can convert those to the promissory notes with 5% interest with a maturity of December 2022, which if you look at some of even the financing we just did, which was at attractive rates, the 5% is still a fairly attractive rate. So it does provide us a lot of flexibility. And at the time of delivery, we would contemplate using that option to roll those over.

Great. Appreciate the thoughts.

Thank you.

And our next question comes from Ian Macpherson of Piper Jaffray.

Hi. Thanks. Just a quick guidance follow-up. Carl, you opened up with some revenue guidance for the year, and then we got the corresponding cost guidance just on a Q1 basis. So I know if you'd wanted to guide the full year on costs, you would have. But just thinking directionally, I would envision more rig days in the second half of the year, or just more rig days progressively through the year to think about the volume trend of operating costs from Q1 into later quarters. Is that fair?

Broadly, yes, Ian. And just to give a little bit more outline on that, we're still in the mode of not giving full-year guidance just because of where we find ourselves in the market and how quickly things are changing. But we did give a revenue guidance partially because we felt that some of the market commentators have probably built too much revenue in for this year. And as such, the consensus was a little bit high from what our predictions were. And that's largely driven by the fact that I think people have just got a little bit ahead about how fast some of these new contracts will come into place. We do anticipate winning more. We have built into our forecast new work coming for the second half the year, and we do anticipate winning some more contracts over the next few months. But several of those probably won't mobilize or become active until the tail end of the year. And as such they don't have a great influence on 2018 revenue as much as they do 2019. So that's the reason we gave the revenue guidance, just to kind of align that a little bit. But the general essence of the market trajectory we agree with. And we do anticipate – if we stay in the type of market conditions we see today, we do anticipate more rig days and utilization beginning to pick up in the second half of the year.

Okay. Thanks. And then for a follow-up question, just maybe you could compare the pricing broadly, the pricing environment for premium jackups versus ultra-deepwater, specifically rigs in your 120s class, your 140s class, where you had some contracts pending. Is it fair for us to think about day rates there that are still historically low – and I would think that's under $100,000 a day easily – but at probably better cash margins than is typical for most asset classes right now? Is that a correct way to think about it?

Okay. So, again, we're not going to give a tight guidance on this. But. So, first of all, there is a difference between pricing between the jackup segment and the floater segment. In the jackup segment, it does look like pricing has bottomed out at still, in most cases, quite reasonable cash-generative levels. Most contracts being signed today, we haven't seen too much pricing movement. But what we have seen – there are a few geographies around the world where it does look like pricing has come off bottom, or beginning to. And the higher-capability, harsher-environment jackups is one of those. The North Sea in that area for heavy-duty jackups is beginning to improve, look better. And we see some other geographies where we're beginning to test a little bit of pricing. I think it will be modest in 2018 and, as we said in the prepared statements, that we will be looking really into 2019 before we began to feel that we would see any real pricing changes in the jackups. But we are beginning to see things come off bottom in a few places. And the cash generation in the segment you called out is still pretty good. The floaters are different. And I think as we said in the pre-prepared statement, that most contracts that are going to be put in place and start in 2018 are at close to or limited cash margin. We need to see a bit more of a pickup in customer demand and we need to see a little bit more of attrition before we can start to see a position where we would feel that you could test pricing. But we do think that based on the current tender and inquiry levels that we're going to start to see utilization pick up in 2019. Now, what we are doing is we are – been getting more selective now, particularly in the floaters segment, about which contracts we bid on and at what pricing levels we bid on them, mainly under the view that there's more options now, so you don't have to chase every single thing that's out there.

Well, that's something. Very helpful as always. Thanks.

And the next question comes from Waqar Syed of Goldman Sachs.

Hi, Waqar. Waqar Syed - Goldman Sachs & Co. LLC: Hi. How are you?

Very good. Waqar Syed - Goldman Sachs & Co. LLC: My question relates to 5004 floater. You're retiring the sister rig. This rig's contract ends kind of midyear. Do you see the future for this rig, or after the contract ends, you think that this may be stacked or retired?

Waqar, I maybe missed that, but are you referring to 5004? Waqar Syed - Goldman Sachs & Co. LLC: That is correct. Yes.

Yeah. Yes, I think at this stage, we see opportunities around the Med area for that rig potentially to work on. We also have a replacement strategy to upgrade it with another rig if we don't find the new contracts for it. So I think 5004 for us is a little bit of a swing rig, depending on how quickly we see the market recover. Waqar Syed - Goldman Sachs & Co. LLC: Okay. And then some questions on your 8500 Series rigs that have the capability for conventional mooring. Just from my understanding, when you're bidding them for conventional mooring work, do you maintain the DP certification and the subsea engineers on the rigs, or you let those people come off and you go into complete concessional mooring more and maybe reduce costs substantially?

Waqar, this is Carey. We do keep our personnel onboard. There are some natural cost savings that come from not running all of your DP equipment, let's say, and your power system. But some of those rigs are actually going from one well that's moored, and the next well could be DP'd. So we keep them onboard.

Yeah. We keep them onboard. We keep them in certification, because, as Carey said, there's often flexibility between the – the real niche that those rigs have found is where they're working between moored and DP contracts on different wells. I'll just use the opportunity to explain a little bit more of our fleet strategy around the 8500s. We don't intend bringing out any of the other rigs that are stacked at the moment until we see market conditions improve. We are going to market the ones – the three that we have out, and we'll look for better utilization and longer-term contracts on those rigs before we bring out any of the further 8500s. So we're going to maintain quite a difference between what is our marketed fleet and what is our stacked fleet. And then secondarily on that issue, it's very likely that as we bring out those additional 8500s, we will bring them out with mooring adaptions. Waqar Syed - Goldman Sachs & Co. LLC: Great. Very helpful. Thank you very much. That's all I have.

Thank you.

The next question comes from Colin Davies of Bernstein. Colin Davies - Sanford C. Bernstein & Co. LLC: Good morning. The conversation around evolving contract structures and the dynamics of the negotiation with customers is very interesting. But the piece I'm quite curious about is we've heard from others of potential longer-term tenders may be starting to come forward in the floater market. So, firstly, are you also seeing that, and how do those conversations go? Is it simply customers trying to lock in their rig portfolio at low cost long-term, or is there some reasonable conversation starting to occur around inflation in the sort of 2019, maybe even 2020 period, of inflation on priced options, and those types of structures?

Yeah, Colin. Broadly, we are seeing an increased number of tenders and inquiries now for longer-term floaters, which is something that's really developed over the last two or three quarters. That's been driven by two things. The first is that several of our customers have deferred out projects that they really need to do for as long as they can, and are beginning to need to – now to contract rigs for those. The second one is what you referred to, which is actually customers' beginning to see that they might have bottoms in pricing, and beginning to try and lock in pricing. The discussions around how you tender those, and the negotiations with clients, are very mixed. And I think you've probably hit upon one of the hardest decision processes that we have at the moment, which is exactly how to price the out-years. In general, we are trying to price increased stepped pricing, not locking in at one low future rate – certainly for those contracts that are longer – or to bid differential pricing structures depending on whether it's for one to two years or three-plus years. And it's somewhat different in each case. But, quite clearly, if you're on the customer side of the table and you do have the ability to go award a long-term contract, they are trying to lock them in at the lowest rates that they can. Colin Davies - Sanford C. Bernstein & Co. LLC: Yeah. That's helpful and understandable. And then in terms of some of the conversations that were occurring at the time of the Atwood transaction, the push, obviously – and I think you'd articulated, the priority – was to really build up the backlog on those Atwood rigs given the quality. Perhaps you can give us a little bit of an update on the strategy there vis-à-vis trying to get exposure to lock into some longer-term business, or whether it's really just a scramble to get that backlog filled in on a bunch of shorter-term opportunities.

No – firstly I think we have split our fleet into a marketed and effectively non-marketed fleet at the moment. And a lot of the rigs that are in the non-marketed fleet or are stacked, we are going to keep them stacked for a while and only release them into the market in a very controlled manner as we see better conditions. So that means our focus is on our market-facing marketed rigs, and our priority is to win contracts on those. And in the ultra-deepwater or the drillship market, as we said earlier, our two major rigs that we are looking to try and market now as we go through the remainder of this year are DS-9 and DS-11. But what we are doing is doing a little bit of a portfolio effect, which is we are relatively comfortable with putting some rigs away on quite low pricing to have them there, secured, in a key market, warm, and generating some cash. And then to maybe hold back a proportion of the fleet that we're waiting to try and place into probably a little bit better price or more attractive contracts. And to give you a little bit more color on that, what makes a contract attractive is not necessarily just the headline day rate. The things that we are looking at is where is the contract, with which customer, whether there is follow-on work in that particular area. But what has become increasingly important has been that several customers – that some contracts are coming out with quite ridiculous wish lists for upgrades, improvements in technology, all at the rig contractor's expense. Now, those don't make sense if then the day rate is not attractive. And so some of those contracts we're choosing not to pursue under that type of tender, and we're either bidding as is, and therefore making it more attractive, or choosing to place into other contracts where the upfront capital outlay is much more limited. Colin Davies - Sanford C. Bernstein & Co. LLC: That's very interesting and makes perfect sense. Thanks very much.

Thank you.

And next we have a follow-up question from Ian Macpherson of Piper Jaffray Simmons.

Hey. Thanks for the follow-up. This is going back – it's sort of more backward-looking than forward. But for your lengthy reconciliation of adjusted EBITDA for Q4, we're not adding back the Atwood contract amortization. And I wonder if it would be fair to think of that as an additional cash add-back to cash EBITDA. It's less material going forward, but nonetheless more than a rounding error. So just thoughts on that?

Sure, Ian. I'm just looking at the supplement. Are you walking down the EBITDA reconciliation from that schedule?

Yeah.

Okay. So tell me again, what's the line item you're asking about?

In Q4, $16 million of kind of contract amortization from the Atwood revenues, right?

Right.

Is your net income at the top of that reconciliation not suppressed by that contract amortization?

It is. But it also shows up on the schedule later down. So you see the $15.8 million amortization net – it's included in that item.

It's in there. Sorry. Okay. Sorry to waste your time.

No, and there's more than just that in there. I just quoted the Q1 2018 number, but in the Q4 number, there are several ins and outs, but it is included in that amortization line.

All right. Thanks for straightening me out on that, Jon.

Sure.

It's far from straightforward, Ian.

Hence the supplemental schedules.

Yeah. Okay.

And at this time, we have no further questions. I'll hand the call back to Nick.

Thanks, Laura, and thank you, everyone, for your participation on today's call. We look forward to speaking with you again when we report our first quarter 2018 results. Have a great day.

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