Good day, everyone, and welcome to Ensco Plc's Fourth Quarter and Full Year 2016 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 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 2016 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 our earnings release on our website for additional information. As a reminder we issued our most recent fleet status report on February 22. 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. The offshore drilling industry continues to face challenging market conditions. We remain in the midst of arguably the worst downturn our sector has ever faced. During 2016 commodity prices reached new decade lows. And reductions in customers capital expenditures led to declining utilization and day rates across the global fleet. Despite this difficult backdrop, our offshore crews and onshore personnel did an outstanding job of staying focused on our core values of operational excellence and safety. And in turn delivered the best performance in our company's history. Across the fleet, operational utilization was 99%, a new company record, and a 3 percentage point improvement over last year's results. Floater operational utilization was particularly strong at 99%, compared to 94% in 2015. We also achieved our best ever safety performance, setting new company records for total recordable and lost time incident rates. And we made improvements in several other key safety metrics. Our improved operational and safety results benefited from targeted investments in enhanced systems and training that have improved equipment reliability and increased competency among our rig crews. These investments are part of a multi-year effort to further improve our systems, processes, and technology, which will help to differentiate our assets from the competition through better performance and reliability. In addition to being core values for Ensco, operational efficiency and safety are critical to our customers, especially in the current market where customers have their choice of rig or company they contract with. To this end we were honored to once again be recognized as the leader in total satisfaction by our customers, earning the number one rating for offshore drillers in the annual EnergyPoint Research survey, our seventh consecutive year to win this award. In addition to total satisfaction our customers rated Ensco…

Thanks, Carl. As Carl mentioned, Ensco has once again been recognized by our customers as the industry leader in customer satisfaction in an independent survey by EnergyPoint. This achievement is the result of a continued focus and commitment to safe and efficient operations by our offshore crews and onshore personnel, as evidenced by operational and safety improvements that resulted in new company records in 2016. Our preventive maintenance programs and the condition based monitoring of equipment on our rigs also play an important role in delivering high levels of uptime. We've made significant investments in these areas, including implementing our proprietary Ensco asset management system to continue improving our operational and safety performance to further differentiate Ensco from our competition. Our outstanding performance has also helped Ensco win several contracts and extensions for our rigs, totaling approximately 14 rig years of incremental work since our last conference call. Starting in the Middle East, we secured additional work for ENSCO 54, extending its current contract for five years into 2022. We also reached agreements with customers to extend lower day rates for 2017 that will keep several rigs working in the region. The Middle East has been the most resilient market during the downturn and continues to be an important region for Ensco, as evidenced by our seven rigs currently under contract. We also took top honors in the Middle East in the EnergyPoint survey, a reflection of the strong performance from our offshore crews in the region. Moving to the Asia Pacific market. ENSCO 106 will return to work for a new program offshore Indonesia that is estimated to take five years to complete. Our prior operational performance for the customer in the region differentiated us from the competition and positioned us to win this work and return an uncontracted…

Thanks, Carey. Today I'll cover fourth quarter financial results, our outlook for the first quarter 2017, and actions we have taken since our last call to further strengthen our financial position. Starting with fourth quarter results versus prior year, fourth quarter 2016 earnings per share from continuing operations were $0.10 compared to a loss of $10.23 a year ago. As detailed in our press release several items influenced these comparisons, including a gain on a debt-for-equity exchange during fourth quarter 2016, discrete tax items that impacted results in both periods, A loss on impairment a year ago, and a customer dispute related to a contract for ENSCO DS-5 last year. Total fourth quarter revenue was $505 million, versus $828 million last year. In the floater segment revenue was $303 million, compared to $490 million in fourth quarter 2015, primarily due to a year-over-year decline in reported utilization to 44% from 57% last year and a decline in average day rates to $358,000 from $397,000 a year ago. Operational utilization for the floater segment, which adjusts for uncontracted days and planned downtime, was 98%, up from 96% a year ago. In the jackup segment revenue was $187 million, compared to $307 million last year. As reported utilization declined to 54% from 66% in 2015. And average day rates declined to $101,000 from $126,000 a year ago. Operational utilization for the jackup fleet was 96%, compared to 99% a year ago. Total contract drilling expense declined to $289 million from $415 million in fourth quarter 2015. Excluding a $17 million provision for doubtful accounts in the year ago period, contract drilling expense declined 27% due to fewer operating rig days and disciplined expense management. Depreciation expense was $110 million, in line with our expectations. General and administrative expense of $25 million was…

Thanks, Jon. Keri, 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 of Credit Suisse. Please go ahead.

Morning, Greg. Gregory Lewis - Credit Suisse Securities (USA) LLC: Yes. Thank you and – hi, good morning. Thank you. So a couple weeks ago at our conference, one of the big subjects was around potential M&A and the timing of that. Just as we look at Ensco's balance sheet, clearly you guys had a big 2016, doing what you needed to do to get the balance sheet where it needs to be. How are you thinking about that over the next 12 months to 18 months?

Okay. Well, I think the way you asked your question summarizes very much what our strategy was. In 2016, we very much wanted to get our balance sheet and liquidity in position. And we were very much aimed at building a bridge through to the recovery. I think that now we find ourselves in 2017 with a little bit more confidence of an uptick in client activity that now we can start to look a little bit further forward and maybe use that liquidity in a little bit more of an offensive way. But what I would reiterate is that first and foremost, our priority still remains on making sure we can manage our way through our near-term liabilities. And importantly in that is the $300 million that we still have remaining on our new build program to deliver the final two rigs, DS-10 and ENSCO 123. Thereafter, what we have seen during the last couple of quarters is that when we have looked at our various opportunities to deploy capital, we have started to realize that we have quite a significant number of investment opportunities by investing in our own fleet. And on a risk/reward balanced basis, these seem to produce some very good returns. So we have been looking at ways to modify and improve our current fleet. And we've referred to some of it in the prepared statement. So we are doing modifications on some of the rigs. We are adding offline handling to the ENSCO 140, ENSCO 141. We've had – as we've announced, we're going to add another mooring system to ENSCO 8504. And we bought another set of the equipment – or we're going to buy another set of the equipment to give us the option on another modification of an ENSCO 8500. And…

Okay. I mean this leads into a bit broader discussion on market conditions. And I think what I would refer back to is the point we made in the pre-prepared statements, which is that we certainly feel that we're in a different point in the cycle. And that 2017 is going to be a pivotal year, probably very much as we look at it in the rear-view mirror. But it's not like the lights have suddenly come on. And I think that the – as we said we expect the recovery to be protracted and staged. And I can expand on that a little bit more in a second. But all that said, what we have seen is a broad-based pickup in client activity in terms of tender opportunities and inquiries. It's much more marked in the jackup segment, where we are seeing tender activity that is – if you look at the fourth quarter versus – of 2016 versus the fourth quarter of 2015, we have seen over 100% increase in the number of tenders and inquiries. And we have seen the number of tendered days go up by over 3x, a factor of 3x. So we're seeing a higher number of inquiries and the contract durations are longer. So I think it supports what we said in the last earnings call, while we felt that the jackup market would be the first to pick up and that there was the possibility that utilization would bottom out in 2017. Now to kind of reinforce that a little bit literally whilst we are on the call, we have had a contract back and conformation of an award for the ENSCO 92 in the North Sea, which is an extension of this contract by four years. And as a result we…

The next question comes from Scott Gruber of Citigroup. Please go ahead.

Yes. Good morning, gentlemen.

Morning, Scott.

Carl, we see the jackup market leading the turn here. What is the outlook for high-spec jackup demand in the North Sea, Middle East, elsewhere? What is the likelihood that we could see some of your idle ENSCO 140s, MOD Vs and I think there's at least one ENSCO 120 idle. What are the chances that some of these rigs go back into service this year?

Well, for some of those markets it's early. But I think that if we see the trend continuing that we see here, we would be – we're hopeful that we will start to see some of these rigs back to work in the second half of the year. In Jon's comments we referenced the fact that our CD&E costs in Q1 will be a little bit higher than maybe people have expected. But in part that is because we're actually proactively prepping a few rigs in anticipation of more work in H2, which is as yet uncontracted. But we just feel on the general trend that it's probably time to get an early start on some of that to get rigs ready for potential work, H2. And I think the two markets you picked out, the North Sea and the Middle East, is where we will be hoping to get more placements as we go through the next quarter or so. There's certainly quite a lot of tendering activity, which suits our rigs in those markets.

It's obviously in the Middle East then that would be jackup demand. Is there jackup demand in the North Sea as well, as you're prepping some of these high-spec jackups?

Yeah, Scott. This is Carey. In fact, our high-spec jackups in the North Sea, the ENSCO 120 series, are kept warm and prepared to answer some of those opportunities.

Got it. And just on that topic and as we turn to the floaters, I think you guys have discussed in the past the $25 million to $35 million reactivation as you pull the rigs out of preservation stack mode. And I know that the demand pickup as you mentioned is late this year into 2018. But how do you think about striking the balance between the customer desire to contract hot rigs and your own desire to receive a payback on the restart investment? So if your active floater fleet becomes more fully utilized, would you reactivate some of the preservation stacked rigs speculatively to keep one 8500 series or one drill ship ready? Or do you wait and demand a full payback on a certain contracts before you reactivate? How do you think about striking that balance?

Okay. So, Scott, first of all, on that $25 million to $35 million guidance we gave on reactivation. I think that the more we now work with these stacked rigs that the more we feel confident that's the right range. In fact, what we now are beginning to understand is that the actual true reactivation cost is actually probably less than $10 million. The rest is made up of catch-up on maintenance that you would have to have done anyway and maybe some upgrades to make the rig applicable to the client's program. So that's just to give you a little bit more color on that. The – with respect to keeping rigs warm, yes – and having rigs ready to go, we are inclined to always have at least one or two rigs of any class ready to go for work. Now remember thus far, we still have rigs like DS-7 and DS-9, which are ready to go to work. And if you take the case of DS-7, it's warm, ready to go. But we would be prepared if we saw the right market conditions to proactively bring out maybe one additional drill ship and one additional ENSCO 8500 series warm and ready in anticipation of work and not require the first project to carry all the cost of doing that. Now that's something we can do, because we have the financial wherewithal to do it. Not necessarily everyone is in that same position. And it's also – is very much why we have driven to make sure we have the liquidity to see through the cycle, because we want to be able to make that proactive investment to have rigs ready.

Got it. I appreciate the color.

The next question comes from Haithum Nokta of Clarksons Platou Securities. Please, go ahead.

Hey, morning, gentlemen.

Morning, Haithum.

Morning.

Jon, you were able to extend a portion of the revolver last year I think, which was somewhat of a surprise just on an unsecured basis at least. And that was before the OPEC decision. Curious to know, since then obviously the market has – or the capital markets have definitely improved. Is there any upside to be able to either extend that revolver further or increase the availability under that one year extension?

Yeah, sure. So the revolver extension this year, just to kind of frame how that works. We – for our full revolver we have 14 lenders comprising that $2.25 billion facility that we have today. When we originally entered into that facility, we had two one-year options at our election to call the options and a lenders' option then to extend. And so what we did this time here was we actually exercised one of those options. And each of those 14 banks within the revolver were given the choice to extend or not to extend. And so we were approximately half, so the $1.13 billion extended for the additional year. So within that existing revolver under those terms, we still have one of those options remaining. And we continue to evaluate if and when the right time to go back to lenders for that. We monitor the markets for the – for bank lending. The revolver was put in place under investment grade terms. At this point we are not an investment grade company, so we have been downgraded by S&P and Moody's to sub-investment grade. And so those extensions aren't necessarily given, given the change in credit profile. But we do have a very strong relationship with our banks. And I think that our banks view Ensco very favorably from a credit standpoint within the industry. And so we continue to have those conversions with the banks to see the appropriate time to ask for any further extensions or to potentially even ask for an increase.

I appreciate that color. And I guess to shift gears to the ENSCO 8503, congrats on that initial contract in Mexico. I'm curious if you can expand a little bit on what you're seeing in the Mexican market? And specifically for that rig, I mean is it relatively easy for a floater to move between the U.S. and Mexico side from a customs and tax and all that kind of perspective? And then also do you think – how do you think about – the operators are thinking about their contractor selection in Mexico? Are they kind of importing kind of their preferred providers from the U.S. or internationally? Or kind of just any color around that would be helpful?

All right. I'll take that first and then maybe I'll let Carey add a little bit more color on some of the practicalities. So firstly, I mean I think there were a couple of key capitalistic markets for helping in the recovery here. One of them is Mexico, the other one is Brazil. And we've mentioned this before, primarily because the legal and physical conditions are changing there and allowing more international capital to come in. And unblocking the constraints that have existed of having one major national operator. And so I think over time both those markets are going to become important during the recovery. Neither is going to be just – instantaneously and drastically affect 2017. Both of them are going to be a bit slower burns. But they are going to over the next couple of years begin to take in more floaters. With respect to the last part of your question on what we're seeing, is certainly the customers that we're talking to do have a preference to use the international drilling companies that they work with and have an ongoing relationship with. And that is one of the things that has allowed us to go in with the ENSCO 8503. I think it's probably a little bit different for jackups. But we've even had a lot of conversations with clients who work on the U.S. Gulf of Mexico side that going into Mexico now that would ultimately like to take companies like us with them. They may end up using local companies, but that's the tenor of the conversation.

Yeah. And also Haithum, this is Carey. I'd add that the issue of moving rigs in and out of Mexico or back and forth to the Gulf of Mexico is not a major issue. We've done it for years with our jackups. And there's not much – it's not more complicated for a floater.

Okay. Understood. I appreciate that. Thank you.

The next question comes from Ian Macpherson of Simmons. Please go ahead. Ian Macpherson - Simmons & Company International: Hi, thank you. Congratulations on the fresh four-year extension on the ENSCO 92. I know there's a reason why day rates are becoming more private now. And I won't be so brash as to ask you to tell us your private day rates. But when you – when we look at the ENSCO 92, when we look at the ENSCO 106, can you help us understand your strategy for bidding long-term contracts? Are they fixed rates for these multiyear programs? Are they variable? Are they performance linked? Or are – is there an index? Can you provide any color around these recent pictures?

Yeah. A little bit but without as you say going – we've made the decision on the fleet status report now to not issue pricing and day rates on an ongoing basis. And maybe if I just add a little bit more to that, I think very clearly we're in a very competitive market condition and pricing is quite a sensitive issue. So we've decided to do that for competitive reasons. But I think the other is that all with – I think what we're doing is really formalizing and making it just very clear on a go forward basis, what is starting to become a pretty normal practice now amongst certainly a lot of our peer group. And rather than selectively picking and choosing some contracts to announce and some not to. And allowing then there to be speculation about why we've disclosed some and not others, we just decided to be systematic and consistent. Now with respect to our bidding strategy on the jackups, I think that we are quite prepared to put some of our rigs away on long-term contracts. Certainly where we think that the day rate is still appealing for us at – over those long durations. And where we think they're working with key customers in key basins. And what we will do is we run a bit of a portfolio approach, so having locked away a few on longer-term contracts, we wouldn't do that on every single rig. But I think you should view this as a bit of a portfolio approach. And having some of our rigs on good long-term contracts, which are cash generative, I think at this stage of the cycle is something we're happy to do. And in this particular case we've been working – the ENSCO 92, we've…

I think it's the latter. It's a long-term improvement and adding flexibility to the rig. I think we have been very pleasantly surprised by the client response to that and the number of opportunities that it opens up. Now clearly at the moment it's a very low day rate environment. But we think that as we go forward what this will do is it will provide a market niche for some of our ENSCO 8500s that other rigs can't easily compete in. And where we're not going head to head with the drill ships. It increases the demand for the type of work that we think that they will do in the future, which is to do a lot of work around existing infrastructure, where they're going to be drilling infill wells, step-out wells, re-entry onto wells on existing deepwater assets. And we think that that's going to be an important part of the market going forward and one of the areas that will recover earlier in (52:21) the floater segment. Because I think what we are quite clearly hearing from our customers is that they're going to prioritize investment around existing basins and existing blocks. And they're going to put money back to where they have existing producing assets, because the incremental barrel costs there are much lower than the new development. And so I think you should view this as us making a more long-term investment in the future of the ENSCO 8500 series rigs. And trying to place them to a very specific market demand that we think is going to be building. Ian Macpherson - Simmons & Company International: That makes sense. Thanks for the color, Carl. I'll turn it over.

Thank you.

The next question comes from David Smith of Heikkinen Energy Advisors. Please go ahead.

Hey, thank you, and good morning or good afternoon. Just regarding the cost guidance for the first two quarters – and sorry if I missed it – but do you have a rough estimate of how much relates to contract preparation or start-up cost?

Yeah. Hi, David. We're not actually disclosing the details of that kind of level of granularity. But I would say that if you look at the – what we kind of guided in our prior earnings call a quarter ago, the big delta between the CD&E guidance and where we're at today is largely driven based on those start-up costs. And so if you were to run a delta on that, that's not only that. But that's the material part of the difference that you see in a quarter-over-quarter in that guidance.

Yeah. What I would add, that if you – it may have been a little bit buried in the statements, but a relatively important factor is that in Q1, we expect to go up – our utilization, our average utilization across the fleet to go up from 51% in Q4 to 57% in Q1. So we are seeing – so some of the cost increase is actually just activity based CD&E. And the other is as we said is some preemptive preparation for – well, some of it is actually rigs starting those – the investments we're making to get those rigs ready to work. The other is a little bit of preemptive work, because we are seeing generally a little bit of a pickup in our utilization. And we want to have rigs ready to move on that. And to that end, a point I was going to make earlier is just that we have taken a series of fleet rationalization decisions in the past in 2016. But I think we are very much out of the mode of preservation stacking now. I think from what we see in the market, any rigs, any of our core fleet that comes off contract now, we are going to be keeping it warm stacked, ready to go back to work at this point, unless we were to see a material step down in the market conditions or a major fall off in commodity price. That's very much the mode we're in.

I appreciate all that color. So just quickly regarding your comment about the preemptive costs for potential startup. Is it fair to ask if that first half cost guidance, if there's any allowance for the reactivation of a preservation stacked rig or two?

Sorry. I'm not quite sure we follow.

I was just going to ask if that first half operating cost guidance included in the allowance for the potential reactivation costs of a preservation stacked rig – I should say preservation stacked floater.

We have made some – on one of our floaters in Tenerife we have made some – we've started to do some pre-active work on that to see whether we would pull it out of preservation stack. I wouldn't say we've gone the whole way yet. But some of that cost is in the Q1 guidance.

Great. Thank you very much.

The next question comes from Sean Meakim of JPMorgan. Please go ahead.

Thanks. So just to follow up on that a little bit. You've obviously taken a lot out of the cost structure the last couple years. And this, I'm sure, isn't the first time I've asked you this, but is the signaling in your prepared remarks on that first half guide basically saying on a per rig basis, we've bottomed in terms of OpEx reductions? I mean that would seem consistent with your view as you just stated with the preservation priority versus now the hot stacks. Is it fair to say that we've perhaps hit bottom on that per rig basis for OpEx?

I think on an operating basis, yes, we're probably pretty close. I won't say we've driven out every little bit. And we're still working on some other ways to reduce some of our support overhead cost and so the operating cost. But I think you shouldn't expect major reductions going forward further on an operating basis. And on our CD&E, our CD&E going forward is going to be very dependent on how many rigs we have operating and what our utilization is. So if our utilization starts to come back up, you will see CD&E go up accordingly, because we will have more operating rigs. I think – I hope that answers where you were going.

Yeah.

So first, I think there are two things at play at the moment, as we look at our CD&E. The first one is that we are seeing the continuing effect of actions we took in 2015 and 2016 that really – where we changed and cut our support structure costs and our structural elements across the whole company. And some of that is still playing out as we go through the next couple of quarters. Because we took some cost actions in 2016, where we still aren't seeing the full effect yet. What is offsetting that a little bit is, as we start rigs back up and our utilization comes back up, then we have a corresponding offset in just the actual operating cost of running a rig.

Exactly. Okay. No, that's very clear. And then just one last one on the DS-10. I was just curious if you could maybe give us a little peak into the decision tree, as you're thinking about the choice in terms of the duration of the delay, alternative options, stacking? Just curious how we think about – how that thought process unfolded?

I think first and foremost, what we've looked to do is reduce our ongoing cost over the next kind of year or so, of having the rig at the shipyard. And we've ended up with an agreement that has reduced that cost versus what we would have incurred if we'd have taken it ourselves. On the duration I don't think you should read too much into that. It's partially just a mutual agreement we came to with the shipyard. We are still marketing that rig. And I know this may seem strange in the current market environment. But given that it's one of the most capable drill ships in the global fleet, we still have had client interest in that rig. So we're continuing to market it. And our hope and intent is still that we can bring it out before the official delivery date at the beginning of 2019.

Okay. Great. Thanks, Carl. I appreciate it.

The next question comes from Colin Davies of Bernstein. Please go ahead. Colin Davies - Sanford C. Bernstein & Co. LLC: Good morning. Yeah, just reflecting on some of the prepared remarks and comments for the Q&A. And a noticeable change of tone. So just thinking about your earlier comments around industry rig scrapping and particularly potential further candidates within the Ensco fleet. Are there still sort of a prioritized list there, that might move to scrap, they come off contract? Or can I take from your comments that the thinking within Ensco now is to really hold most of that portfolio for the turnaround in the market?

I think – well, first of all largely we – as we've gone through this cycle, we guided very clearly to rigs that we think are not in our core fleet. And we have pulled those off into held for sale or discontinued ops. And we have – and as they become idle that we have announced that we intend to scrap them or sell them. So for example in the floater fleet, ENSCO 5000, ENSCO 5001, ENSCO 5002, ENSCO 6000, ENSCO 6003. So there's a list of rigs that we have – and DS-1 and DS-2 and ENSCO 7500. We have clearly said that we will remove them from the fleet when they came available. The others within our floater fleet I think that we are very comfortable with where we sit today. And we intend to keep that floater fleet as our core fleet. On the jackups there are a few of our old jackups that we will assess as they come to the end of their contracts on the cost of any SPS or renewal versus what we expect for renewal rates or extension rates. And we will make some decisions at that point. But largely the fleet structure that we have – we – is that we're comfortable to go forward with. And we have – and the what – we've very clearly indicated the rigs that we have been removing. Colin Davies - Sanford C. Bernstein & Co. LLC: That's very helpful, thanks. And then just to change to tack slightly. You'd mentioned through the Q&A and the remarks as well around a pickup in tender activity and inquiry activity. And obviously you said the jackup activity is stronger. But you did say I think that you are having more conversations around floater opportunities. I'm intrigued where that's coming from in light of lower CapEx amongst the IOCs. Are you seeing a pickup more in sort of NOCs and independents rather than the IOCs?

We're seeing a mixture. But I would go back to what I said, which is that the macro trend is still for utilization on the global fleet to drop through 2017. The number of inquiries that we've seen and tenders coming out is a step up than we saw through 2016 and 2015. But that's coming off an extremely low base. And the number of inquiries we've seen are not enough that we have seen to offset the number of deepwater rigs which will have contracts ending this year. So that's important to put in context. Now what we have seen is Brazil, we've seen a number of new inquiries and tenders coming out for Brazil. We've seen a few shorter term ones around Africa, around East and West Africa. And we're seeing one or two in Mediterranean and Asia. Colin Davies - Sanford C. Bernstein & Co. LLC: Okay. That's very clear.

I think one of the big differences is that where in the jackup market, we've seen an increase in activity and duration of contracts being offered. It's the opposite in drill ships. In the average duration of a drillship contract that is out and being tendered now is lower than it was a year ago. So we're seeing a lot of shorter duration contracts come out. And some of that is customers taking advantage of current pricing to do certain bits of activity, where they have to do it or they already have the capital committed. The other thing that's coming to play is that a lot of people have announced flat or slightly lower E&P spending in the offshore in 2017. But because the cost and supply chain basis is a lot lower, in some cases that's flat activity. Colin Davies - Sanford C. Bernstein & Co. LLC: Interesting, yeah, yeah. That's very helpful. Thank you.

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

Thank you, Kari. I want to thank everyone for your interest in Ensco and participating in our call today. Have a great day.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect your lines. Have a great day.