Sean Patrick O’Neill - Vice President, Investor Relations and Communications Carl Trowell - President and Chief Executive Officer Carey Lowe - Executive Vice President and Chief Operating Officer Jon Baksht - Senior Vice President and Chief Financial Officer.

Gregory Lewis - Credit Suisse Praveen Narra - Raymond James & Associates, Inc. Haithum Nokta - Clarksons Platou Securities.

Good day and welcome to welcome to Ensco Plc’s Second Quarter 2016 Financial Results Conference Call. All participants will be in listen-only mode. [Operator Instructions] After today’s presentation, there will be an opportunity to ask questions. [Operator Instructions] Please note this event is being recorded. I will now turn the conference over to Mr.

Sean O’Neill, Vice President of Investor Relations, who will moderate the call. Please go ahead, sir..

Welcome, everyone, to Ensco’s second quarter 2016 conference call. With me today are Carl Trowell, CEO; Carey Lowe, our Chief Operating Officer; Jon Baksht, CFO; as well as other members of our executive management team. We issued our earnings release which is available on our website at enscoplc.com.

Any comments we make about expectations are forward-looking statements and are subject to risks and uncertainties. Many factors could cause actual results to differ materially. Please refer to our earnings release and SEC filings on our website that define forward-looking statements, 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, so please see our earnings release on our website for added information. As a reminder, we issued our most recent fleet status report on July 18.

An updated investor presentation is also available on our website. Now, I’ll turn the call over to Carl Trowell, CEO and President..

Thanks, Sean, and good morning, everyone. During the second quarter we took decisive steps to further enhance our financial position. We completed a successful tender the reduced debt by $861 million, at a 28% discount. We purchased another $79 million of senior notes on the open market at a 21% discount.

And we raised net proceeds $586 million through a secondary equity offering. As a result we increased liquidity to more $4 billion at quarter end, composed of $1.8 billion of cash and short-term investments, and a fully available $2.25 billion revolving credit facility.

Additionally, we improved our net debt to capital ratio to 28% from 40% at the end of the first quarter, better positioning Ensco to weather the current downturn and capitalize on opportunities in a market recovery.

S&P’s global rating service recently acknowledged our positive capital management and cost saving actions in the face of challenging market conditions in the off-shore drilling sector. While we received a one notch downgrade, given their more negative industry outlook, we maintained our investment grade rating with S&P.

As detailed in our press release, earnings from continuing operations with $2.04 per share, that included gains on debt repurchases $261 million and early termination contract settlements of $205 million. Excluding these settlements revenue was better than expected for the second quarter.

Results benefited from another strong performance of our offshore crews, with record operational utilization of 99% and new year-to-date safety record. Disciplined expense management also supported our financial results, with contract drilling and general and administrative expenses in line with our outlook.

As we remain on track to achieve our targeted run-rate, we continue to pursue further efficiencies and cost savings across our operations and support structure.

While some customers have elected to early terminate contracts, we have agreed to blend and extend agreements with others that added to our revenue backlog, as noted in our most recent fleet status report and as Carey will discuss in a moment. Turning now to fleet management, we expect to take delivery of ENSCO 140 and ENSCO 141 later this year.

Our high-grading also included the scrapping of seven more rigs during the quarter, five floaters and two jackups, bringing total rig sales to 28 since 2010, compared to 16 rig deliveries over the same period.

Following the rig sales completed during the second quarter, we now have a total of seven additional rigs that we plan to sell for scrap or permanently retire; two rigs in discontinued operations plus ENSCO 56, ENSCO 81 and 82, ENSCO 86, and ENSCO 99.

As we stated previously, rig scrapping will be an important factor in helping to rebalance the rig market. We believe rig scrapping industry-wide will continue over the remainder of 2016 and into 2017.

Fleet management also includes the stacking of un-contracted rigs to reduce costs, while preserving the rig for timely and efficient reactivation when market conditions improve. To this end, we have preservation stacked several rigs, and developed detailed reactivation plans and budgets, that Carey will speak to later in the call.

We continue to take steps that we believe are prudent and necessary to persevere through the current downturn until market conditions improve. We remain optimistic about the medium- to long-term prospects for our sector and are conducting early planning for the eventual upturn in the market.

While we have recently seen customers early terminate rig contracts, we’ve also seen some incremental positive developments, including customers approving new drilling programs to put rigs back to work such as ENSCO DS-6, which is expected to return operations next month in Egypt.

Other major E&P customers have indicated that breakeven economics for deepwater projects have improved through reengineering and cost deflation. And we have seen some positive commentary on certain programs which were previously delayed and may be getting closer to final investment decision approval in regions like the U.S.

Gulf of Mexico, the Mediterranean, and offshore Africa. We are also seeing some requests for information, a precursor to future drilling programs as customers evaluate rig availability and technical information for projects in the coming years.

We believe that these are early signs that the unprecedented pullback in customer spending is having an impact on customers’ production as they evaluate their portfolios longer-term. On the rig supply-side we’ve continued to see rigs scrapped and retired, which will help to improve the supply-demand balance of offshore rigs.

However, as I’ve stated previously, we expect that utilization in day rates will continue to move lower over the second-half of 2016, as more rigs roll off contract without follow-on work.

As we manage through the downturn, we will continue to be proactive in terms of fleet restructuring, capital and expense management, and selectively investing in opportunities that will improve rig efficiency, and help to increase our leadership and competitive advantages. Now, I’ll turn the call over to Carey..

the quayside power source to dehumidify quay equipment and prevent corrosion of the hull; the removal of certain equipment for temperature control storage; and periodic inspection and maintenance of large equipment by Ensco personnel.

As we previously disclosed for our sixth gen 8500 series rigs, the preservation stacking process requires approximately $5 million of upfront cost.

In addition to three of our preservation stacked 8500 series semis, during the second quarter we decided to preservation stack two of our sixth gen drill-ships, ENSCO DS-4 and DS-5, which will cost approximate $5 million each. Up to this point, we have not preservation stacked the jackup.

But for comparison a high-stacked jackup will be approximately $1 million. We expect that the reactivation benefits will more than offset these costs. While stacked, daily operating expenses reduced to a possibly $15,000 a day per drill-ship, less than $10,000 a day for an 8500 series rigs, and less than $5,000 a day for a jackup.

These are meaningful savings compared to the cost to keep these rigs hot-stacked or warm-stacked. In terms of reactivation, each situation will be fact-specific and our operations and asset management teams have detail plans for every rig.

On average, we anticipate the cost to reactivate each preservation-stacked DP floater will be between $25 million and $35 million, and approximately $5 million for newer high-stacked jackups that may be preservation stacked.

Some of these costs are for deferred maintenance that would be incurred during the intervening period if we kept these rigs active and marketed.

Since five of our six preservation-stacked floaters are less than eight years of age, the cost to recertify these rigs upon reactivation are projected to be at the low-end of the spectrum relative to older rigs.

When market conditions improve to a level that can support incremental rig supply, we expect rig reactivation will take between 90 and 120 days, inclusive of time for systems integration testing, endurance testing, plus other rigorous testing that is typically done as part of a new-build rigs commissioning process.

This extensive testing will enable our rigs to deliver high levels of uptime performance upon reactivation. By way of contrast, Ensco has sold the vast majority of its older less capable un-contracted floaters; whereas some competitors have instead opted to stack a large number of older floaters, which may take longer and cost more to reactivate.

Now, I’ll turn the call over to, Jon..

Thanks, Carey. Today I’ll cover our second quarter financial results, our outlook for the third quarter, and our recent capital management actions and resulting financial position. Starting with the second quarter results versus prior year, second quarter 2016 earnings per share from continuing operations were $2.04, compared to $1.15 a year ago.

As detailed in our press release, several items influenced these comparisons, including a $261 million gain on the repurchase of senior notes at a discount and $205 million of early contract termination settlements for ENSCO DS-9 and ENSCO 8503 during second quarter 2016. Year ago results were impacted by a $7 million loss to retire debt.

Total second quarter revenue was $910 million versus $1.06 billion last year. The early contract termination settlements I just mentioned, benefited second quarter revenue. However, excluding the settlements revenue is still above our initial expectations, due to record fleet line operational utilization.

In the Floaters segment, excluding these settlements, revenue declined to $431 million, primarily due to a year-over-year decline in utilization to 57% from 76% last year. And the average day rate declined to $360,000 from $417,000 last year.

Operational utilization for the floater segment, which adjusts for un-contracted days and planned downtime, was a record 99%, up from 92% a year ago. In the Jackup segment revenue was $251 million compared to $384 million last year, as reported utilization declined to 63% from 77% in 2015.

And the average day rate declined to $112,000 from $140,000 a year ago. Operational utilization for the total jackup fleet was also 99%, up from 98% last year. Total contract drilling expenses declined of $350 million at the lower-end of the outlook we provided on our last conference call.

Year over year, we reduced contract drilling expense by 30% from $503 million in second quarter 2015 due to fewer rig operating days and proactive expense management. Depreciation expense declined $112 million, largely in line with our expectation.

General and administrative expense of $27 million was in line with our outlook, and down from $30 million a year ago. As detailed in our earnings release, other income was $210 million, due a $261 million gain on the purchase of $940 million of senior notes at an average discount of approximately 27%.

Excluding this gain as well as a $7 million loss to retire a debt a year ago, other expense was $51 million compared $48 million last year, due to lower capitalized interest this quarter, partially offset by lower interest expense following our recent debt repurchases. The effective tax rate was approximately 6% for the second quarter.

Excluding discrete items such as debt repurchases and early contract termination settlements, the effective tax rate was approximately 20%, better than our outlook due to additional tax efficiencies achieved through recent restructuring. Now, let’s compare our second quarter 2016 to first quarter 2016 sequentially.

Starting with revenue, excluding contract termination settlements, revenue declined 13%, primarily due to five floaters and jackups completing contracts, offset by one floater commencing a new contract. As a result utilization declined to 61% from 65%, and average day rates declined to $195,000 from $208,000 last quarter.

Total contract drilling expense decline $14 million sequentially from the first quarter. Second quarter contract drilling expense included the following items, $9 million to terminate a contractor relationship, which we expect to recoup to lower cost going forward. $2 million of mobilization costs to move ENSCO DS-4 and DS-5 from the U.S.

Gulf to Tenerife plus $6 million of costs to larger complete preservation stacking the rigs, and $5 million contract preparation costs for ENSCO DS-6, including mobilizing the rate to Egypt.

Adjusted for these items contract drilling expense decline $36 million or approximately 10% compared to the prior quarter, primarily due to lower operating expenses to rigs about contracts. Looking at other expenses, depreciation was flat quarter-over-quarter. G&A expense decreased $4 million, primarily due to the timing of annual compensation.

Interest expense declined $11 million due to deleveraging from the tender and open market debt repurchases that we’re completing during the second quarter. Excluding discrete items, our effective tax rate declined due to our restructuring. Moving to our outlook for third quarter 2016.

Total revenues are expected to decline on a sequential quarter basis due to an estimated 5 to 6 percentage point decline in average day rates from second quarter levels of $195,000, and lower reported utilization for the fleet, which is expected to be in the low 50% range.

Third quarter contract drilling expense is expected to decline to $295mil to $300 million due to fewer rig operating days, reduced costs recently preservation stack floaters and the removal of scrap rigs from our fleet. Depreciation expense is expected to be in line with second quarter level.

We expect third quarter G&A expense to decline to $25 million. Interest expense, net of capitalized interest is estimated to be $56 million during the third quarter. We expect our effective tax rate percentage to be in the high teens. Note that our recent equity offering will impact our earnings per share calculation going forward.

Weighted average shares outstanding for the third quarter are expected to be approximately $299 million for the purposes of calculating earnings per share.

Now will cover our capital management actions and our resulting financial position, as a result of raising $586 million to an equity offering, reducing net debt by $255 million by repurchasing $940 million in debt at a discount and strong operational performance. We have increased our cash and short-term investments to $1.8 billion.

Our net debt capital ratio has declined to 28% as of June 30, a significant improvement over net debt capital ratio of 40% at the end of the first quarter. In addition to cash and short-term investment on the balance sheet, we have a fully available $2.25 billion revolving credit facility that matures in 2019.

The total liquidity of more than $4 billion. As a reminder, we have no debt maturities until 2019, and only 2 billion of maturities over the next seven years plus $4.1 billion of revenue backlog. While Moody’s downgraded the offshore drillers to below investment grade earlier this year.

Our credit rating continued to be among the highest of the major offshore drillers and following the recent S&P downgrade we remain investment-grade rated with S&P at BBB minus. Moving to our capital expenditure outlook, total remaining newbuild CapEx is approximately $725 million.

Forecasted CapEx for the rest of 2016 is $190 million, including final payments to the shipyard of $40 million for ENSCO 140 and $39 million for ENSCO 141. Today, we have paid approximately $157 million each for ENSCO 140 and 141. Our 2017, estimated CapEx budget is $450 million, of which $375 million is for newbuild.

Our estimated CapEx declined to $325 million in 2018, of which $225 million is the newbuild CapEx. We expect 2019 CapEx, to then decline significantly, since we have no remaining newbuild commitments.

In addition to newbuild the annual CapEx budgets, I just mentioned include re-enhancements and minor upgrades and improvements, which will continue to be carefully evaluated. In closing, we remain focused on proactively managing our financial position, and we are achieving our run rate savings target.

We will continue to evaluate our cost structure in line with market conditions through the cycle. We’ve taken several decisive actions over the past two years to significantly improve our capital management flexibility and liquidity.

And we will continue to evaluate opportunities in a disciplined matter with an eye towards improving our competitive positioning in both the short and long term. Now, I’ll turn the call back over to Sean..

Operator, you may now open up the lines for questions, please..

[Operator Instructions] our first question comes from Gregory Lewis of Credit Suisse. Please go ahead..

Yes. Hi, thank you and good morning..

Good morning Greg..

Carl, I had a question about the new build Jackups. I guess, there was a release from [Lan for all the] [ph] shipyard that I guess, the rig is going to be delayed. And they went further to say that they’re going to be going back to the OEM provider potentially, looking to recoup some damages.

Does that, is there anyway Ensco can pick any benefit from this rig maybe. I mean, it sounds like it’s only going to be delayed 30 days.

Is there anything the company can do to sort of take advantage of the fact that the rig might be a little bit late?.

Greg, so although they didn’t name rig in the press release, I think, regionally clear we have a rig there, which is slightly delayed in the shipyard. And since, it’s a live ongoing situation and discussion.

I don’t want to get into exactly the details of our contractual relationship there, but other than that, at the moment we think that the delay is solvable. It has pushed the rig outside its contractual window and there will be potentially some contractual elements that we can claim back depending on exactly when the rig is delivered.

Other than that, I don’t really want to go into and discuss the sensitivity, because there has been some ongoing contract negotiation..

Okay. Yes. Sure. Fair enough. And then just….

I think, the big thing there Greg is there is no big macro story around at the moment as we see it today, there may be some. There are the usual protections in the contract that you would do with the new builds including liquidate damages and things like that..

Okay. Sure. So maybe, a little bit on the margin. And then just, Carey, you went in, in great detail on the preservation stacking.

So just should we kind of view that - the 5005, is that similar to an 8500 in terms of the costs and the idle expense? Just because, I mean, you kind of laid out all the rigs that are older rigs that probably aren’t going to be around next cycle.

And I mean, is there something special about this rig, given the fact that it is 30 years old that it made sense to sort of preservation stack. Is this kind of broadly speaking, this is how you’re looking and thinking about this rig and say this will be our sort of mid water floater for the next cycle.

Just trying to get a little more understanding, why that rig was decided to be preservation stack in the cost associated?.

Greg, it’s Carl here. Let me just answer a little bit on the broad picture and then Carey can maybe be a bit more specific about the rig you ask. So I think, it’s important to understand when we’re talking about the preservation stacking where it fits in our overall fleet management.

When we have a rig that is becoming idle through the cycle, we are looking at a very balanced positioning. And so, some of the rigs, some of the older less capable rigs that we don’t believe have got a place in our core fleet going forward. What we are doing with that is we’ve been very judicial about spending any further money on those.

And in most cases, we are retiring them or selling them. So a good example here is the 6003 and the 6004 which came idle in Brazil. We have sold those scrap during the quarter. The rigs that we are preservation stacking, we are doing that, because we believe that will place in the market fleet going forward.

And a lot of those are generally are much younger fleet structure and we have every intention of bringing them back.

And we’re only removing them at the moment, because we believe market cannot sustain the global fleet and we want to reduce our market fleet to be able to manage cost and have the right structure fleet going forward over the next 12 months to 18 months or so.

And then, there is a third group which is we will keep some rigs warms and hot stacked ready to go to pick up spot work and incremental work. So if we preserve stacked rig, you can automatically assume that we believe, it’s got a place in the fleet going forward..

And Greg, I’ll just add that. ENSCO 5005 is a rig that underwent a significant shipyard light enhancements just two years ago and then it’s in great shape. It’s got a new BOP refurbished quarters and - we feel it, it plays a role in the mid-water market, which will be they are going forward.

When we talk to - when we gave you estimates for reactivation, they were more gear towards DP floaters. ENSCO 5005 being more, this is not have as much equipment and will be below that range that we gave you. A significantly below that range we gave you.

When we talk about the range of costs we gave you to reactivate rigs, I just give you some color on that. If we take $25 million is a reactivation costs, some $10 million to $12 million of that is deferred maintenance step would have been incurred that the rig was warm stack.

The remainder is incremental costs to remove preservation equipment, reactivate systems, testing and recertification. These estimates are good for five years and the idea the cost increases generally with time is not correct.

For example on our DP floaters, we remove the thrusters and we included the cost of overhauling the thrusters in the reactivation estimate. The work scope to complete a thruster overhaul does not increase your time.

In fact, some of the overhaul work will be less costly as the equipment is already removed and it’s an ideal location from the work scope. Our preservation stacked rigs were in good conditions prior to undergo in the preservation stacking process.

And three had five year service, so there are no significant additional costs like catch-up repair or steel piping replacement, which you would expect with an older early generation rig..

Okay, guys. That was very helpful. Thank you very much..

I think the important thing is the cost estimate that we give here is an all-in cost and includes catch-up on deferred maintenance that we have to do anyway here..

Our next question comes from Praveen Narra of Raymond James. Please go ahead..

Hey, good morning, guys..

Good morning..

Just a follow-up on that kind of line of thinking, guys, you want to make sure that - I’ve got this clarified. That specifically because you guys have been able to preserve - getting to a better preservation mode.

If you had to take a guess, kind of industry reactivations, would it fall, would it be higher than that, do you have a kind of an estimate for where that might lie?.

I don’t know whether we could be in a position to say what other people might do, because I think it’s very much driven by how much upfront work you do and what state the rig is in. We’ve come up with a quite detailed engineering plan of the preservation process, and then the re-mobilization process.

I think what is may be a point to make is that, if you’re talking about all the rigs, and some of the older generation floaters. It would be considerably more expensive to bring back, I guess.

You would not only have the - to basically bring out preservation, but you probably have quite significant amount of steel work, piping and bringing back in class to do. So I think, what is important with this is that it doesn’t change our view.

Well, first of all, it doesn’t change our own decision process about still scrapping some of our older rigs.

Same time, it doesn’t change our view, a significant number of the older floaters in the marketplace will be retired or scrap going forward, because the cost to stack and then bring back some of these older rigs, it’s going to be three, four, five times higher than the one we disclosed to you.

And in many cases, even when they come back they’re going to be uncompetitive in the market..

Right. I think, that makes a lot of sense. So I guess, moving to the European jackups, we got a lot of availability come due in kind of August 2016.

Could you give us a sense kind of what kind of a customer discussions and what your thought are as we move into that period?.

This is Carey. In the North Sea, we’re in discussions with customers about possible additional works. Some of which are extensions, some of it is actually new jobs. And this includes discussions surrounding our 120 series. Our 120 series rigs had performed very well and our customers are very happy with their performance.

And this helps quite a bit in re-contracting and extending contracts. And good performance we had overall is also evident in the North Sea, and that also helps us re-contracting the rigs..

So the North Sea is challenged at current oil prices, but it isn’t dead by any means. What we are seeing is quite a bit of activity around plug and abandonment intervention work and some short-term work.

So I think in the near-term the North Sea, Europe area is going to characterized by some spot and short-term contracts and extensions to exist in one..

Okay. That’s helpful. And then, I guess just one more follow-up if I could. In terms of the normal terms and conditions, I know before as we kind of softened in the market, we started to see offering less punitive cancellation provisions.

Have you seen any other changes in terms of changes to the terms and conditions in contracting, that either operators are asking for or the contractors are offering, inside Ensco or is it an industry question?.

Generally, I mean, the terms and conditions have certainly moved in the favor of the clients at this point, particularly around often contract term and the cancellation clauses.

What we haven’t seen certainly where we’ve drawn the line is on things which transfer excessive liabilities over to us and then we still have - hold some redlines in that area. But there’s been nothing I think materially changed. We have seen some customers want to discuss taking deferred payment against sometimes production or late payment terms.

And we view those on a case-by-case basis. But up until now we haven’t taken any unusual T&Cs..

Okay, that’s great color. Thank you very much..

[Operator Instructions] Our next question comes from of Haithum Nokta of Clarksons Platou Securities. Please go ahead..

Hi, good morning, guys..

Good morning..

Yes, just a follow-up on the reactivation cost that you mentioned.

Does that include survey related costs or how should we think about that in relation to the straight reactivation of a preservation stacked rig?.

Yes, that includes all of the survey cost required to reactivate a rig and to keep it in class..

Keep it in class, okay. Then my second question, I’m curious, you guys have a handful of rigs on long-term contracts that are probably considered older, for instance like the 5004 or the 5006 or the 6001 and 6002 in Brazil.

I’m curious if you guys had any discussions in the past about substituting in one of the DS-3, 4 or 5 in for those rigs, that way you could keep a newer rig contracted and working and hot for a longer period of time. I’m curious if you had those discussions and/or why not or what the operators might think of that type of arrangement..

So in a broad answer, we’re quite open to the swapping out of rigs. But actually the examples you gave then, if you look at the class and type of those rigs they can’t be swapped in for, say, a drill ship. So, 5000 and 5006 and MOD rigs working in very different environment that a DP floater could not work in.

And 6001 and 6002 are quite unique rigs working on infill work and step out work on the existing deals, and then not easily or efficiently swapped out for a drill ship for example. So the - whereas logically you might say that the actual specifics of those rigs and the environment they’re working in don’t them particularly swap out candidates..

Okay. I appreciate the color. Thank you..

And this concludes the question-and-answer session. I would now like to turn the conference back over to Sean O’Neill for any closing remarks..

Thank you, operator. And since there are no more question, just want to thank everybody for their participation on our call today. Have a great day..

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