Nick Georgas - Director of Investor Relations Carl Trowell - President and Chief Executive Officer Patrick Carey Lowe - Chief Operating Officer Jonathan Baksht - Chief Financial Officer

Gregory Lewis - Credit Suisse Ian Macpherson - Simmons Blake Hancock - Howard Weil Haithum Nokta - Clarksons Praveen Narra - Raymond James Colin Davies - Bernstein

Welcome, everyone, to Ensco's second quarter 2017 conference call. With me today are Carl Trowell, CEO; Carey Lowe, our Chief Operating Officer; Jon Baksht, CFO; as well as other members of our executive management team.

We issued our earnings release which is available on our website at enscoplc.com. Any comments we make about expectations are forward-looking statements and are subject to risks and uncertainties.

Many factors could cause actual results to differ materially. Please refer to our earnings release and SEC filings on our website that define forward-looking statements and list risk factors and other events that could impact future results.

Also, please note that the company undertakes no duty to update forward-looking statements. During this call, we will refer to GAAP and non-GAAP financial measures.

Please see the earnings release on our website for additional information. As a reminder, we issued our most recent fleet status report on July 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, I'll discuss some key developments since our last earnings conference call, starting with an update on our planned acquisition of Atwood.

We received US antitrust regulatory clearance in June and integration teams continue planning for a smooth transition. As it is customary in these types of transactions, we're working with the SEC to respond to their comments on our merger proxy and following Ensco at Atwood shareholder meeting to approve the transaction, we expect to close later this quarter.

While oil prices have declined since the announcement of our planned acquisition, we remain committed to the transaction for several reasons. By acquiring Atwood, we significantly enhance the drilling capabilities of our floaters and refresh our jackups.

Atwood has four best in class drillships that we believe will be the type of rigs that go back to work first as market conditions improve. These drillships have features such as dual directs, 2 BOPs that create efficiencies for customers as they complete the growth of project.

And we expect future customer demand will be higher for rigs of these capabilities. Additionally, Atwood's versatile semisubmersibles have established themselves by delivering high levels of operation performance to customers.

And the jackups are well through for opportunities that are developing during the early stages of the shallow water recovery that is underway. Furthermore, we expect to recognize significant synergies from the transaction.

We anticipate run rate expenses of $65 million on an annual basis beginning in 2019 and $45 million of synergies in 2018. After adjusting for approximately $100 million of transaction cost, we calculate these synergies create more than $400 million of present value at a 10% discount rate.

As we've learned more about the Atwood organization during integration and planning, our confidence in these synergy targets and transaction cost estimates has increased and as a result we believe this transaction creates meaningful value for shareholders. Finally, we evaluated different scenarios as we consider the acquisition, including a scenario where material pricing power for floaters does not return until after 2020.

And in each scenario, the transaction was accretive to Ensco's shareholders on a discounted cash flow basis. For these reasons, we believe that the proposed acquisition of Atwood is compelling for Ensco shareholders and we look forward to completing the transaction.

Upon closing the transaction, our fleet management strategy will shift in light of the new composition of our rig fleet. First, we will further rationalize legacy Ensco assets and we expect to retire several rigs over the next three years given the refresh that the acquisition will bring to our fleet.

Second, we will be highly selective in reactivating rigs until market conditions and pricing improve after closing, when a new work for Atwood's delivered floaters will be our top priority, so that we position these assets for the eventual market upturn. Third, further enhancements to our floater fleet will be limited.

At this time we expect to upgrade ENSCO DS-7 with a second BOP in anticipation of work beginning in the first quarter of 2018. Coupled with the rigs dual activity capabilities, this upgrade will improve the marketability of the asset over its useful life.

Since we already have a stead BOP [ph] in inventory, we expect this cost will be less than $10 million. We may incur additional CapEx for ENSCO DS-9 in the event that we contract the rig or if we elect to put a managed pressured drilling kit on another drill ship.

But our investments today have already positioned our drill ships among the most capable ultra-deepwater rigs in the market. Coupled with our highly competent crews and enhanced operational safety systems, these high specifications assets solidify our position as a key service provider for offshore customers globally.

In addition to the investments in our fleet, recent new contracts give us further confidence in our ability to meet future customer demand. By securing work for ENSCO DS-4 and DS-10 with key strategic clients on projects that have the potential for multiple years of continuous work, we improve our prospects for future utilization as we emerge from the downturn.

Returning ENSCO DS-7 for the active fleet for short-term jobs also position this rig follow-on work that we expect will increase its utilization during 2018. Among our jack-ups, multi-year contracts for ENSCO 120, 110, and 102 in strategic shallow water basins have added backlog and improved future utilization.

We've also continued to reposition our premium jack-ups into markets where the current supply is older and less capable. This includes our decision to move ENSCO 109 to West Africa and ENSCO 104 to the Middle East and more recently our decision to move ENSCO 102 from the North Sea to the U.S.

Gulf. We expect that the recovery in the offshore sector will be prolonged and paced.

Bridging our assets to better market conditions has been the priority over the past year. We expect the active high specification rigs, which can provide efficiencies for customers drilling programs and are operated by drillers with enhanced operational safety systems will be the rigs that win contracts as the market recovers.

As utilization for this subset of global supply improves, we believe these rigs will be the first to see increasing pricing though. More broadly, the market cycle continues to play out as expected.

Established offshore drillers are winning a disproportionate amount of new work. And there is a bifurcation amongst offshore drillers as larger customers are focusing on a selected group of service providers.

While recent volatility and commodity prices could present challenges at the onset of customers' 2018 budget season, we continue to see signs of improvement in customer activity. New contract awards and inquiries for future work have increased year to year, albeit of a very low base.

More projects have reached final investment decision sanction this year than we did for all of 2016, providing a pipeline future offshore work in the years ahead. While customer activity has increased, market conditions remain extremely challenging and we are in the midst of a sector changing downturn and we expect this will reconfigure the offshore drilling industry.

We anticipate that the recent trend of customers contracting rigs with established well capitalized drillers that have the technology, systems, scale, and diversification to help customers lower their development costs, while persevering through the industry cycle will continue. We believe the offshore drillers must adapt to this new reality or there will be competitively disadvantage and in certain cases obsolete.

Therefore, it is incumbent upon our management team to best position Ensco for this new reality. By acquiring Atwood and investing to enhance our own fleet, we significantly improve our assets and technology, bettering our ability to meet customer requirements when demand returns to high levels in the future.

In the interim, we remain focused on delivering high levels of operational uptime and safety performance to customers, so that we continue to win new contracts to keep our rigs ready to capitalize on improving market conditions. Now, I'll turn the call over to Carey.

Thanks, Carl. Since our first quarter earnings call, our offshore crews and onshore personnel have stayed focused on delivering high levels of operational uptime and safety performance to our customers.

Operational utilization was 99% in the second quarter in line with first quarter levels. And our safety metrics are tracking better than last year's record results.

We recently secured a new work in several regions, including three drill ship contracts. In total, we have added approximately 19 rig years of backlog year-to-date.

Ensco ranks first among all offshore drillers and new contracts during this time period, capturing approximately 20% of total rig years awarded industrywide. Starting in West Africa, ENSCO DS-4 is expected to commence a two-year contract offshore Nigeria in August with an option for one additional year of work.

This contract award is highly significant as it marks the first time we have reactivated a drill ship since the start of the downturn, demonstrating our ability to win work for preservation stack rigs ahead of competitors' rigs that are active or warm stacked. The rig is well suited for the customers' needs and is outfitted with dual derricks.

In addition to the rig's capabilities, our detail reactivation plans contributed to winning this contract. We activated DS-4 on time and within the previously announced cost guidance for returning a preservation stack floater to the active fleet.

Additionally, this process validates our stacking and reactivation procedures. We believe that as we move through the cycle, we will be able to do the same for our remaining preservation stacked rigs.

We also secured a one-year contract with five additional one-year options for Ensco DS-10, our final new build drill ship, which is among the most technologically advanced rigs in the global fleet. The rig's delivery will now be accelerated into third quarter of 2017 and it will undergo a period of customer acceptance testing before commencing its maiden contract offshore Nigeria in the first quarter of 2018.

ENSCO DS-10 is equipped with dual derricks and optimized whole design and fully retractable thrusters and riser storage in the hull. These features provide customers with efficiencies for their drilling programs, including lower fuel consumption, more usable deck space, and a higher variable deck load.

ENSCO DS-10 is a sister rig of ENSCO DS-8, which is also operating offshore West Africa and has consistently delivered high levels of operating performance and it's commencing its initial contract in fourth quarter of 2015. These contracts also underscore the importance of having a strong local partner in the Nigerian market.

By forming a partnership with OES, a local drilling contractor with rigs operating in the country, we have improved our ability to meet customer needs offshore Nigeria to our joint venture ODENL and we believe our partnership better positions our rigs for follow-on opportunities in Nigeria. In addition to these contracts, ENSCO DS-7 will return to work to complete a short-term project with its existing customer offshore Ivory Coast with an expected commencement date in August.

This allows us to return DS-7, which was a previously warm stack to an operational state in advance of anticipated work beginning in first quarter 2018. In the Middle East, ENSCO 110 has been awarded a three-year contract in Qatar.

The Middle East has been the most resilient market project for jack-ups during the downturn. And we have a strong reputation with customers in the region as evidenced by our number one rating for total satisfaction in an independent industry survey.

Moving to the North Sea, ENSCO 120 received customer approval to commence its three-year contract. Also in the region, ENSCO 121 and ENSCO 122 secured new contracts that will keep each rig busy into first quarter 2018.

ENSCO 102 has been awarded a 400-day contract in the US Gulf of Mexico that is expected to start in November and the rig is currently mobilizing from the North Sea in advance of this contract. Among our floaters in the Gulf of Mexico, ENSCO 8503 recently drilled the Zama-1 prospect offshore Mexico, the first offshore exploration well drilled by the private sector in the country's history, which resulted in a world-class discovery.

The customer has chosen to extend the contract for two months of operation on the US side of the Gulf of Mexico starting later this year. ENSCO 8505 has been contracted for short-term work and we are actively marketing the rig for follow-on opportunities.

Finally, ENSCO 52 completed operations in Malaysia and was classified as held for sale. ENSCO 56, 90 and 99, all previously classified as held for sale, were sold and will be scrapped.

ENSCO 86 was sold to an operator effectively removing the rig from the competitive supply. Turning now to the broader rig market, the number of new contract awards for floaters globally has increased over each of the past four quarters.

Tenders and inquiries, a leading indicator for new contract awards for shallow water work have continued their recent upward trend compared to a year ago. Projects sanctioning has also increased, including three deep water projects that were approved in the second quarter alone.

Furthermore, Mexico held a shallow water licensing round where strong customer demand led to the government awarding two thirds of the blocks available. Additional lease rounds in Mexico and Brazil are expected in the next six months and it is anticipated that these will draw answers from a diverse group of customers.

On the supply side of the market, 78 floaters and 21 jack-ups have been retired since the start of the downturn. We see another 65 older less capable floaters and 155 jack-ups as candidates to be retired over the next 18 months.

While retirements have slowed lately, we believe much of this situation is occurring silently as companies have no incentive to announce when they no longer plan to return a rig to the active fleet, particularly for jack-ups given their lower stacking costs. We expect the deliveries of uncontracted new builds will continue to be delayed until the demand recovers.

In closing, Ensco continues to capture an outside share of new contracts awarded in a highly competitive market. This stems from consistently delivering the highest levels of service quality and operational excellence to our customers.

At the same time, we've invested in our assets and technology to improve the drilling process and create efficiencies for offshore projects helping to set Ensco apart as the driller of choice with customers. Now, I'll turn it over to Jon.

Thanks, Carey. Today I'll cover second quarter 2017 financial results, our outlook for third quarter and a summary of our financial position, including our capital expenditure outlook for the remainder of the year.

Starting with second quarter results versus prior year, a loss of $0.15 per share compared to earnings per share of $2.04 in the year ago period. As detailed in our press release, several items influenced these comparisons, including $10 million related to the settlement of a previously disclosed legal contingency arising from a customer dispute that was included in the second quarter of 2017 contract drilling expense.

$6 million of discrete tax expense included in the second quarter 2017 tax provision; $4 million dollars of transaction costs related to the proposed acquisition of Atwood included in second quarter 2017 G&A; $261 million gain included in the second quarter 2016 other income related to the repurchase of senior notes; and $205 million of early contract termination settlements included in second quarter 2016 revenue. Excluding these items and adjusted loss of $0.10 per share compared to adjusted earnings of $0.51 per share a year ago.

Total second quarter revenue was $458 million versus $910 million last year. In the Floater segment, revenue was $264 million compared to $636 million in second quarter 2016.

Revenue in the year ago period included $205 million of early contract termination settlements for ENSCO DS-9 and ENSCO 8503. Fewer rig operating days led to a decline in our floater utilization to 43% from 57% a year ago.

And the sale of ENSCO 6003 and 6004, both of which operated during the second quarter 2016 also contributed to lower year-to-year revenues. Finally, the average day rate for floaters declined to $339,000 dollars from $360,000 dollars in the second quarter 2016.

Operational utilization for the floater segment, which adjusts for uncontracted days and planned downtime was 99% equal to a year ago. In the jack-up segment, revenue was $179 million compared to $251 million a year ago due to fewer rig operating days and the decline in the average day rate to $89,000 from $112,000 last year.

While the total number of operating days declined, the floater utilization increased by one percentage point to 64% due to the retirement of several jack-ups since last year. Operational utilization for the jack-up fleet was 98% compared to 99% a year ago.

Total contract drilling expense declined to $291 million in second quarter 2017 from $315 dollars a year ago, as lower personnel and other activity-based costs, due to fewer rig operating days more than offset expenses related to contract separation costs for rigs returning to work and the settlement referenced earlier. Depreciation expense declined to $108 million from $112 million a year ago due to the extension of useful lives for certain contracted assets.

General and administrative expense increased to $31 million in second quarter 2017 from $27 million a year ago due to $4 million of transaction costs for the proposed acquisition of Atwood. Interest expense in second quarter 2017 was $60 million, net of $14 million of interest that was capitalized compared to interest expense of $54 million in second quarter 2016, net of $13 million of interest that was capitalized.

The increase in interest expense is largely due to the convertible notes issued in fourth quarter 2016, partially offset by debt repurchases. As mentioned previously, second quarter 2016 other income included $261 million gain on the repurchase of $940 million of senior notes and an average discount of approximately 27%.

Tax expense declined to $19 million in second quarter 2047 from $37 million a year ago due to lower profitability. Now, let's compare second quarter 2017 to first quarter 2017 sequentially.

Revenue declined 3% due to a two percentage point decline in reported utilization and a slight decrease in the average day rate ENSCO 5004 was placed on a standby rate for a portion of the second quarter. Contract drilling expense increased $13 million sequentially, primarily due to the following items: $10 million of higher cost for jack-up surveys, shipyard projects and scheduled repairs and $10 million settlement that I mentioned earlier.

This is partially offset by lower reactivation costs for the ENSCO DS-4 and reduced cost for the ENSCO 5004 while the rig is on standby. Including the settlement I just mentioned, contract drilling expense for second quarter 2017 was slightly higher than our prior guidance range, primarily due to DS-7 reactivation expenses in advance of the new contract that will return the rig to operation.

This work and the related reactivation expenses were not contemplated in our prior guidance. Reactivation costs for ENSCO DS-4 are expected to total $28 million in line with our prior cost guidance for returning a preservation stack floater to the active fleet.

Approximately $18 million of these costs have been included in contract drilling expense to-date and we anticipate the remaining $10 million will be incurred over the next few quarters as we refurbish spare parts that were used in the rigs reactivation. In terms of the rig's total reactivation cost is approximately $6 million was for depreservation and $22 million is differed maintenance that would have been incurred if the rate had remained warm stacked.

G&A expense increased by $4 million due to transaction costs related to the proposed acquisition of Atwood. Other expense decreased by $4 million due to $6 million loss in the first quarter 2017 to complete a previously announced debt exchange, partially offset by lower capitalized interest in second quarter 2017.

Moving to our outlook for third quarter 2017, we anticipate the revenue will decline by approximately 2% primarily due to fewer operating days for our jack-up fleet as several rigs complete contracts and jack-ups undergo scheduled maintenance. This is partially offset by higher floater revenue from ENSCO DS-4 and ENSCO DS-7, which are expected to begin contracts in August.

We expect third quarter contract drilling expense will be between $295 million and $305 million. The increase in contract drilling expense is primarily due to contract preparation costs for ENSCO 102 before the rig commences a contract in the US Gulf of Mexico later this year.

Higher maintenance costs, as jack-ups complete surveys and shipyard projects, are partial quarter of operations for ENSCO DS-7, which will result in higher daily costs and the refurbishment of spare parts. These increased costs will be partially offset by $10 million decline related to the settlement of a customer dispute during the second quarter.

The third quarter is somewhat unique in that we have four jack-ups undergoing surveys during the quarter combined of higher spare refurbishment activity and contract preparation costs. We expect the contract drilling expense will decline from third quarter levels to approximately $275 million to $280 million in the fourth quarter.

Excluding transaction costs related to the proposed acquisition of Atwood, G&A expense is expected to decline by $2 million quarter-to-quarter primarily due to the timing of certain annual incentive-based grants. We anticipate that interest expense will decline to approximately $48 million from $60 million in the second quarter, primarily due to increased capitalized interest as we prepare ENSCO DS-10 for its meeting [ph] contract.

We expect our third quarter tax provision will be approximately $19 million. As I mentioned on our prior conference call, we are likely to incur income tax expense in periods where we operate at a loss.

Please note that the third and fourth quarter guidance I've just reviewed is for Ensco only and does not include any impact for the proposed acquisition of Atwood. Turning now to a summary of our financial position, as of June 30, cash and short-term investments totaled $1.9 billion.

We also have a fully available $2.25 billion revolving credit facility available through September 2019. The $1.13 billion of which is available from September 2019 to September 2020.

In addition to this liquidity, we have $3.3 billion of contracted revenue backlog in line with our backlog at the end of the previous quarter. Year-to-date we've added more than $600 million to our backlog or approximately 20% of rig years awarded globally during this time period.

We believe that we will continue to see a flight-to-quality as customers award more work to offshore drillers with established operational and safety track records and strong balance sheets. Additionally, we believe that our recent contract wins position us well for follow-on opportunities, bridging our rig fleet to better market conditions.

During the second quarter, we opportunistically repurchased approximately $190 million of debt maturing between 2019 and 2021 on the open market and now have less than $1 billion in maturities before 2024. Moving to our capital expenditure outlook, we expect total CapEx for the second half of 2017 to be approximately $300 million, an inclusive of $210 million of new rig construction costs, primarily due to the recently announced contract for ENSCO DS-10.

Remaining capital expenditures to the rig are expected to total approximately $190 million, inclusive of $75 million final milestone payment to the shipyard, $35 million of capitalized interest, a second seven-ram blowout preventer and other customer requested upgrades, mobilization from the shipyard to Nigeria, plus customer acceptance testing upon arrival in Nigeria. We expect to incur $170 million of these costs in the second half of 2017 with the remaining 420 million occurring in the first quarter of 2018.

In addition to new reconstruction, CapEx for rig enhancements and minor upgrades is expected to total $90 million for the remainder of 2017. This includes $10 million of remaining capital for the reactivation of ENSCO DS-4.

The proactive purchase of a modular MPD package that positions us for upcoming contract opportunities, as well as other customer specific upgrades. Our capital expenditure outlook for the balance of the year may increase if we are successful in contracting additional rigs.

These targeted investments better position our fleet to meet future customer demand as we expect that active high specification rigs owned by established offshore drillers with enhanced operational and safety systems and financial strength will be the most competitive in winning future contracts even if the market remains tight. Finally, I'll provide some further detail on our planned acquisition of Atwood.

As mentioned in our press release, integration planning is well underway and we expect the transaction to close during the third quarter. We estimate that we will achieve $45 million of expense synergies in 2018 and run rate synergy of $65 million on an annual basis beginning in 2019.

We expect to achieve these synergies primarily through the consolidation of offices and shore-based head count. Onshore support costs totaled approximately $85 million on an annual basis including $50 million of G&A expense and another $35 million of costs classified as contract drilling expense.

Certain corporate support costs including engineering, supply chain, and asset management, are generally charged to contract drilling expense along with onshore support costs incurred in field offices that directly support operations. Since we expect to support our combined fleet using Ensco's existing support structure, we believe that $65 million of synergies is an achievable target and we'll continue refining our estimates as integration planning progresses.

There may be other operational and fleet management synergies that lead to improved utilization in the future, but these benefits have not been included in our synergy targets. As of March 31, Atwood's balance sheet included more than $400 million of cash on hand and outstanding revolver balance of $850 million and approximately $450 million of 2020 senior notes.

We expect to repay the outstanding balance on the revolver. Using a portion of Ensco's cash upon closing, we also anticipate that the 2020 senior notes, which have a put option on change of control will be retired.

Adjusting for these debt payments, Ensco's pro forma liquidity will be more than $3.2 billion including $1 billion of cash with less than $1 billion of debt maturing before 2024. Following the delivery of ENSCO DS-10, remaining pro forma new build capital commitments to the shipyard, excluding customer acceptance testing, mobilization, and capitalized interest costs, will be approximately $495 million dollars.

We would also maintain the option to extend final payments totaling $250 million for two-hour drill ship to late 2022. In closing, our financial strategy entering the downturn was focused on extending our runway, reducing debt, managing cash outlays and increasing our liquidity.

We successfully strengthened our balance sheet and improved our competitive positioning to prepare the company for a protracted recovering the offshore sector. Our financial strength has given us the flexibility to evaluate a variety of investment opportunities.

We have leveraged this position to pursue the acquisition of Atwood and make targeted investments in our assets, technology, systems, and processes that will significantly enhance our fleet, so that we can better meet customers' drilling requirements in the future. I'd like to also note that when evaluating the acquisition of Atwood, we'll consider the combination through scenarios that range from a more rapidly rebounding environment to an even longer and protracted recovery than we are expecting.

Irrespective of the market environment, we believe the acquisition is accretive on a discounted cash flow basis, inclusive of synergies expected to create more than $400 million of present value at a 10% discount rate. While we pursue these countercyclical investments, we are maintaining strong liquidity and manageable debt maturities, giving us the financial wherewithal to bridge the company due to better market conditions.

We'll preserve our financial flexibility through prudent liquidity and liability management as we navigate industry cyclicality with a focus on delivering the highest return to our shareholders. Now, I'll turn the call back over to Nick.

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

Yes. Thank you and good morning gentlemen.

Good morning, Greg.

Carl, could you talk a little bit about the reactivation of DS-4 and sort of how that opportunity came to happen. Really I'm just trying to understand, I mean, this was a preservation stacked rig.

I think one of the big themes in the sector has been the ability of hot rigs to win work as opposed to stacked rigs and I'm just trying to understand what enabled the DS-4 to be reactivated and really win that work, which is a nice solid two-year contract.

Okay, alright. Well, first of all, at the high level, Greg, I think what we should view is the positioning we've done of some of our rigs, DS-4 included and DS-10 has been because we've decided that we want to have the right rigs working in the right places with the right clients and that positions us well for what we expect to be an increasing level of activities we go forward over the next couple of years.

And as we said, going back a couple of quarters we will be prepared to invest, to put rigs into key markets, but once we were there we expected them to be cash generative and that is true of the contracts that we announced for the drillships recently. Now, we expect to be at score, I think we also came to the idea that on the balanced portfolio basis we actually would like DS-4 to be out on active because it's a very competitive rig and that we would keep them DS-3 and DS-5 in preservation stat.

So, a little bit more on that award, it was a competitive award, it wasn't directly negotiated and DS-4 did win the work against all rigs. And, I think when we decided we would start rigs, it's certainly preservation static agreement.

We said at that time that we felt, to be competitive bringing the amount against to the rigs and I think we have proven that. And, part of that was we took up for investments to make sure that the rigs were very well preserved against a series of very carefully planned procedures, that we had already a detailed procedure for bringing them back that we were able to demonstrate to the client.

And, that we were able to put the rig back to work as it would be and to the level that it would have been within warm stack within the time duration. So, I think we are very pleased to have that rig back working and as we said once it gets to Nigeria, we expect it to be generating cash for the business once it's there.

Now, what we are doing of course is, we are making some additional investments in the rig, but these are enhancements that think will make the rig competitive and make it the most capable rigs in the market going forward over the multiple years.

Okay, great. And then just - you touched on paper remarks about the depending acquisition of Atwood, I noticed in the 10-Q this morning about some potential I guess law suits against Atwood and regarding the merger.

Does that have any impact in the timing of the potential closing of the deal? I am just trying to understand, I see these things and I am trying to understand, is that sort of normal course of any acquire, any M&A transaction, or is that - I am just trying to understand.

And those are against Atwood not Ensco, correct?

Yes, so Greg these are within the normal scope and expectation of M&A activity. There is nothing unusual there and nothing that we think is going to delay the process.

And they are all from a - Atwood primarily, one of them those [indiscernible] was a counter party as part of that deal, partially because the way the deal is structurally done. But, nothing that we expect is going to cause any problems on the closing of the deal.

Okay, perfect. Thank you very much gentlemen.

Thanks, Greg.

Hi, thank you. Congratulations on the recent contract wins, I wanted to ask you Carl or Carey if you secured a way in, how you think about generating a return for the DS-10, given that you had to spend close to $200 million, from here forward to complete the rig.

And whether the one year plus five year of customer options provide the basis for getting it and accept for return on approximate 200 million bucks, given where rates are today.

Ian, maybe, I'll take it first and see if Carey wants to add anything. First of all, we have to bear in mind that we have very long lived assets and so that sort of return will not load in the return on the first year's contract, quite obviously.

We think that the investments we've made there will make a good return for us for the investment and for the shareholders over the duration - over the next two years and over the life of the asset. The options on that contract in the out years of price are tiered envelope and I think that if the options were accept –taken them we would feel relatively pleased on the placement of that rig and the rates that we would get for it.

So, we are not loading everything on the first term contract or say a year or two year option extension. [indiscernible]

Sorry go ahead Carey.

Ian, just one thing to add just to clarify the CapEx remaining on the DS-10 is actually 190 million - the 210 million number I mentioned in the prepared remarks, only a portion of that was the DS-10. And of the 190 million, 35 of that is capitalized interest, so really its interest would be paying anyway.

So it's not all incremental cash spend, so just wanted to clarify.

And, also additionally a lot of those expenses we would have had whenever we brought the rig out. So, we are going to quickly capitalize - I'm sorry, the customer acceptance testing mobilization is other things too.

Understand thanks. I was really mainly curious if what the mechanisms are of the customer options, if they are variable or an oil price turning at the market conditions or if they are just sort of fixed with some price escalation?

We are not going into the exact details of it. They are not variable on oil, they step up overtime.

Okay, and then, the lastly for me Carl. You mentioned that depending closing of the deal, that's filling up Atwood's fleet would be job one and that you would be examining more retirements within the legacy Ensco fleet, could you describe which rigs that would - could fall into that bucket?

No, we are not going to go into it specifically at this point Ian. One is because we are finding that plan secondly similar to rigs working on contract with clients.

But you should expect is as we go forward post closing that will give more insight into that. But broadly speaking, I think you can fully expect us to retire a few more of our older jackups as we have done recently with ENSCO-52.

One of the real positives of the Atwood transaction is that we bring in five highly capable younger jackups that fit into real sweet spots that we're seeing for marketing at the moment as the jackup market begins to recover and we will take that opportunity to refresh and renew our jackups lead and probably cast a few more of the older ones. A lot of these rigs are, some of them are most aged ones, very heavily written down or very low NBV anyway, things that we wrote down three years ago, so that becomes a relatively straight forward decision.

And we will take a look at accepting some of the plugs as well, once we close and we work through this a little bit more. So, we'll give you more news when we refine the plan.

Understood, thank you.

Thank you. Good morning guys.

Jon maybe the first one for you here, on the 4Q cost guide, the 275 to 280, can you just quantify how much reactivation is still left in there, incremental cost that isn't standard operating cost.

Yeah, there is a bit in there, just to provide some broad guidance because there is still some variability that could go into it, but in the mid-single digits is probably where I guide you.

Okay. That's perfect.

And then the next one, Carey you talked about kind of the growing tenders year-over-year still, do you get this as function of the operators or more or less, having to start moving forward projects to kind of meet production targets, 2019, 2020 or is this more of a function of just the offshore cost structure has come down as much that they might as well move forward with all these assets.

Blake, I think it's a good to follow that offshore costs have come down, the growing cost are being reengineered and brought down. The fact that opportunities are there for infill type work, is creating some demand and the fact that a number of projects had not been sanctioned in the past two years and at some point the oil companies have to start drilling again.

This is causing operators to start making plans to drill and coming out with tenders.

Yeah Blake, maybe I can take the opportunity to just give a broader picture about the market on the back of that. So, first thing to say is that, despite the swing in the oil price dip down and then a little bit of recovery recently, we haven't actually seen any major interruptions to the tendering activity in Q1 and Q2, now in many cases, that's also a lot of these things already in process, but we just come up with five considering the state in view of all of our opportunities due to the market conditions here.

And, I think probably somewhat surprising to know there is actually its normal to withdraw the contract, despite to be sit down like in the old price. Now, it's coming up on old basis, we said in our pre-compared statements, we don't think that this is leading to a sort of hospice recovery, by any means.

But, I think truly speaking, we feel now that the Shallow water has bottomed and it is recovers as far as activities concerned. We think that the next area that we expect to see pickup now is in the Deepwater around existing infrastructure.

So, this is type of neglects and preventions for new some sea tiebacks. I think that we are feeling courage by what we are seeing in the market is reflected by some of the common treatments by the big major, service companies like [indiscernible].

I will be thinking about the next area that will pick up a bit. And, as far as the deep water is concerned and Floaters segment as a whole, we don't think it will change from a quarter to a go, despite the increase in the tenders.

We fixed a number of rigs growing on contract this year, is going to be, when you are going to see further global utilization full off in the tender mark in the third closed segment. As we look '18 and '19, we are seeing a number of new opportunities come and interestingly in the last few months, we have seen some new shore cum work come to the table, that didn't exist and it wasn't on our radar at all, three months ago.

A lot of this seems to be price response to our customers, you know, to contact people to re-express all the spread of services at great [ph] and not to be sustainable right on time, and its driving some less extreme demand, and, we are now seeing several new tenders for activity in '18 owing to deep shore programs around existing infrastructure and the in the deep well services. So, that's the general market condition and it's because of that we do feel we are in the forwarding point of cycle, at different basis and different segments, and, it's why we believe that it's time to making some investments in the future.

That's great. Thank you guys, I appreciate it.

Hi, good morning. Carl I just wanted to take up on your last point there.

Yes, just kind of confirm it sounds like despite the old price sans weakness over the last call three months, it hasn't really been a change in the havoc for opportunities and may be in the pre-tender phase. And, I guess has there been a difference at all between the Jackups customers, Shallow water customers verses the Deep water customers, any reaction to that.

Haithum, not really, no maybe it's a bit early. Especially in the deep water, people might take decision processes quite long time in advance.

So you don't see switch on and switch offs so quickly. But, I think completely from what we've seen I don't think we could make a comment that we've seen it full off.

I think in the Jackups, Shallowwater segment, we're seeing now, quite a lot of customers start pushing projects through for FID and beginning to look at increased activity level and partially of adapting to the new reality of both oil prices and cost inputs. And we're seeing a lot of simplification of projects, a lot of streamlining and a lot of efficiency build in there.

And accordingly, I think that oil prices within the range, they been still support the continued investment in the Shallowwater. In respect to the Deep water, I think a lot more will rest on the sentiment going into the 2018 planning cycle for all of the customers as we get two to three months down the line.

Then, the [indiscernible] that we sold over the last quarter, is affecting our outlook for '18 and '19. So, I think that we would probably have more comments; more feel of that within a quarter or so, once we understand, what were the essentials from some of the customers is as far as the planning for '18 is concerned.

Now, if it does. And, in respect with DS-4, in a re-activation and then we can't' deliver it and anyway can you give a reason why the 3 and the 5 were not chosen into the four that kind of went ahead.

And, I am curious into the 15 million that is the capitalize, what is the nature of the upgrades were, and whether or not they are a part of, you know many of us who consider that part of the reactivation, but still, so bid on why the four and not the three and five?

Yeah, hi, this is Carey. The tender will require to do the activity rig and DS-4 is still activity worse three and five.

So, that is one of the reasons that drove us to DS-4. As for the capital upgrades, some of it is trusted to specific requirements well light connectors, different frames, cloth clipping frames and so on.

Step related to the completion process, and then there was some additional tubular's that were required to double contracts specific.

Yeah, and, that's exactly the way we deal this, there are very much three buckets you can costed for re-activation of a rig. The first one is, how much does it really cost to basically be preserved and actually that's relatively small, it got to be like in one episode in the order about $6 million.

Then there is effectively catch up on surveys, maintenance and refurbishment of equipment, which is actually the biggest part. I wish most of those costs would have been incurred if you begin involved, and then the third bucket which, is the one that you are talking to, which is, are there any further enhancements which are not necessarily required to the activated rigs but either enhancements for the rig, for the future or required for the contract all the basins going through.

And, I think in this particular case, we are prepared to make those investments, cause additional investments, because, we think it adds value to the rig in the long term and we do believe, one of the reasons, we take these contracts with these clients in that areas, because we have relatively good visibility to ongoing work there beyond the contract. So, we really think that there is a very good chance that we will continue to work, within neither Nigeria that was set with the market on that type of targets.

We are actually declining over the contract, you know in places in the world at a shorter duration, where the client is requesting. What we think is actually completely irrespective, or quite ridiculous upgrades or enhancements to the rig that they expect, the contractor to make for the short and long term contract.

And, we don't think that the investments there warranted would be covered over the life of the rig, because they are often very, very specific to that client who's holding that contract. And, in that case we are actually no bidding some of these contracts and we have actually stepped up in a number of low bids we've done over the quarter or two.

So, we are being very specific about which contract we will bid into, and will invest for, and which ones we won't.

Alright I appreciate that call, thanks. And this one last quick one is, did I hear correctly that DS-7, there's potential follow on work in the first quarter '18 for that as well.

We are anticipating some worth, yes. And, it's also why, we are actually quite pleased to have the rig go back to work for existing customers, who go from their homes successfully active status.

Got it. Perfect.

Thank you.

Hi, good morning guys. I am just sticking to the DS-4 commentary, in terms of the re-activation cost; you mentioned 6 million for deepwave drilling, if we go on further for say, it's called cold stack for two years and beyond, do you think we would still be able to hold that 35 million as the deep wave drilling goes up, but the reminder stays very calm.

Yeah. Probably - this is Carey.

The $25 million to $35 million estimate we gave you is good for a five-year timeframe. There is a point when you don't have to do any more maintenance.

You are not consuming hours on equipment or increasing the amount of overhauls you have to do and it kind of flattens out. So, we've estimated those numbers based on a five-year timeframe.

Okay. Perfect.

And then in terms of the contract on that, I guess, you guys mentioned that the two-year contract was something that was important to you in terms of the term. I guess what kind of hall weight [ph] on term would have been acceptable to go through the reactivation process?

Do you mean the duration on the term?

Correct. I guess, would you guys have done it for one year term along with the potential for follow-on work behind that?

Yeah. I think the simple answer to that probably is yes if it was the right client right basin with follow-on work, which is sort of what we've said.

And I think our view through the likelihood of follow-on work would be it's a major decision in doing this. So, we might do it for one location, one client, but not another.

Okay. Perfect.

Thank you, guys.

Hello. I just wanted to come back to the deal.

You mentioned that you would run a range of scenarios to test the thesis around the deal and you mentioned the downside scenario of no pricing power emerging in the rig market. Can you give some sense and put that in a more macro context as to what kind of oil price environment would you be running at for that sort of downside scenario to still make sense?

Sure. I'll take a stab at that.

In just generally speaking, when we evaluate all investment opportunities and not just Atwood, we do screen things against many scenarios. And so, some more rapidly recovering and some lower for longer if you will.

And so, the ones that were in the merger proxy were the two that we relied on for there, but internally we look at other various scenarios that we evaluate just from a management standpoint. And I can tell you from a lower for longer scenario, we do test fairly various scenarios.

And so, I don't pin an exact oil price on there. I think as the lower oil price would translate into recovery, yeah, I think the way we would look at it is lower utilization for longer and lower day rates for longer and that could be loosely coupled to oil price.

But you can call it more bearish and the forward strip is today and the recovery that - if you look in the proxy the case we showed was recovery, various recovery scenarios for jack-ups and floaters, so we also screen it against scenarios that the recovery is further up than those presented.

I think the thing is it's probably a good point to make a broader statement, which is in some ways it lessens the specific oil price in the sense that what we are seeing now is our clients in the general market is adapting to the new reality offshore of lower oil price and we've touched on this before about how costs would come down for a lot of offshore developments. And what we're seeing is a lot of developments that are coming to the table, ones which at the top of the queue and they are optimized to the current oil prices.

The issue today, the thing - so we do feel we're in a broad market. We actually think activity is coming up in several areas, area that constrains us and maybe drives more of a down case is that we see a structural overhang for longer on the rigs and we see suppressed pricing and we don't see the return of pricing power for longer.

Yeah, yeah, that makes sense. But just to try and clarify that a little bit more, I mean, if that downside scenario still assuming that we sort of continue where we are, but, for example, deep water economics are able to proceed at a sustained lower cost base.

Sure. And again it's a bit loosely coupled.

I think obviously we have some fairly detailed models that we use basin by basin and from an activity level standpoint and that activity level turns on and turns off based on oil prices. And then we use that to extrapolate rig demand and then we look at global rig demand supply against that.

And ultimately then we have some judgments on what that environment would look like from a utilization standpoint and how that translates into day rates. And so, to broadly answer, yes, we do look at that.

I can't tell you it's as precise as you might - I think you might be characterizing because there are some judgments involved in the process, but we do look at it and we do look at scenarios where it translates into more downside than our current day rates reflecting more downside than current utilization that we're experiencing today.

And I'll use the opportunity to make a little bullet point, which is that we've looked at more aggressive recoveries and slower recoveries than we currently estimate at the moment. But we're not naive in expecting that to be a rapid recovery here to make the Atwood acquisition a success.

Our belief is that the market will gradually recover overtime. We think that the level of investment now three years and possibly going into four years of quite material pullback investment outside of OPEC and onshore US is going to lead to a supply issue and the longer that goes on the more - the great the chance for dislocation on the supply side.

And thus there will be over time recovering investment in offshore and the offshore is going to be viable and especially because the cost base - breakeven cost structure is coming down. But the future is not going to look like it did in the past and we don't assume that all of the companies that exist in our sector today are going to exist and all the rigs that are working today have been working over the past few years.

They are going to work in the future. And therefore - and there is going to be a new reality and we're going to be asked by clients to play a greater role in helping the drilling efficiencies and bringing down costs and we're going to be asked to be - to probably take on some new contracting models, including potentially the integration of other services around our rigs.

And what we need to do as a management is prepare ourselves for that and make investments at this point in the cycle to be ready for it and that means having the highest quality fleet. It means investing in technology and innovation and it means investing in the ability to take different contract models and that's what we're doing at the moment.

And we work within a cyclical asset intensive business and you can argue that the drilling sector has tended to make investments at the wrong point in cycle peaks. If you're in that type of business, we need to be looking to make investments that counter cyclical into the bottom of the cycle and that takes some bravery and it takes some foresight because that's exactly when uncertainties and the greatest market sentiments that is lowest.

So, that's where we need to called in honors [ph] as the management team to make some decisions and make some investments. And it's in that context that you should view the acquisition of Atwood and our investment in our fleet.

The continued investment we're making in technology and innovation that we're going to be rolling out and putting on some of our rigs later this year and beginning of next year.

That's great. Really helpful context.

Thank you very much. I'll hand it back.

All right. Thanks.

Okay. Thank you, Chad.

And thank you to everyone for your participation on today's call. We look forward to speaking with you again when we report our third quarter 2017 results.

Have a great day.