Sean Patrick O'Neill - Ensco Plc Carl Trowell - Ensco Plc P. Carey Lowe - Ensco Plc Jonathan Baksht - Ensco Plc.

Gregory Lewis - Credit Suisse Securities (USA) LLC (Broker) Ian Macpherson - Simmons & Company International Robin E. Shoemaker - KeyBanc Capital Markets, Inc. Haithum Nokta - Clarksons Platou Securities, Inc. Vaibhav Vaishnav - Cowen & Co. LLC Eduardo B. Royes - Jefferies LLC Praveen Narra - Raymond James & Associates, Inc..

Good day, everyone, and welcome to the Ensco Plc's Third Quarter 2016 Financial Results Conference Call. All participants will be in listen-only mode. Please note this event is being recorded. I will now turn the call over to Mr. Sean O'Neill, Vice President of Investor Relations, who will moderate the call. Please go ahead, sir..

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

Any comments we make about expectations are forward-looking statements and are subject to risks and uncertainties. Many factors could cause actual results to differ materially.

Please refer to our earnings release and SEC filings on our website that define forward-looking statements and list risk factors and other events that could impact future results. Also, please note that the company undertakes no duty to update forward-looking statements. During this call, we will refer to GAAP and non-GAAP financial measures.

Please see our earnings release on our website for additional information. As a reminder, we issued our most recent fleet status report on October 13. An updated investor presentation is also available on our website. Now, let me turn the call over to Carl Trowell, CEO and President..

Thanks, Sean, and good morning, everyone. Third quarter results showed a continuation of our strong operational performance with new year-to-date records for rig uptime and safety that drove positive financial results relative to our prior outlook.

Earnings from continuing operations were $0.28 per share, influenced in part by a gain from debt repurchases and other factors, as outlined in our earnings release.

Operational results were better than expected with our revenue outperformance for the third quarter, driven by fleet-wide operational utilization of 99%, and contract drilling and G&A expense both in line with our prior outlook.

We have some positive contract wins during the quarter, particularly on the jackup side that Carey will discuss in greater detail. However, we recognized that market conditions continue to be very challenging for the offshore drilling sector given the decline in rig demand as customers restrict capital spending.

In response, we have taken further action to bolster our liquidity and balance sheet, reduce expenses and optimize the positioning of our fleet. First, in terms of capital management, we recently announced a one-year extension of a portion of our revolving credit facility into 2020, which remains undrawn.

We can borrow up to $2.25 billion under the revolver through September 2019, and up to $1.13 billion from September 2019 to September 2020. This revolver extension was an important step in increasing our liquidity and capital management flexibility as we manage through the market downturn.

In addition, we repurchased another $189 million of senior notes on the open market during the third quarter. Annual cash interest savings from these debt repurchases will be approximately $11 million beginning in fourth quarter 2016.

Along with these debt repurchases, we made the final payment for ENSCO 140 during the third quarter, while maintaining $1.8 billion of cash and short-term investments, and more than $4 billion of liquidity as of September 30.

On the expense management side, we took further steps during the third quarter to reduce and centralize our onshore workforce that will create further efficiencies. And we suspended a discretionary compensation plan that will generate additional savings in 2017.

In aggregate, annualized cost savings from these three actions, and others taken during the second quarter, total approximately $50 million. These cost reductions are being phased in as follows. Approximately $15 million of annualized savings were included in third quarter results and were incorporated into our prior guidance.

Another $15 million of annualized savings will begin in the fourth quarter and are included in the fourth quarter outlook that Jon will review. And finally, the remaining $20 million of annual cost savings are expected to begin in January 2017.

These savings are on top of expense savings related to fleet restructuring and offshore crew management that have benefited results to date as evidenced by a $200 million or approximately 40% reduction in combined contract drilling and G&A expense when comparing third quarter 2016 to third quarter 2014, when the current market downturn began.

In terms of our fleet management strategy, as noted in our most recent fleet status report, we've decided to preservation stack additional rigs to reduce cost in light of excess marketed supply within our fleet. Please note, however, we continue to maintain ready-to-work rigs by region and rig type for new contracting opportunities.

We believe this portfolio management approach balances marketing available rigs with expense management as we navigate the downturn. Another aspect of our fleet management strategy is removing older, less capable rigs from our fleet.

We recently moved two rigs, ENSCO 53 and ENSCO 94 to held for sale, as noted in our most recent fleet status report, since we expect to sell them in the near term for scrap value. As we've stated previously, rig scrapping will be an important factor in helping to rebalance rig supply, and we believe there is more scrapping to come in our sector.

On the demand side, improving breakeven economics will help to increase customer demand for offshore drilling rigs.

We have seen several recent announcements by major customers and suppliers across the offshore supply chain showing that breakeven economics for offshore project have improved significantly through re-engineering and improved project management.

This is a critical step in terms of increasing the overall competitiveness of offshore programs, and laying the ground work for a future improvement in market conditions once customers free up more capital spending for their offshore projects.

We have also seen positive indications that certain key offshore markets like Brazil may lessen restrictions that allow greater participation and investment by more E&P customers. In summary, while market conditions are difficult, I'm pleased with the steps we are taking as a company and as an industry.

Ensco's operational teams have achieved record uptime and safety results. That, in turn, have driven new contracting wins, especially on the jackup side. And we have reinforced our financial position in terms of liquidity, leverage and our debt maturity schedule, while also streamlining expenses and our organizational structure.

Offshore breakeven economics are improving, even more substantially than we anticipated. And rig supply pressures will be less than some market commentators predict as more rigs are scrapped and older, less capable rigs remain stacked for extended periods of time, making their return to the global fleet unlikely given significant reactivation costs.

In the meantime, we will continue to take proactive steps that we believe are prudent and necessary to persevere through the downturn, so that we are fully prepared to take advantage of the eventual upturn in the market. Now, I'll turn the call over to Carey..

Thanks, Carl. Our record operational performance is a result of employees' continued commitment to safe and efficient operations, and enhancements to our management systems that increase equipment reliability and knowledge sharing across our organization.

To provide some context, our year-to-date total recordable incident rate, a key safety statistic tracking the number of incidents relative to hours worked, has improved by more than 35% since 2013. Floater operational utilization is up 7 percentage points over the same time period.

While the market for offshore drilling remains challenging, this performance helped us win incremental work recently for several rigs. In the Middle East, we secured two jackup contracts for a total of eight years with Saudi Aramco. We extended ENSCO 88's contract for three years into 2019.

And together with ENSCO 84 and ENSCO 94, we're awarded five years of work. The Middle East remains the strongest market in terms of customer demand, and our operational track record positions us well for future opportunities in the region.

Moving to the Mediterranean, ENSCO DS-6 successfully returned to operations in early August at a full day rate of approximately $485,000. Our customer elected to fast track development of their major project offshore Egypt, which is expected to acquire drilling for approximately two years.

And we are gratified that they chose ENSCO DS-6 for this important work. Moving to the North Sea, we secured several short-term contracts and extensions for ENSCO 72, ENSCO 101, ENSCO 102 and ENSCO 120, increasing backlog by approximately $40 million.

The specific details for each contract can be found in the most recent fleet status report on our website. In the U.S. Gulf, we contracted ENSCO 8503 and ENSCO 8505 for short-term work with repeat customers.

Both rigs are for the versatility of a more DP configuration with high-spec, six-generation drilling equipment, which is a differentiating factor when marketing these rigs. In addition, we secured three short-term contracts for ENSCO 75, which is one of the most capable and reliable jackups in the region.

Moving to the Asia Pacific region, we've reached an agreement to extend ENSCO 5006 by 15 months, adding approximately $90 million of backlog. Strong operational performance by the rigs crew was an important factor in winning this extension.

ENSCO 67, also in the region, is currently undergoing contract preparations after winning a one-year contract for work offshore Indonesia. During the third quarter, we signed new contracts totaling more than 12-rig years, approximately 30% of the rig years contracted globally over this time period.

The majority of this new work went to jackups, supporting our view that shallow water activity will be the first to return given it's relatively lower cost and faster payback versus deepwater. In terms of our marketing strategy during the downturn, we continue to actively manage our fleet in line with market conditions.

Given limited contracting opportunities and existing uncontracted Ensco rig supply in the U.S. Gulf of Mexico, we decided to preservation stack ENSCO DS-3 and ENSCO 8506 in order to reduce operating expenses for these rigs.

While we are not currently marketing these rigs, our preservation stacking approach allows for a 90-day to 120-day reactivation schedule to meet higher levels of customer demand when market conditions improve. Our fleet management strategy also involves positioning our fleet for the future.

And to this end, we accepted delivery of ENSCO 140 during the third quarter and expect to take delivery of ENSCO 141 in the fourth quarter. Both jackups were built in the Middle East and will be warm-stacked in the shipyard with daily stacking costs covered by the shipyard for up to two years.

Turning now to global rig supply, which we cover in detail in our investor presentation on our website, offshore drillers have announced the retirement of 67 floaters since the beginning of the downturn. Looking at the active fleet, approximately 40 floaters are over 30 years of age and are either cold-stacked or idle without follow-on work.

Another 30 rigs in the same age category will see their contracts expire by the end of next year. In total, most of these 70 additional floaters are likely candidates for retirement, and are three times the number of newbuilds currently scheduled for delivery by the end of 2017, excluding 12 rigs in Brazil with questionable deliveries.

Similar to floaters, we expect more retirement of competitive jackups. Over the past two years, offshore drillers have announced the retirement of 23 competitive jackups in total. When we look at the active fleet, approximately 90 competitive jackups are over 30 years of age, and stacks are idle without follow-on work.

Another 55 rigs in the same age category have contracts expiring by the end of 2017. In total, these 145 jackups are candidates to be removed from the global fleet during the market downturn, and these jackups far exceed the approximately 90 newbuild jackups currently scheduled for delivery by year-end 2017.

Remember that the majority of newbuild jackups are being built by speculators and have seen their deliveries repeatedly delayed. Based on original delivery dates, more than 50 of these speculator rigs should have been delivered by now, highlighting the uncertainty of when and if these rigs will be delivered into the competitive market.

In closing, we are entering the third year of a downturn in the offshore drilling sector that began in mid 2014. While we expect the market to remain challenging in the near term, three factors will ultimately help to rebalance rig supply and demand, and we have seen positive trends on all three fronts.

First, commodity prices have recovered from the decade lows experienced during the first quarter. Second, industry-wide efforts to reduce offshore breakeven economics have resulted in a queue of offshore projects that are economic at current commodity price levels.

And based on customer commentary, we expect many of these programs will reach final investment decision approval when capital expenditures are freed up for incremental projects.

Additional efforts to lower these breakeven prices through project reengineering, strategic combinations and alliances amongst service companies and cost deflation across the supply chain will help to improve the economics on other offshore programs, and in turn, lead to future customer demand in offshore drilling.

And lastly, a large number of offshore rigs have been retired, a trend that we expect will continue to aid in rebalancing rig supply, along with deferrals and cancelations of newbuilds.

In the interim, Ensco's offshore crews and onshore support staff remain focused on delivering outstanding uptime performance, along with safe and efficient operations, so that we can continue to maintain our leadership position and customer satisfaction. Now, I'll turn it over to Jon..

Thanks, Carey. Today, I'll cover third quarter financial results, outlook for the fourth quarter, and actions we have taken since our last call to further strengthen our financial position. Starting with third quarter results versus prior year, third quarter 2016 earnings per share from continuing operations were $0.28 compared to $1.34 a year ago.

Several items influenced these comparisons, including a gain on debt repurchase and discrete tax items during the third quarter, revenue related to early contract terminations a year ago, as well as other items noted in our press release. Total third quarter revenue was $548 million versus $1.01 billion last year.

In the floater segment, revenue declined to $319 million primarily due to a year-over-year decrease in reported utilization to 48% from 59% last year and early contract terminations in the year-ago period. Average day rates declined $353,000 from $422,000 last year.

Operational utilization for the floater segment, which adjusts for end contracted days and planned downtime, was 99%, up from 95% a year ago. In the jackup segment, revenue was $214 million compared to $326 million last year.

As reported, the utilization declined to 55% from 64% in 2015, and average day rates decreased to $109,000 from $134,000 a year ago. Operational utilization for the total jackup fleet was also 99%.

Total contract drilling expense declined to $298 million, in line with the outlook provided on our last conference call and included $4 million of severance and other restructuring costs associated with our onshore support reductions.

Year-over-year, we reduced contract drilling expense by 31% from $434 million in third quarter 2015 due to fewer operating rig days and proactive expense management. Depreciation expense was $109 million, in line with our expectations. General and administrative expenses of $25 million was in line with our outlook and down from $28 million a year ago.

As detailed in our earnings release, other expense was $31 million and benefited from an $18 million gain on debt repurchases, inclusive of a discount to the principal amount and a net premium for the carrying value of these notes.

Excluding this gain, other expense was $49 million compared to $52 million last year due to a $12 million reduction in interest expense following our year-to-date debt repurchases, partially offset by $10 million of lower capitalized interest. The third quarter effective tax rate benefited from several discrete items.

Now, let's compare third quarter 2016 to second quarter 2016 sequentially. Starting with revenue, excluding $205 million early contract termination settlement during the second quarter, revenue declined 22% primarily due to approximately 500 fewer rig operating days.

As a result, utilization declined to 53% from 61%, and average day rates declined to $184,000 from $195,000 last quarter. Total contract drilling expense declined $52 million sequentially from the second quarter due to fewer rig operating days and disciplined expense management, including lower operating costs for preservation stack rigs.

Looking at other expenses, depreciation is $3 million lower quarter-over-quarter and G&A expense declined by $2 million primarily due to the timing of the annual compensation. Moving to our outlook for fourth quarter 2016, total revenues are expected to decline by 7% from third quarter levels of $548 million primarily due to lower average day rates.

Given recent contract wins for several jackups that will require incremental startup costs plus preservation stacking cost for ENSCO DS-3 and ENSCO 8506, which together total $16 million, fourth quarter contract drilling expense is expected to increase slightly from third quarter levels at $298 million.

Adjusted for these startup and preservation costs, fourth quarter contract drilling expense is expected to decline to approximately $285 million to $290 million.

We expect first quarter 2017 contract drilling expense to be down further from this adjusted fourth quarter range, driven by the expense management actions Carl described earlier, plus a full quarter's cost savings from preservation stacking additional rigs.

Fourth quarter depreciation expense is expected to be in line with third quarter levels, and we expect G&A expense to be $24 million to $25 million for the fourth quarter. Interest expense, net of capitalized interest, is estimated to be in line with third quarter levels.

Our effective tax rate for the fourth quarter is expected to be in the mid-20% range. Looking out to 2017, we may experience higher effective tax rates, since in periods of declining profitability, our income tax expense may not decline proportionally with pre-tax income.

We have not yet completed our budgeting process for 2017, and we'll provide an outlook for our effective tax rate next year when we report fourth quarter earnings. Now, I'll cover our capital management actions and our financial position.

Earlier this month, we extended a portion of our revolving credit facility by one year and now have access to $1.13 billion from September 2019 to September 2020, providing us with additional liquidity and capital management flexibility.

Importantly, the terms of our revolver extension are unchanged, the facility remains unsecured, and the only major covenant remains at 60% book debt-to-capital ratio, which we are well below.

We've further reduced leverage on our balance sheet during the third quarter by repurchasing $189 million of debt, and the third quarter purchases will reduce our annual run rate interest by $11 million and $45 million in total through the maturity of these notes.

More recently, after quarter end, we opportunistically exchanged $24.5 million of long-dated debt maturities for approximately 1.8 million shares. This transaction resulted in a $9 million gain that would be reflected in our other income during the fourth quarter.

In total, our year-to-date capital management actions have reduced net debt by more than $1.6 billion and annual cash interest obligations by more than $60 million. Our net debt to capital ratio declined to 27% as of September 30, a significant improvement over a net debt to capital ratio of 41% at the end of last year.

While we repurchased debt and made a final milestone payment for ENSCO 140 during the third quarter, we maintained $1.8 million of cash in short-term investments on the balance sheet at quarter end.

In addition to cash and short-term investments, we have a fully available $2.25 billion revolving credit facility that matures in September 2019 to total liquidity of more than $4 billion, along with $3.8 billion of revenue backlog.

As a reminder, we have no debt maturities until 2019, with only $1.8 billion of maturities over the next eight years, and all of our debt obligations are unsecured. Moving to our capital expense outlook, since our last earnings call, we have reduced 2016 CapEx by $25 million and we now expect total CapEx to be $350 million for the full year.

Total remaining newbuild CapEx is now $670 million following the delivery of ENSCO 140 during the third quarter. As detailed in our investor presentation on our website, we have a manageable CapEx outlook with declining commitments over the next several years.

In closing, we have proactively managed our financial position by strengthening the balance sheet and through disciplined expense management, including proactive fleet restructuring and reduced operating and support costs.

We will continue to evaluate opportunities in a disciplined manner with an eye towards improving our competitive position in both the short and long term. Now, I'll turn the call back over to Sean..

Operator, you may now open the line for questions, please..

Thank you. We will now begin the question-and-answer session. And our first question comes from Gregory Lewis with Credit Suisse. Please go ahead..

Yes. Thank you, and good morning..

Good morning, Greg..

Jon, in your prepared comments, it sounded like you – there was a transaction where we've – there was an issue of some stock for some debt. I didn't see that in the press release.

If I understood that right, could you just kind of walk me through that opportunity and sort of how that worked?.

Yeah. Sure, Greg. Happy to do so. First, let me just kind of frame it within our broader capital management framework. So, there's three main tenets that we've been working under and I touched on all three of those in the prepared remarks. So, the first one was debt reduction. So, the net debt, we've taken down by $1.6 billion year-to-date.

The second piece, reducing cash interest expense and, again, that one we had $60 million of annual savings on interest expense. And then, the third piece is continuing to extend our runway with only $1.8 billion of maturities over the next eight years, and then the additional year of revolver commitment.

Within that framework, that was – there is a unique transaction on a small scale, so $25 million, that fit into this broader capital management framework It opportunistically allowed us to both reduce leverage and generate cash interest savings..

Okay. I mean....

And, Greg....

Yeah. I mean, that's great, but – okay. Yeah..

Greg, it's Carl here. Yeah. Just to add that this isn't something that we have been actively looking to do necessarily, but we got an opportunistic chance to do it. And so, since it fit in with our general structure, we decided to do it..

Okay.

And just that was from an existing bondholder who offered this?.

Yeah. That's right..

Okay. No, I mean, I think that's a great move. I mean, if you've found (26:57) opportunities to do that, well, please go ahead and do them. I think that's great. And then, really, I just had another question about just as we think about the balance sheet.

Clearly, you guys are doing – just as an example, trying to do creative things to sort of really continue to deleverage and buying back some more of the 2021 bonds, it looked like in the Q.

Just at a certain point, does the company sort of look at its balance sheet and say, we're in a good position, maybe it's time to start maybe trying to build out a cash war chest so that we can potentially go after some assets or are we still kind of in the more of the all hands on deck paying down debt position right now?.

I'll take that, Greg. So, I think largely to understand, we've used – we've done a lot of work, as you said, around the balance sheet and our liquidity. And our priorities have been to build a bridge to the future to make sure that we're in a strong financial position for an extended downturn and even if conditions were to get worse.

The second one is then to start to address our liability management and make sure that we have delevered the balance sheet. And the third then is, we – it gives us opportunities to look at things that might be a little more offensive or on the M&A side, and that's largely the priority in order. Now, on the first two, we've done a lot of work there.

I think – I can't and won't say that we're at the end of the road on that because we'll reserve the right to look at this. But I think we feel very comfortable with where we sit today and on the actions we've taken, which means that we do have the opportunity to start looking at other things such as M&A.

But that said, we don't feel compelled to do anything. We have done a lot of work to make sure that we're in a strong and healthy position, and we've done a lot of heavy lifting around our fleet and taken some very painful decisions about retiring some of our older rigs, whilst we bring in the new rigs.

So, that puts us in a strong position to just go it alone and see ourselves through the cycle. But given our liquidity, given our operating capabilities and our global footprint, I think you'd expect us to be scanning the environment at the moment for M&A.

And as the management team and the board, it behooves us to take a look, but we are not going to do anything that weakens or basically makes us more vulnerable through the cycle. And anything we do would be very judicious and very carefully considered..

And, Greg, one thing I'd add to that is if you look at the transactions we've done on the debt repurchases this year, so in aggregate, we've purchased over $1.1 billion of debt, and we did that opportunistically.

And I use that word because we purchased that debt at a 24% discount on average, and the substantial majority of that was all near-term maturities due 2021. If you look at where our bonds are trading today, the opportunity set has changed significantly. So, the debt has gotten significantly more expensive.

A couple of our near-term maturities are now trading above par. So, the value proposition has changed as well..

Yeah. Okay, guys. Many thanks. Great job on continuing to extend the runway. Have a great day..

Thank you..

Thank you..

Our next question comes from Ian Macpherson with Simmons. Please go ahead..

Hi. Thanks. I had a question regarding the backlog with your customers, mainly Saudi Aramco in the Middle East. And you – I guess, congratulations on the contract extension that you've recently reported.

And you also still have several rigs that have – on the status report, they're scheduled to resume – to revert back to prior day rates that are much higher than what they've earned this year as of January.

And I just wanted to check in with you on that, the status of those and what your expectations are for those day rates as we move into January; if we're still expecting to reprice or to revert back to the original..

So, we still have it in the fleet status report. As the price is going up in 2017, that's still the contract position. So, that's what we're reporting. I think we'll have to see as we get closer to it. But as we have seen, what we may end up in is a larger scale renegotiation around some of those contracts that may involve some term.

So, I think we will just have to wait and see as we go into the beginning of 2017 where we end up..

Okay. Separately, Carl, you had a, I thought, a pretty favorable outcome with the ENSCO 140 and the ENSCO 141 with the shipyards defraying your warm stack costs for a couple of years.

When we look out to next quarter with the ENSCO DS-10 due for delivery, can you update us on what you're thinking for that rig in terms of the delivery date staying intact or maybe moving, and what your expectations would be for cash burn if you were to accept the rig into some form of a stack mode?.

Okay. So, if you don't mind, Ian, I'm not going to go into great detail on this because we're right in the middle of negotiations with the shipyard, and that's a relatively sensitive subject at the moment. So, I'm not going to provide a very clear update on that.

But just to say, as Jon noted in the prepared statements, we are, as of this point, assuming it in our CapEx for next year. And so, we'll see where we end up.

We would – since we're in a somewhat different position from some of our other peer group in the sense that we have good liquidity and good cash, we don't have to defer that out because we are not able to make the stage payments. So, we could take delivery of it within our predicted cash flows. So, we'll see where we end up.

It is – that – the ENSCO DS-10 is probably one of the most capable and best equipped rigs – drillships anywhere in the world. So, at some stage, that is going to be a very competitive rig for us and we are anticipating taking delivery of it at some point..

Understood. Okay. Thank you..

Sorry if I've been a bit obscure on that, but I think you can understand given the position we're in..

Certainly. Thanks, Carl..

Our next question is from Robin Shoemaker with KeyBanc Capital Markets. Please go ahead..

Yes. Thanks. I wanted to ask a just general question on the market recovery scenario. So, obviously, a lot of the opportunities today are very short term, but you've got a couple of interesting slides in your presentation that relate to the deepwater economics.

And is the Gulf of Mexico and the North Sea going to be the starting point of a broader recovery with short-term work, single-well programs, tiebacks and so forth? And then, a progression as oil prices climb to some of the other markets with, I think, West Africa probably being the last one.

But do you see it that way or is it going to be somewhat surprising to us in terms of how the market recovery evolves as oil prices step higher?.

Hi, Robin. Maybe I'll take the opportunity. Just to step back a little bit and give a higher picture on the market, and then I'll try and walk through the market recovery scenario as we see it as for your question.

The first thing to point out is that what we are seeing at the moment is a difference between how we see the deepwater and the floater market recovering versus the jackup market. In the jackup market, we have seen over the last quarter, a step-up in inquiries and potential tenders coming for 2017.

And certainly, in dialogue with a lot of our customers that work in those basins, we are seeing them begin to get ready to go back to work. And an oil price – Brent price of $50-plus, I think, is a key threshold that – for people begin – to begin, start to reconsider work.

So, we feel more – we feel increasingly confident on the conviction that the jackup market is going to be the one that comes first, and we're well-exposed in a lot of the key basins there for that recovery.

Now, at the moment, it's important to point out that the number of inquiries and tenders that we have seen are not enough yet to offset globally, the number of rigs that come off contracts over the next couple of quarters. So, I'm not calling bottom there.

But what we do see is a scenario building where we could see a turning point on the jackup market in 2017. And certainly, in terms of utilization, I think market – pricing is going to be very competitive still. The floater space is different.

We don't yet see a catalyst to call any kind of term there, and I think we are clearly in a market condition where we're seeing customers restricting capital expenditures still as they try and build cash reserves and cash flow.

And I think we are going to be seeing utilization and day rates continue to drop probably for at least the next four quarters. Now, that being said, the sequence that we think is going to evolve here, and we're beginning to see this a bit, is that the jackup space and the jackup market will be the first to come back.

If anywhere – if any part of the market has the ability to surprise, it's there. I'm not sure we're there yet, but if there was, I will not call out, it's in that.

Then in the floater space, I think the first thing we are going to see is step out wells, tie-backs, interventions, work up in-field around the existing infrastructure probably on a well-by-well or a small program basis.

And that's what we're seeing around in the Gulf of Mexico, for example, and our two ENSCO 8500 series rigs that we have working are pursuing that type of work. And I think as they go forward, the type of work you'll likely to see them take is this well-by-well or two- or three-well programs around that type of in-field work.

And then lastly down the line, you're going to start moving to more development drilling of new FIDs, and then sort of last in the chain of things is probably going to be deepwater exploration. So, I think that's the chain that we see coming.

As far as initial markets to pick up, I think the Asia Pacific is showing – and the Middle East area are the ones that are showing probably the greatest ability to flex up on the jackup and shallow water market.

On the floaters, I think it's a bit early to start calling where, but we do think there will be individual opportunities for short-term contracts around the Gulf of Mexico, bits of the Mediterranean, North Sea area.

What we have actually seen – just as one quick addition on is we have seen a handful of floaters, tenders inquiries start to come out now for 2018. Nothing to call any great significance to, but I think where customers do have line of sight and they have cash flow programs, they are beginning to think about 2018..

Okay. And in – just one follow-up. On your presentation, you talk about a future catalyst to Mexico.

Is the deepwater there – is that going to be an exploratory drilling in the first phases and is that likely to ensue immediately after the blocks are awarded? Kind of generally, what timeframe do you see the deepwater drilling in Mexico or tendering for that activity?.

So, we don't see at this point that it's going to be a very, very near-term catalyst, as in something that can affect immediately 2017 or things like that. But as we begin to go out beyond that, I think that it will start to build.

It is likely to be exploration quite quickly on the back of – exploration wells quite quickly on the back of the licenses. But any development is likely to be pushed out further in time.

I think it's a slow burn and a slow build, but the potential, therefore, it starts to absorb a significant number of rigs over time, I think, is something that will happen.

What we're also seeing is that the – even in the shallow water areas that there's a lot of interest from a very wide range of E&P customers into Mexico, and not just to the big IOCs. We're seeing quite a few of the U.S. independents we've worked with wanting to go there.

And they are actually very keen to work with the drilling companies they've worked with on the Gulf of Mexico, the U.S. side. So, we're getting a lot inquiries from the independents that we worked with about working with them in Mexico..

Interesting. Okay. Thank you very much..

Our next question comes from Haithum Nokta with Clarksons Platou Securities. Please go ahead..

Hey, good morning..

Good morning..

I wanted to just, I guess, follow up a little bit on your comments about the jackup market. And, look, I guess, ex-Middle East, you mentioned Asia-Pacific.

Are there any other regions that you feel could pick their head up over the next 12 months in addition, and like the North Sea or West Africa or those kind of later recovery basins in your mind?.

I would reiterate that – the fact that I think the Middle East and Asia on top of that is probably the one that we expect to see first responses. And I think it's early to call on the North Sea, that the North Sea is going to be very dependent on what next year's oil price looks like and where people go into their budgeting cycles.

It's still in decline at the moment in the sense that contracts coming off tender don't have immediate follow-on. Although, as you've seen, we are getting well-by-well extensions and things like this on the lot of the rigs.

There is a sentiment change happening in the North Sea as Brent has gone back up to $50 than where we were looking at it six months ago. But I don't think we would call and say that it's reflected in a wholesale change in activity. We certainly see a series of key opportunities going into next year.

And, for example, as our ENSCO 120s begin to come to their end of their current contracts, we are going to keep them warm and ready to go because we see quite a few opportunities to put them back to work going into next year. So, the North Sea is not dead by any means.

I'm not sure I would say it's going to have a wholesale pickup next year or not yet. Gulf of Mexico has actually come up a little bit in activity, but it's come off a very low base, but it's one of the first markets where we've seen a step-up. And so, we are seeing some early signs of jackup activity picking up in several basins as the moment.

But I want to be very clear that as of yet, that's not enough to offset a lot of the global fleet coming off contract within the next quarter..

Sure, and I think that's well-understood. And then on, I guess, the ENSCO 8500 series, you mentioned targeting a lot more in-field work and how a lot of that's been what you're doing in the Gulf of Mexico.

Are there any other regions that you see exporting those rigs to or where that in-field type of work makes no sense at this point from an operator perspective on this?.

So, I think, first of all, on the rigs, the two rigs that we've got in the Gulf of Mexico, I think as I've said, they're going to – we see them over the next, say, three quarters, four quarters working largely on short-term contracts, but picking up work as it comes about on a well-by-well or small programs.

Asia Pacific is another area where we see a need for that type of rig, so we're definitely going to be keeping the ENSCO 8504 available for pickup work there. And that's a market where that we will watch carefully as it develops as to whether we would relocate another rig there of that class.

And, also, the areas that we are watching very carefully where we believe there is a need is in West Africa. So, we've stacked out four of the rigs in preservation stacking now. We're going to keep three marketed to pick up this work.

If we saw enough activity in this in-field work beginning to come, we would be prepared to proactively bring out one of the rigs from stack to address that market and most likely relocate it out of the Gulf of Mexico..

Okay. Thank you. And then, just one last quick one.

The ENSCO 140 and ENSCO 141, I know that Lamprell is basically covering the stacking costs for those, but will there be any kind of, I guess, OpEx for those rigs that's close to the income statement or no?.

Haithum, this is Carey. Yeah, there would – there will be minimal OpEx that flows through the income statement. We would have just a few people around to keep an eye on the rigs as – while they're warm-stacked and managed by the shipyard..

Okay. Thank you..

But we do – one of the reasons we took delivery of those rigs is because we think as the jackup market begins to recover especially around the Middle East, Asia, that these are going to be very competitive rigs, and we are bidding them into projects now, some for 2017.

So, whilst we'll go straight to stack when we take delivery of them, we are hopeful that these will be back to work within a sensible timeframe..

One of the piece I'd add just on the accounting treatment for the ENSCO 140 and ENSCO 141, just so you have it in your models. So, while we've taken delivery of the ENSCO 140 and we'll shortly for the ENSCO 141, we stop capitalizing those rigs. But we have not yet started depreciating those rigs.

So, you won't see the depreciation expense hit until we get a contract on those rigs and they get – go through their acceptance testing. So, the only piece that you'll see through the P&L is the small bit of OpEx that Carey described..

Appreciate the clarification..

Our next question is from Vebs Vaishnav with Cowen. Please go ahead..

Good morning, and thanks for taking my question. I wanted to touch upon the cost savings and the OpEx guidance. So, help me think about this $15 million and $20 million coming in fourth quarter and first quarter.

Are we going to see that on the OpEx line or in the SG&A line?.

Yes, I'll take the – maybe I'll just give you the first bit, and then I'll pass over to Jon for some specifics. So, at the high level, as you saw, what we have done is we've taken a series of actions that are going to result in annualized $50 million of savings versus where we were at the end of – in Q2 this year.

Now it's probably important to point out that these are not aspirational targets or these has all been enacted. So, we've centralized some key functions. We're moving to a different support model for a lot of our business.

And what I'll point out is that this is also designed so that we have a more efficient support structure as we go through the cycle and afterwards. So, these are efficiency changes to the way we run the company that we expect to gain advantage for us as we come out of the cycle as well. But they're all enacted.

And the decisions around the discretionary compensation are all agreed and in place. So, there's nothing here that is aspirational that is yet to be done. It's all done and ready to start rolling through.

The other element I'll just say is that what we did call out in the pre-prepared statements is the fact that we'll have a slightly unusual Q4 contract drilling expense, CD&E, as a consequence of these one-off items that we have around preservation stacking to floaters, and then the preparation for at least four rigs getting ready for new contracts.

If you strip that out, our quarterly CD&E would be coming down, and we still expect that trend to continue into January next year. So, we would expect another dropdown in January, and we'll give you more details of that when we report Q4..

And then to focus on – and if you want to understand the split between G&A and CD&E, the vast majority of the savings are going to be flowing through CD&E. So, if you think about who the $50 million is impacting, it's our shore-based personnel, both the corporate and the rig support personnel.

And the rig support and some of the other back office functions will be flowing through CD&E. So, that's where you'll see the majority of the reductions..

Okay. So, if I take out the stackings or these one-time costs for preparation of contracts, I was thinking maybe for the – from a full quarter benefit of stacking ENSCO 6003, ENSCO 6004, then ENSCO DS-3, ENSCO DS-5, your OpEx would have been normally down $15 million to $20 million in fourth quarter.

Am I being – is it being fair saying that $15 million to $20 million of onetime costs are embedded in your fourth quarter cost guidance?.

Yeah. The $16 million is – of onetime costs is built into our guidance that we've just given for Q4 CD&E..

Okay. And....

Yeah. Vebs, this is Jon. Just to be perfectly clear, so our reported contract drilling expense guidance on a reported basis would be $301 million to $306 million. The $16 million Carl was just mentioning, which are partly related to startup costs, which is good news because those are contracts getting new work, is $16 million.

So, as Jon described in his prepared remarks, the adjusted contract drilling expense guidance for 4Q 2016 is $285 million to $290 million, and that incorporates the $15 million of incremental cost saving efforts that we talked about on an annualized basis in terms of actions that have already been taken..

Okay. That's helpful. And one last thing for me, just if I look at the OpEx for jackups, so the revenues declined, but the OpEx increased.

Can you help me think about what was going on there? Where there any onetime specific items?.

Yeah. Just give us a second. We're just gathering the....

You're talking about on Q3?.

Yes, sir..

Yeah. So, the majority of that was just some startup costs that hit us in Q3..

Okay. All right. That's all for me. Thank you..

Our next question comes from Eduardo Royes with Jefferies. Please go ahead..

Hey, guys. Good morning..

Good morning, Eduardo..

Morning..

Just a question on day rates and bidding strategy and the like. Obviously, for competitive reasons and whatnot, we know that we're getting less and less color on what those actual day rates are.

I guess this is a bit of a – it's not really a theoretical, and I know there's only so much you can give, but when you guys are maybe going after a one-well job with a smaller customer where it may be obvious that the rate maybe needs to be a lot lower than where you'd like it, maybe even more uneconomic than if you were just to warm-stack the rig, any perspective you can offer on how you guys are thinking about bidding those rigs? Are there scenarios where you're talking to customers and saying, look, I'll give it to you for this for the one well, but the next well I'm going to bump it up because this math doesn't make sense, or if maybe some linking to the oil price, not in terms of what we've thought over these five-year contracts were – okay, if the oil price goes up every year, you take it up, but actually more on some of those well-to-well stuff where I realize – or you guys may realize that the customer can do this one-off well, but if oil's at $45 again three months from now, he may not be able to do it and he certainly won't be able to take the price up.

But conversely, obviously, if oil's at $55, you guys will be able to say, okay, I can do this additional well, but I'm going to take the cost up X-percent? Any perspective you can offer sort of on the day rate strategy obviously without getting into numbers?.

Okay. Yes. We're not going to get into exact bidding strategy. But, if I can elevate that again a little bit.

Just to reiterate what we said in the pre-prepared statements that we have decided to preservation-stack a series of our rigs based simply around our assessment of what the market demand is going to be over the next kind of 12 months or so, and therefore, reduced our market fleet. However, we are not going to just keep stacking out every rig.

What we have decided to do is run this portfolio approach where we were basically keeping a certain number of rigs by class – drillships, semis, and jackups available in core region, by region, by rig type. And those rigs we will have available to market. So, a good example of this is we are going to keep the ENSCO 8504 in Asia available for work.

The ENSCO DS-7 drillship is going to – when it finally comes off the contract, will be available and kept warm, ready to work. And the ENSCO 120 series – some of the ENSCO 120 series that we have in the North Sea, for example.

And for those rigs, we are going to be bidding them to keep them active, to keep the crews active, and to form a bridge through to the future. And we will judge each project a little bit on its own merits.

And there are some single-well projects that require maybe very expensive mobilizations we will choose just not to bid on because the cash flow burn on those projects just don't make it worthwhile as it's better to keep the rig warm-stacked and wait for the next project.

In places like the Gulf of Mexico, on some of the ENSCO 8500s, actually, we are able to string together, streams of single-well projects with different operators that actually can be economic for us to run the rigs through by putting them together because there aren't major mobilizations from well-to-well and things like this.

So, it really is dependent on case-by-case. But for the rigs that we have decided that are going to be our swing capacity and are warm-stacked, we are going to be bidding aggressively to keep them active..

Eduardo, let me just add to that. This is Carey. Now, there are numerous creative contracting ideas and pricing ideas, and probably as many as there are clients.

So, without getting specific, those are kind of things we're open and interested in doing, but there's just too many of them and I don't think we want to get into details about how we would do it right now..

The other one is you also have to look at the counterparty risk for these single wells with customers that have difficult cash flow. I mean it's one thing to enter into an interesting or new contract model. It's another one to just basically take risk and gamble, and we are definitely avoiding the latter..

No, that makes sense. Thank you very much. Just my follow-up, I guess, is for Jon. Just to be clear in the guidance, when you gave the revenue guidance.

For the ENSCO DS-7, that's – even though there's a termination effect that, I guess, any day now, this weekend, the way that's being modeled, if I understand correctly, is that the rate just drops down to the $439,000 per day. So, I'm guessing the revenue guidance includes effectively, this reduced warm stacking day rate.

Is that correct?.

Yeah, no, that's correct. So, after the termination notice, we have 90 days of full rate and then it drops down to 75% of the rate, and that's what reflected in the guidance..

Okay.

And you're going to be getting the cash – or how are you guys going to be getting the cash? It's not an upfront payment?.

No. No. There's not a lump sum payment like we've recognized in some of these other terminations. It will – we'll receive the 75% due to the duration of the regional contract term after the 90 days, which we'll get from the full term – the full payment..

Effectively like the ENSCO DS-9 a year ago, I guess, until like they cancel, more or less?.

Well, until we just....

(58:41).

...negotiated an upfront payment for the remainder of that cash flow stream. That's right..

Okay..

And that's the only thing that could change here is if at some stage, there was a single payment settlement, but that's not in the contracts, and therefore, that becomes a mutually negotiated agreement..

Right. All right. Thanks, guys, very much. I'll turn it over..

Our next question is from Praveen Narra with Raymond James. Please go ahead..

Hi, Praveen..

Praveen, your line is live. You may go ahead with your question..

Hey. Good morning. Sorry.

Can you hear me?.

Yes. Good morning, Praveen..

Good morning. So, I just wanted to ask a couple of follow-ups.

Regarding the ENSCO DS-10, it's a little bit hypothetical, but if we just assume that you guys do take delivery and you guys certainly have liquidity to do so, do you think you guys would be able to reserve the berth at this shipyard in order to keep it quayside or how do you think about that?.

That's all part of the ongoing negotiations we have, so I'd really prefer not to go into that. Only to add that if they can't stay in their own shipyard, which is one option, we have other places we can take it to.

And we've gained a lot of experience now on exactly how to stack these drillships either in warm stack or in preservation stack, and exactly what's required to be able to have them ready to go in certain timeframes and in very good condition whilst they're being stacked.

So, we feel very comfortable about taking the rig ourselves and warm-stacking it..

Okay. Perfect. That's very helpful..

To be perfectly – Praveen, just to be perfectly honest, one of the things that comes into the discussion here is, given our liquidity position, we don't want to do anything that doesn't make financial sense. And, in some cases, we can actually do this cheaper than a shipyard can do it..

Okay. Interesting. That's very helpful color.

In terms of the M&A question and sort of getting more offensive and really taking care of your balance sheet recently, how do you weigh kind of the opportunities and the bid asks that are out there today versus kind of the risk of having to compete rigs against your current rigs and kind of the being more offensive at today's prices? Is it attractive enough today to make that risk-adjusted return?.

It very much depends on which type of M&A you're looking at.

And if you remember, in the past, I referred to the fact that you could simply put it into three types of buckets, the distressed assets, there's then the smaller fleet companies of maybe 4 rigs to 10 rigs that some of which are getting into distressed situation, and then there is the more peer group side, international company, which looks – that type of deal looks more like an equity merger.

So, it's not so much the bid spread ask as the individual circumstances of each of those categories.

On the – at this stage in the cycle, in the individual assets, we have decided not to play, and we are not chasing after one-off rigs at this point because to just go and acquire a rig without a contract, put it to the back of the queue behind our existing rigs, it doesn't look like a viable, sensible use of our liquidity at this stage.

And also, it doesn't move the needle for us. Now, as we go forward through the cycle, I think we may look at these things differently depending on how the cycle impose. But today, we're not looking at that type of – not aggressively looking at that type of opportunity.

With the medium-sized or the smaller-sized companies, the core issue there is not so much the – its spread ask, it's their balance sheet position. A lot of them have got very poor or very weak backlog, and very, very heavily levered on the balance sheet. And you just wouldn't want to take them at their balance sheet positions.

So, I think we would have to see some restructuring of some of these companies, which I think is likely to happen before maybe they become a bit more attractive..

Great..

It's much more individual case specific rather than just the immediate – the equity price for a lot of these companies is not the relevant decision-making criteria..

Great. That's super helpful. Thanks a lot. Have a great day, guys..

Okay. Since there are no more questions, I just want to thank everyone for participating on our call today. Have a great day..

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