Valaris Limited (VAL) Q4 2015 Earnings Report, Transcript and Summary

Good day, everyone, and welcome to Ensco Plc's Fourth Quarter and Full-Year 2015 Financial Results Conference Call. All participants will be in listen-only mode. After today's presentation, there will be an opportunity to ask questions. Please note, this event is being recorded. I will now turn the call over to Mr. Sean O'Neill, Vice President of Investor Relations, who will moderate the call. Please go ahead, sir. Sean Patrick O'Neill - Vice President-Investor Relations & Communications: Welcome, everyone to Ensco's fourth quarter 2015 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. During this call we will discuss GAAP and non-GAAP financial measures and a reconciliation between the two is included in our earnings release. 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 the risk factors and other events that could impact future results. Also, please note that the company undertakes no duty to update forward-looking statements. As a reminder, we issued our most recent Fleet Status Report on February 16, and we issued our Form 10-K yesterday. Now, let me turn the call over to Carl Trowell, CEO and President. Carl Trowell - President, Chief Executive Officer & Director: Thanks, Sean, and good morning, everyone. We are facing extremely challenging market conditions. The recent incremental leg down in commodity prices and uncertainty regarding the timing and degree rebalancing in the oil markets has caused our customers to announce further reductions in capital expenditures, the results of which is to push out the likely duration of the down cycle for the offshore drilling sector. As a consequence, we have taken further steps to improve our liquidity so that we are well placed to persevere through the downturn and positioned for an eventual recovery in market conditions. These market conditions and the current outlook drove the goodwill and asset impairments we recorded in the fourth quarter of 2015, which Jon will discuss in further detail. However, broadly speaking, the weight of the asset impairments have been to rigs which we either intend to scrap or retire and those which are aged and we do not believe will have a place in our long-term fleet. During the quarter we sold ENSCO 5001 for scrap and in total, we sold two floaters during 2015. Furthermore, we intend to scrap or permanently retire the following floaters; ENSCO DS-1 and ENSCO DS-2, ENSCO 6000 and ENSCO 7500. We also plan to retire jackup rigs ENSCO 56, ENSCO 81, ENSCO 82, ENSCO 86 and ENSCO 99. Along with three jackups currently held for sale. We believe the rate of rig scrapping across the sector will accelerate as we go through 2016. And we believe this will be an important factor in rebalancing the rig market. Turning to other fleet management decisions, we've delayed the delivery of ENSCO 123 by 19 months, pushing out approximately $200 million of CapEx to 2018. However, we are moving forward with ENSCO 140 and ENSCO 141, which are being built in the Middle East and expect to take delivery of these rigs later this year. Additionally, we have made the decision to cold stack ENSCO 8500 to reduce operating costs along with ENSCO 8501 and ENSCO 8502 until market conditions improve. We will continue to market our four remaining 8500 Series rigs. We view the 8500 Series as part of our core fleet, but do not believe there are enough market opportunities to justify keeping all seven rigs in this series available for work. As outlined in our prior disclosures, including our Form 10-K filed yesterday, we are in dispute with our customer for ENSCO DS-5. We believe we have a valid contract in force and we are in discussions with the client regarding this matter. Nevertheless, for the fourth quarter, we did not recognize any revenue for ENSCO DS-5. We recognized a $17 million provision for doubtful accounts in connection with unpaid receivables from prior periods. Excluding the financial impact of the ENSCO DS-5 dispute with our customer and impairments, we posted strong fourth quarter results that reflect the actions we have taken to further improve operational performance and reduce costs. As outlined in our press release, adjusted earnings were $0.92 per share and our adjusted contract drilling expense was $398 million for the quarter which is better than the guidance we provided on our last call. Financial performance during the quarter was driven by record fleet wide operational utilization with 99% for jackups and 96% for floaters. Revenues in the fourth quarter also benefited from the delivery and contract commencement of ENSCO DS-8. Exceptional performance by our capital projects and operational teams resulted in an on-time delivery, a very successful startup with the rig achieving nearly 100% uptime. ENSCO DS-9 and ENSCO 110, two newbuild rigs delivered earlier in the year also contributed to fourth quarter financial results. We are on track with our previously communicated cost reduction targets of $57 million in annualized savings from restructuring the support functions of the company that included a 30% reduction of our onshore workforce and a 15% reduction in offshore unit labor cost, both compared to 2014 levels. This is in addition to cost savings we've achieved by proactively stacking rigs and lowering cost for uncontracted rigs. On the back of actions already taken, we expect that our contract drilling expense will be lower in the first quarter as Jon will outline later. Our cost reduction initiatives are being undertaken in a very structured way and our fourth quarter results show that operational excellence and safety can be achieved alongside rigorous expense management. In fact, our dedicated crews and onshore personnel delivered another record year in terms of key safety measures in 2015. In terms of capital management, it's important to emphasize that the actions we've taken have given us an improved liquidity position, with $1.3 billion of cash and short term investments and a fully available $2.25 billion revolving credit facility. To further improve liquidity and to give us greater flexibility to manage our capital structure, the board of directors has decided to take further action on the dividend as reported in our earnings release. The unprecedented level of pullback in capital spending by E&P companies will eventually lead to a supply response and offshore reserves will play a major role in future global oil supply. In the meantime, we remain extremely focused on what we can control, namely, fleet restructuring, operational performance and cost reduction. The cycle will eventually turn and oil prices will increase at which point we will be well positioned. Now, I'll turn the call over to Carey Lowe who succeeded Mark Burns when he retired as COO in December. P. Carey Lowe - Chief Operating Officer & Executive Vice President: Thanks, Carl. In conjunction with our organizational restructuring last year, we decided to integrate our marketing teams into our operations group with the goal of having more seamless interaction with customers at the operational and business development level. We believe this will help us to win more work and we have continued to capitalize on the few opportunities available around the world resulting in the recent addition of several new contracts. Among our floaters, we secured work for ENSCO 85 (sic) [ENSCO 8504] in Indonesia that will keep the rig working into mid-2016 and we have bid the rig into several opportunities in the Asia-Pacific region for potential follow-on work. ENSCO 8504 has had an excellent operational and safety track record over the years, a record that contributed greatly to earning this new contract. Additionally, we won short-term work in the same region for ENSCO 5005 which commenced its 60-day contract in late 2015. Moving to our jackup fleet, we were able to earn additional work for two rigs in the North Sea, a four well extension for ENSCO 120 and a four month accommodation contract for ENSCO 102, both of which will help our jackup utilization in 2016. Our strong operational track record in this region, evidenced by Ensco's number one ranking in the North Sea category of EnergyPoint's Customer Satisfaction survey contributed heavily to these new contracts. As you'll note in our most recent Fleet Status Report, this is one of our best regions in terms of contract backlog. Just this week, we were awarded six months of work starting in Q3 2016 for ENSCO 107 in Australia with Chevron at a day rate in the high $120,000s. We also earned two contracts for ENSCO 75 in the U.S. Gulf of Mexico, a short-term job during the fourth quarter of 2015 and a one year contract that started earlier this year. This contract will keep the rig working into 2017. This represents a significant achievement in a region that has seen an 80% decline in the number of contracted jackups over the past year and is a testament to our operations teams. These new contracts added approximately three years of work, bringing our total to approximately 18-rig years earned during 2015, which included the previously announced three year contracts for ENSCO 104 and ENSCO 110 in the Middle East as well as ENSCO 71 and ENSCO 72 in the North Sea, plus ENSCO 8505, which earned a multi-year contract for both shallow and deepwater work in the U.S. Gulf of Mexico that leverages our hybrid moored and DP configuration. This design provides flexibility to customers and was the result of extensive collaboration between our operations, engineering and marketing teams, which we believe will help us win more work. We now have two ENSCO 8500 Series rigs in this configuration and are likely to upgrade a third. Earning these long-term contracts, especially in the current environment, is due to Ensco's commitment to go beyond customer expectations with premium assets and exceptionally well trained crews, crews that deliver leading safety and operational performance. As Carl noted, we achieved record fleet wide operational utilization in the fourth quarter and for the full year we achieved a new safety record with the lowest total recordable incident rate in Ensco's history. This type of performance is what led to Ensco being recognized as the best offshore driller in overall customer satisfaction for the sixth consecutive year, including the number one rating in the Middle East and Asia Pacific in addition to the North Sea region as I just mentioned. In an effort to extend our leadership position in operational performance and customer satisfaction, we implemented a new Ensco asset management system over the past year. This proprietary system is the result of a multi-year joint project spearheaded by our asset management group and supported by operations, information systems and several other groups. This system will make our repair and maintenance processes even more efficient and cost effective. Our record setting results are the culmination of the successful work we've conducted over several years on many fronts, including fleet design, training and development, new systems and vendor management. These efforts are ongoing and we will continue to leverage our expertise and innovation to drive improvements. Specific examples of these include investments in our quality assurance and quality control department, additional training and more rigorous testing for our offshore crews, which have increased organizational competency around the equipment on rigs, and improved processes and procedures for rig-based activities such as between well maintenance where we have reduced downtime and improved subsea equipment performance. We have been very pleased with our safety and operational improvements to date including a meaningful reduction in BOP-related downtime hours per active rig in 2015. Another way that our sector improves safety and operational performance is through the quality of the global fleet of offshore rigs. Our recent investor presentation, which is on our website, details the new rig supply coming into the market that will high-grade fleet quality. But it is also important to note that the global fleet of rigs is likely to decline in number by the end of 2017, which will not only help to rebalance supply and demand dynamics but also improve the overall quality and reliability of offshore drilling for our customers. Since third quarter of 2014, offshore drillers have announced scrapping of 50 floaters including the floaters, we referenced in our earnings release. Over this same period, an additional 38 floaters have been cold stacked. Looking at the current supply picture, approximately 40 floaters, including some of the cold-stacked rigs I just mentioned, are more than 30 years of age and idle without follow-on work. Another 50 floaters are more than 30 years old and will see their contracts expire by the end of 2017. In total, these 90 floaters are likely candidates for scrapping. And as a group, excluding the recent number – the reduced number of build in Brazil rigs are nearly triple the number of floaters currently scheduled to enter the market before the end of 2017. I should also mention that we are now seeing increasing number of floaters younger than 30 years of age being scrapped. And this trend will help to reduce supply. Similar to floaters, we expect stacking to accelerate for jackups. Here is a picture of competitive jackups defined as independent leg cantilever rigs, roughly 70 are 30 years of age or older and stacked or idled without follow on work. Another 75 are also over 30 years of age and have contracts expiring by the end of 2017. That brings us to a total of 145 jackups that are candidates for scrapping or conversion to non-drilling units by the end of next year. This figure far exceeds the 100 or so jackups scheduled for delivery by 2017, many of which may not enter the market in the medium term since two-thirds of these jackup newbuilds were ordered by speculators who were only required to make small down payments. So in summary, the intensity of the current downturn, while very challenging in the near term, will also be the catalyst to drive out excess supply through scrapping of older rigs and cancellation of certain newbuilds, which in the mid to long-term will be positive for our sector. Now, I'll turn it over to Jon. Jonathan Baksht - Chief Financial Officer & Senior Vice President: Thanks, Carey. Today, I'll start with our fourth quarter financial results, our outlook for first quarter 2016, and then I'll wrap up with a discussion of our financial position and capital management. As noted in our earnings release, several items impacted fourth quarter 2015 results and the year-over-year comparisons, including non-cash impairments totaling $2.9 billion, the impact of a customer notice regarding ENSCO DS-5 that Carl just mentioned and a favorable discrete tax item. Year ago results included $3.9 billion of goodwill and asset impairments, as well as discrete tax items noted in the non-GAAP reconciliation in our earnings release. Excluding these items, fourth quarter 2015 earnings per share from continuing operations were $0.92, compared to $1.68 a year ago. Total fourth quarter revenue was $828 million versus $1.16 billion last year. Lower fleet utilization was partially offset by the addition of ENSCO DS-8, which commenced its initial contract offshore Angola during the fourth quarter, ENSCO DS-9, which was successfully delivered in second quarter 2015, the addition of two newbuild jackups to the active fleet and the reactivation of ENSCO 5006 following a shipyard upgrade. In the floater segment, revenue declined to $490 million, compared to $663 million a year ago, primarily due to lower utilization of 57% versus 81% last year, and the decline in the average day rate to $397,000 from $429,000 last year. Earnings contributions from ENSCO DS-8 and ENSCO DS-9 plus the reactivated ENSCO 5006 helped to partially offset these declines. Operational utilization for the floater segment, which adjusts for uncontracted days and planned downtime, was a record 96%, up from 90% a year ago. In the jackup segment, revenue was $307 million, compared to $455 million last year. As reported, utilization declined to 66% from 88% in 2014. The average day rate declined to $126,000 from $147,000 a year ago. These factors were partially offset by the addition of two high specification jackups, ENSCO 122 and ENSCO 110 to the active fleet. Operational utilization for the total jackup fleet was 99%, up from 98% in 2014. Excluding a $17 million provision for doubtful accounts relating to ENSCO DS-5, we reduced total contract drilling expense to $398 million, better than our guidance of $415 million to $420 million that we provided in our third quarter conference call, due primarily to lower personnel costs. Year-over-year, we reduced contract drilling expenses by 23% from $514 million in fourth quarter 2014. Our active expense management and fewer operating rig days offset the incremental costs of adding two newbuild drillships, two newbuild jackups and the reactivation of ENSCO 5006. Depreciation expense increased $11 million to $150 million, in line with our expectations due to the fleet growth I just mentioned. General and administrative expense was $30 million, in line with our outlook. As detailed in our earnings release, interest expense was $5 million higher year-to-year due to our debt refinancing completed in first quarter 2015. Excluding discrete items, the effective tax rate was 15% for the fourth quarter. Our tax rate for full-year 2016 is expected to be in the mid-to-high 20% range due largely to a forecasted decline in revenues caused by deteriorating market conditions as well as a change in our geographic mix of earnings. Now, let's shift our focus to the outlook for first quarter 2016. Total revenues are expected to decline on a sequential quarter basis, due to an estimated 7% to 8% decline in average day rates from fourth quarter levels of $216,000. We expect reported utilization for the fleet to be in line with the fourth quarter in the low 60% area. We anticipate a further reduction in contract drilling expense during the first quarter based primarily on actions we've already taken to refine our cost structure. First quarter contract drilling expense is expected to decline to $385 million to $390 million, despite a full quarter of operations for ENSCO DS-8. As noted in our most recent Fleet Status Report, we have more rigs rolling off contract, particularly in the back half of the year and to the extent we do not re-contract these rigs, we will be proactively managing cost down by stacking rigs on an expedited basis. Depreciation expense is expected to decline by approximately $35 million from $150 million in the fourth quarter due to lower carrying values for rigs impaired during 2015. We expect first quarter G&A expense to decline slightly from fourth quarter levels of $30 million due to the restructuring and expense management actions taken last year. In total, other expense is estimated to be $62 million in the first quarter. In terms of our previously announced cost reduction plans, we are on track to achieve our 15% production in average offshore unit labor cost, compared to 2014 levels. Since offshore compensation is roughly half of total contract drilling expense, this will translate into meaningful cost savings during 2016. Additional expense management actions were taken to reduce our offshore – onshore workforce and we remain on track to achieve our annual run rate savings target of $57 million in 2016 versus 2014 levels. And as mentioned earlier, we will continue to proactively cold stack or scrap rigs without near-term contracting opportunities to manage our costs in line with market conditions through the cycle. Before we review our financial position, I'd like to briefly comment on the impairment charges taken during the fourth quarter. We evaluate our fleet for triggering events on a quarterly basis and any change in an asset's value is reflective of the expected marketability and asset life of the rig in light of our overall business outlook. We also perform goodwill impairment analysis at the end of each year. Due to deteriorating market conditions and our current outlook, we impaired several rigs in our fleet weighted mostly towards our older floaters and jackups, including 12 rigs that we plan to permanently retire as Carl mentioned. Deteriorating market conditions including a lack of visibility in terms of customer demand also factored into the board's decision to reduce the dividend and we believe it is prudent to preserve $130 million of annual liquidity, improving Ensco's capital management flexibility as we navigate the downturn. Now let's wrap up with a review of our financial position. Following our impairment, we ended 2015 with a net debt to capital ratio of 41%. We have $1.3 billion of cash and short-term investments and a fully available $2.25 billion revolving credit facility that matures in 2019. We have $5.8 billion in revenue backlog, which as noted in our earnings release excludes ENSCO DS-5 and we have no debt maturities until 2019. As Carl mentioned, our capital expenditure forecast has changed as a result of our decision to delay the delivery of a newbuild jackup. And our forecasted annual capital spend over the next several years will be significantly lower than 2015 CapEx of $1.6 billion. The final milestone payment for ENSCO 123 of approximately $200 million now moves into 2018. The 2016 CapEx projection has therefore been reduced to $450 million, of which $275 million is for newbuild construction. Our 2017 CapEx budget is also $450 million. 2018 CapEx is now expected to be $325 million, inclusive of the final milestone payment for ENSCO 123 and we have no newbuild CapEx beyond 2018. These updated figures are included in the most recent investor presentation on our website. In closing, since the downturn in the offshore drilling markets began in mid-2014, our actions have been aimed at tightly managing operating costs, including offshore compensation, ongoing rig maintenance expense, and onshore support costs. Capital expenditures by deferring milestone payments for uncontracted newbuilds and reducing our CapEx projections for major and minor upgrades through 2018 and liquidity, including reducing our dividend. These actions will allow us to focus on operational and safety performance, areas within our control during the downturn while optimizing financial performance in both the short and long-term. So with that, I will turn the call back over to Sean. Sean Patrick O'Neill - Vice President-Investor Relations & Communications: Okay, operator, please open it up for questions.

Thank you. We will now begin the question-and-answer session. Our first question comes from Ian Macpherson with Simmons. Ian Macpherson - Simmons & Company International: Thank you, everyone. The first question I had was regarding the Petrobras situation. You highlighted that Petrobras is taking the position that the ENSCO 6001 has exceeded allowable downtime and you might expect a termination notice for that rig. Is the ENSCO 6001 unique in that situation or is it plausible to assume that the ENSCO 6002, the ENSCO 6003 and the ENSCO 6004 could also be subject to similar friction as the quarter or as the year unfolds? Carl Trowell - President, Chief Executive Officer & Director: Good morning, Ian. Yes. So, let me just backtrack a little bit on the whole ENSCO 6000s, then I'll come back to the ENSCO 6001. Ian Macpherson - Simmons & Company International: Okay. Carl Trowell - President, Chief Executive Officer & Director: As of today and currently, all four of those rigs are still on contract, still earning revenue and we are current on all receivables. But as you maybe saw or if you referred to the – our latest Fleet Status Report – you'll have seen that the ENSCO 6001 did have downtime event during Q4 and zero pay days. And because we haven't received the termination notice for the rig, but because of the sensitivity around the Petrobras contracts, we have called that out and we identified it as a risk factor within our 10-K. So, the situation is that the rig has neared its contractual limit on downtime – allowable downtime – and we have a position where there is a difference in view about how time has been attributed to the rig between ourselves and the customer, which if it is deemed to have crossed that threshold, would allow Petrobras to terminate without cause. But that hasn't happened, but we have drawn attention to it. And it is – and that position is unique for the ENSCO 6001. Ian Macpherson - Simmons & Company International: That's helpful. Thank you, Carl. The other question I had was just regarding the impairment. It sounds like this most recent round has pertained to mainly older rigs and rigs that have been stacked – or I mean scrapped or slated for retirement – but I'm curious what your methodology is for impairment testing newer rigs that have been cold-stacked, like some of the ENSCO 8500s or one or two of the drillships and really what the thought process will be for establishing the carrying value of these newbuilds that you'll be receiving this year and next year, in a tough market, whereas the cash flow profile for the next few years, it probably doesn't justify the carrying value. What would trigger re-evaluation of the carrying value of these newer generation rigs that haven't been impaired yet? Carl Trowell - President, Chief Executive Officer & Director: I'll let Jon take some of the detail of that in a second, but I'll make maybe a couple of broader points. The first one is just to say that the process isn't different from an older rig or a newer rig and there is a pretty rigorous accounting process we have to go through, which is standardized regardless of the rig. And once you have – once you've deemed there is a triggering event, then you look across all of the fleet. But there is very big difference between rigs which have – we as you believe is a long-life span and a long time to recover cash flows – from a lot of the rigs which we have taken impairments on, where we believe that their marketable life cannot justify their carrying value when you look at the cash flows, particularly because we have in our fleet a series of rigs which we believe, probably don't have a long-term position, if you look forward, say five years. So if we look at the cash flow on those rigs over the next three to five years, that leads and triggers a large part of the impairment that we've taken. But I'll let Jon maybe expand a little bit on some of the details. Jonathan Baksht - Chief Financial Officer & Senior Vice President: Yeah. Good morning, Ian. So, just to add to Carl's comments, we do follow just standard accounting methodology as we look across our fleet for asset impairments and we do look at these by rig-by-rig. And so while the majority, as I said in my prepared remarks, the balance of the impairment was really on our older rigs. One of the reasons for that is there is a two-step process when you go through these impairments. The first step is a recoverability test. And so in my prepared remarks, you – where I mentioned the, that we look at the asset life and the market outlook for these rigs. And if you look at some of these newer assets, so a new drillship or an ENSCO 8500 specifically, you compare the undiscounted cash flows over the lifetime of that rig to see if it exceeds its carrying value. Only when it does not, do you take an impairment on that rig. And so that would be the same methodology that we use and that our peers use when looking at impairments. Once you do – once the – if you do find that you have an impairment, then you move on to the second test where then you actually look at the discounted cash flows to record the new carrying value for that rig. Ian Macpherson - Simmons & Company International: I got it. So, suffice to say there is still a lot of subjectivity with regard to those cash flows, even once a rig enters cold stacked status, is that fair? Jonathan Baksht - Chief Financial Officer & Senior Vice President: I think so, if you're looking for – I think as Carl mentioned, it depends on your long-term outlook. So if your outlook for that rig is it's cold stack and not returning, then the cash flows would in most cases not justify its carrying value. If you believe that rig will come back to work and then you forecast cash flows for that rig, then each rig would be considered on a case-by-case basis. Ian Macpherson - Simmons & Company International: Understood. All right, thanks, Jon. Carl Trowell - President, Chief Executive Officer & Director: Ian, I'll maybe take another opportunity just to explain a little bit of how we're running the fleet, because what we've effectively done is look at our fleet in the sense of a core and non-core rigs. And for the non-core rigs, many of these will keep working but these are rigs that we will not put a lot of CapEx into speculatively. And we will put any CapEx spend into the core fleet. Because we don't believe that we can get a material or sensible return on our investment for investing in some of those non-core assets and the weight of the impairments that we've taken are on the non-core assets. And it partially reflects the fact that when they finish current contracts or extensions within the next three years to five years. We are likely to not put major life extension CapEx into them. Ian Macpherson - Simmons & Company International: Okay. Thanks, Carl.

Our next question is from Jud Bailey with Wells Fargo. Please go ahead.

Thanks. Good morning. With oil prices dropping here to start the year, we've seen several contract cancellations across the industry and it sounds like discussions on blend and extend type opportunities have picked up quite a bit. I was wondering if you could comment on how that dialogue has progressed with some of your major customers in terms of coming back to you and their appetite to try to extend contracts at lower rates versus maybe an outright cancelation. Has that changed in the last couple of months or maybe just give us a little color on how those discussions may go? Carl Trowell - President, Chief Executive Officer & Director: Jud, you're right in the sense that there is quite a lot of active discussion around blend and extend in the marketplace at the moment. And with the downturn in the oil price, it's triggered a slightly different approach towards projects in 2016. So, I think we're going to see in general across the sector further discussions and further blend and extend contracts. We are – we've been on and off negotiations with various customers for several months now on a few contracts and we are willing to entertain blend and extend contracts where it can be of mutual advantage, where it helps the customer with near-term CapEx, but provides us with some additional backlog and some ability to manage risk as we go through the back years. So those, we have several ongoing negotiations ourselves. I imagine there are several others ongoing within the sector and it's often driven by whether the customer has additional term to be able to add and negotiate.

Okay. So, I mean, am I correct in thinking that we could see perhaps a couple of those opportunities come to fruition for you guys, perhaps this year based on the way negotiations seem to be going or am I reading too much into that? Carl Trowell - President, Chief Executive Officer & Director: It's possible. I think a lot of it will rotate around whether the customer has got something that they can offer that helps us as well.

Okay. All right. That's fair. And then, I guess just a quick follow-up on the ENSCO 8506, I think you said during your prepared comments you were going to cold stack the ENSCO 8500 and I believe that still leaves the ENSCO 8506 as still being marketed or warm. Does that suggest you may have some work for that, some point during the year? Carl Trowell - President, Chief Executive Officer & Director: We are going to keep ENSCO 8506 warm and we're keeping marketing it because as of today we do see some opportunities around in the Gulf of Mexico for the similar type of work that the ENSCO 8503 is doing and ENSCO 8505. So we will see how things pan out but we do believe that there's enough work as we go through this year and next year to continue marketing that rig.

Okay, great. Thank you. I'll turn it back.

The next question comes from Waqar Syed with Goldman Sachs. Please go ahead. Waqar Syed - Goldman Sachs & Co.: Thank you for taking my question. Two questions first. Have you looked into the BOP rental market as some of your competitors are looking into, would that fit in with your outlook? P. Carey Lowe - Chief Operating Officer & Executive Vice President: Waqar, this is Carey. Good morning. Yeah. We've considered this with some of the OEMs and this deal, the deal that you're referring to is not necessarily unique. So we'll continue to evaluate it but it's important that we weigh any incremental improvements against expected costs. One of the stated reasons for doing this has been to improve uptime on the BOPs and we've been working on improving our BOP uptime for some time and as I mentioned in my remarks, we've made some significant strides over the past couple of years to improve subsea equipment downtime. So, yes, it's something that we're considering and looking at. But it has to make sense financially. Waqar Syed - Goldman Sachs & Co.: Okay. Great. And secondly, as we look into 2016 and beyond maybe 2017, like you mentioned for the ENSCO 8500 Series rigs, they're going to be intermittent downtime between contracts and rigs are going to be warm stacked and then working. What's the operating cost difference, even if you can't give specific numbers, but just like in general, between when rigs are going to warm stacked and when they're going to be operating? Carl Trowell - President, Chief Executive Officer & Director: Waqar, it's Carl again. The – without giving the exact incremental, but we can warm stack an ENSCO 8500 for round about $30,000 to $32,000 a day and have it available to go back to work again quite quickly after that. Does that help you? Waqar Syed - Goldman Sachs & Co.: No, no, absolutely. But is that a number that you can keep it stacked for like six months at that rate and then pick it up without incremental kind of cost or no, that is probably more a number in a one month to two month timeframe where you can keep it that way? Carl Trowell - President, Chief Executive Officer & Director: A little bit depends on a rig-by-rig basis, but yes, you could do it for an extended period like six months. What matters is if it then falls out of any particular class or survey there or any particular time base maintenance it needs in that meantime. But assuming that you were keeping up the regular rhythm of classifications and certifications, then yes. Waqar Syed - Goldman Sachs & Co.: Okay, great. Thank you very much.

Our next question comes from Robin Shoemaker with KeyBanc. Please go ahead.

Yes. Thank you. So, I wanted to ask you just going back to the liquidity issue again. You've got the undrawn revolver, which you negotiated in 2014 and goes to 2019 now. It was obviously negotiated at a very favorable time and I just wonder what restrictions if any apply to the drawdown of that revolver in terms of a covenant or something that might restrict the ability to tap into that? Jonathan Baksht - Chief Financial Officer & Senior Vice President: Hey, good morning, Robin, this is Jon. We really don't have any restrictions in terms of drawing down, the only real covenant we have on that revolver is a 60% debt-to-capitalization test, which we are well under.

Right. So with the CapEx program you have in place and your projections, would you believe that this – there is no need to draw on the revolver through this period of remaining fleet construction or expansion? Jonathan Baksht - Chief Financial Officer & Senior Vice President: Robin, I can't really comment on cash flow projections through 2019, what I can point out is that we do have $3.5 billion of liquidity today, including $1.3 billion of cash and short-term investments, the newbuild commitments, as I mentioned in my remarks, if you aggregate all the newbuild profile it's only $850 million and it's spread out over the next three years and then we have no debt maturities through 2019. So, we do have a very strong financial position and a very strong liquidity position.

Right. Okay. Thank you.

Our next question comes from David Smith with Heikkinen Energy Advisors. Please go ahead.

Hi, good morning. Thank you. I just wanted to ask if there is anything that precludes you from aggressively repurchasing your bonds in the open market, particularly the 2019 through 2021 maturities, which look like they're priced for low 20% yields? Carl Trowell - President, Chief Executive Officer & Director: Hi, David. The simple answer is no. We have cash and we have liquidity, so we could do it, if we wanted to. We haven't done it thus far.

I noticed. I was just wondering if there was anything that precluded you. So I appreciate that. Carl Trowell - President, Chief Executive Officer & Director: Yeah. No, there is nothing that precludes us.

The second follow-up was just regarding the cost savings initiatives, I wanted to ask if the labor cost savings include any reductions to base wages, and if not, whether you've seen any indications that competitors have instituted base wage reductions for drilling crews? Carl Trowell - President, Chief Executive Officer & Director: So, we haven't reduced our base salaries thus far, we – the cost structure and the – our wage structure offshore was deliberately structured with quite a lot of discretionary elements to it, and we have removed those discretionary elements. And so we haven't taken that step, I'm not aware at this point of any of the competition or peer group attacking base salaries yet. And I think, the thing that we will always bear in mind is that we still want to maintain a well-motivated work force, because as you've seen, as we've gone through the last year or so the value of uptime and operational performance can outweigh any savings on some of the compensation, so one extra percent of uptime brings a lot to the bottom line for us. So we will do – we're very careful about balancing what we do on offshore labor versus the operational performance and the motivation and retention of our key workforce.

Makes sense. Thank you very much.

Our next question comes from Sean Meakim with JPMorgan. Please go ahead.

Hey, good morning. Carl Trowell - President, Chief Executive Officer & Director: Good morning, Sean.

So just wanted to track back on the ENCO 8500 Series. I know you highlighted some leads maybe for the ENSCO 8506 in the Gulf of Mexico. For a rig like that, at some point would you ever consider an unsponsored relocation to another market like Southeast Asia? Is that something that could ever be in the cards? Carl Trowell - President, Chief Executive Officer & Director: Simplistically yes. I think if we saw the right opportunities and either the right contract or the right circumstances building. For example, the evolution of several potential market contracts that would fit the rig series, then I think we would. And I've said this before that we have probably too many of the ENSCO 8500 Series within the Gulf of Mexico and over time, we would like to redistribute some of those. So, the answer is yes.

Okay. Yeah, that makes sense. And so on your drillship fleet, as you're managing the fleet across a fairly limited number of opportunities, does the ENSCO DS-5's early release change your plans in any way and just kind of thinking about the potential for any impact on the ENSCO DS-10 in terms of delays? Carl Trowell - President, Chief Executive Officer & Director: No material change in the plans as a consequence of that. What it would do maybe is just govern which rigs we would bid into which contracts. But as of yet, no change on the ENSCO DS-10, and I think we wouldn't look to take an early decision on that. We would wait to see as we got nearer the time.

Got it. That's fair. Thanks a lot.

Our next question comes from Mark Brown with Seaport Global Securities. Please go ahead.

Hello. I was wondering on the ENSCO 123 if you had to pay any penalty to delay that and whether that was on schedule before that decision was made and if you can give any commentary? Jonathan Baksht - Chief Financial Officer & Senior Vice President: Yeah, hi, Mark. Yes, we did pay a fee to extend it for 19 months; it was $15 million.

Okay. Good, good. Thank you. Carl Trowell - President, Chief Executive Officer & Director: And the rig was on schedule for delivery as per plan from the shipyard.

Okay, got it. And I was wondering you might have mentioned this in your prepared remarks, but if you had any commentary on Saudi Aramco situation with those renegotiations? And related to that, some of those are fairly old rigs, old jackups, and was curious if there's any consideration to potentially swap in some of your newer rigs, although I do know that Saudi Aramco requires certain capabilities that might have been upgraded in those older jackups a while back. Carl Trowell - President, Chief Executive Officer & Director: Yeah, Mark, there's not too much I can go into here on the call because as you've seen from the Fleet Status Report, we are in the process of actually discussions with Saudi Aramco around what the day rates and fees will be going forward. Yes, several of those rigs are old rigs, but they are all equipped to Schedule G which is the specialist Saudi Aramco specifications. They've been invested in over a long time and they are very fit for the purposes that they're being used for. That being said, the ENSCO 140 and ENSCO 141, which we will take delivery of later this year, have been built to the same Schedule G and Saudi Aramco specification. So they can slot into Saudi Arabia if circumstances were right and the client requested them or wanted them. And we are in a more broad sense, not just for Saudi Arabia but across the whole Middle East, we are looking at maybe opportunities to switch those rigs with some of the older ones if the right circumstances come about. But just to be clear, we wouldn't have to do any further investigation – any further upgrades or investment in the ENSCO 140 or ENSCO 141 to put them into Saudi Arabia.

Okay. And then just if I could, one more quick question on the comments around scrapping in the industry, you think – you said you identified 90 floaters that were candidates for scrapping – and you believe that the pace of that scraping is likely to accelerate. Do you think all 90 of those would be scrapped this year or what kind of timeframe were you thinking of? Carl Trowell - President, Chief Executive Officer & Director: Well, I think what will happen is you'll basically have silent attrition which is a lot of these rigs will be put on the dock and cold stacked and if not immediately announced that they have been scrapped, I think the chances of a lot of them, the majority of them not coming back out in the market is very high. And that's the way I think you should look at it, which is why I think you should look at scrapping and effective permanent retirement of some rigs of this type.

Okay, great. Thank you. I appreciate it.

Our next question comes from Darren Gacicia with KLR Group. Please go ahead.

Hey, thanks for taking my question. When you think about kind of further cost cutting from here, and you think about sort of the contract drilling cost line, can you give a sense of what part of those costs are sort of rig-by-rig operating costs in terms of people and direct running the rig versus sort of support and where might you kind of see more cost coming out or not or are we kind of much further along that now where there is less to sort of strain out of the system? Carl Trowell - President, Chief Executive Officer & Director: Hi, Darren. Good morning. So as you saw, we've taken a lot of support structure cost out of the system as we went through 2015 with a big reorganization of how we run our business units and our support structure. As we go forward, there's still the ability to optimize that and we are still looking at some additional ways to be able to be more efficient on the support structure. But the big levers, we can pull now is actually on the rig-by-rig basis and probably the biggest cost savings are related to some of the announcements we've already made today about scrapping or retiring some additional rigs and that allows us to bring down the cost very rapidly associated with those. And as we go forward, if we see that to the extent that we cannot re-contract some of the other rigs, we will move to cold stack a number of them because that allows us to be able to reduce cost quite significantly. So, I would summarize it this way, as we've outlined, our CD&E cost is still coming down on the back of actions that we've already taken. We will be taking a further cost reduction as a consequence of the rigs that we are stacking. And we have the ability to flex and react to the market conditions if we see that in the second half of the year, when we have a lot of contract renewals, that we have idle rigs.

Got you. On a different note and approaching a question that's kind of been asked in one way, that I want to ask in a slightly different way, with regard to repurchasing discounted debt, what you may or may not have done so far is one thing, what I'm more curious about is when you're talking to debtors, you're talking to the banks, you're talking to us frankly and investors. Do you feel like you'll get – you can get credit for buying debt, do the debt holders like that concept for reducing leverage? So do you get kind of value at it beyond just kind of the dollar pay down advantage you have when it's trading at a discount? Do the banks like that concept? I'm just trying to get a little bit more of a kind of philosophical/like what the conversations with the capital markets are right now around that type of a concept? Carl Trowell - President, Chief Executive Officer & Director: I think it's a bit of a hypothetical question. So I don't really want to get into it and maybe I'll hand to Jon, if he's got anything more to add. Jonathan Baksht - Chief Financial Officer & Senior Vice President: No. I think, like Carl said, it's a bit speculative. I mean what I can say is that buying debt when it is trading at a discount does improve your credit metrics and from that standpoint what the read through is and how people interpret that, I think that's open to interpretation.

Got you. One last if I could. If you think about distressed assets potentially being on the market at some point, is that something where if you have interest, is that something you'd use cash for, use debt for, use equity for or are all things open? Carl Trowell - President, Chief Executive Officer & Director: Well, I think all things are open, but I think what I would add to that is that we already, we're coming off the back of a major capital build out, so we have several new rigs, got some that are already in the ship – are in the shipyard yet to be delivered, so we would be looking very carefully at buying certainly one or two distressed assets. We would have to see that that was a sensible return on investment even at the discount purchase price. And the other thing is that, what we would want to make sure is that, it was the most valid use of our liquidity. So it would be a very carefully considered investment on our side and I – what we also want to be looking at is does it move the needle for us in the current market conditions versus where else we could put our cash.

Great. Thank you very much. I appreciate it.

Our next question is a follow-up from David Smith with Heikkinen Energy Advisors. Please go ahead.

Hey, thanks for letting me back in. I just wanted to ask if you could give any color on the comment in the 10-K about the one year tolling agreement with the DOJ, their request. I haven't had time to figure it out myself yet, but I was wondering if you could help us explain if there is any significance or implications on that? Carl Trowell - President, Chief Executive Officer & Director: David, no. It's a pretty standard process. It just means that the DOJ or SEC don't hit a backstop on term limits on some of the events and we've kept the DOJ and the SEC completely informed of the process during our internal and external investigation. They requested just as a matter of course a tolling agreement, which basically allows another 12 month stay on any term limit, and we've – we just agreed to that, we saw no harm in that at all.

Okay. So that doesn't imply that they've opened an investigation? Carl Trowell - President, Chief Executive Officer & Director: No.

Okay. Great. Thank you very much. Sean Patrick O'Neill - Vice President-Investor Relations & Communications: Okay. Operator, if there are no more questions, we just want to thank everyone for participating on our call today. Thanks, everyone again and have a great day.

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