Nick Georgas - Ensco Plc Carl Trowell - Ensco Plc P. Carey Lowe - Ensco Plc Jonathan Baksht - Ensco Plc.

Gregory Lewis - Credit Suisse Securities (USA) LLC Scott A. Gruber - Citigroup Global Markets, Inc. Haithum Nokta - Clarksons Platou Securities, Inc. Ian Macpherson - Simmons & Company International David Christopher Smith - Heikkinen Energy Advisors LLC Sean C. Meakim - JPMorgan Securities LLC Colin Davies - Sanford C. Bernstein & Co. LLC.

Good day, everyone, and welcome to Ensco Plc's Fourth Quarter and Full Year 2016 Financial Results Conference Call. All participants will be in listen-only mode. After today's presentation there will be an opportunity to ask questions. Please note this event is being recorded. I will now turn the call over to Mr.

Nick Georgas, Director of Investor Relations, who will moderate the call. Please go ahead, sir..

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

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

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

Please see our earnings release on our website for additional information. As a reminder we issued our most recent fleet status report on February 22. An updated investor presentation is also available on our website. Now let me turn the call over to Carl Trowell, CEO and President..

Thanks, Nick, and good morning, everyone. The offshore drilling industry continues to face challenging market conditions. We remain in the midst of arguably the worst downturn our sector has ever faced. During 2016 commodity prices reached new decade lows.

And reductions in customers capital expenditures led to declining utilization and day rates across the global fleet. Despite this difficult backdrop, our offshore crews and onshore personnel did an outstanding job of staying focused on our core values of operational excellence and safety.

And in turn delivered the best performance in our company's history. Across the fleet, operational utilization was 99%, a new company record, and a 3 percentage point improvement over last year's results. Floater operational utilization was particularly strong at 99%, compared to 94% in 2015.

We also achieved our best ever safety performance, setting new company records for total recordable and lost time incident rates. And we made improvements in several other key safety metrics.

Our improved operational and safety results benefited from targeted investments in enhanced systems and training that have improved equipment reliability and increased competency among our rig crews.

These investments are part of a multi-year effort to further improve our systems, processes, and technology, which will help to differentiate our assets from the competition through better performance and reliability.

In addition to being core values for Ensco, operational efficiency and safety are critical to our customers, especially in the current market where customers have their choice of rig or company they contract with.

To this end we were honored to once again be recognized as the leader in total satisfaction by our customers, earning the number one rating for offshore drillers in the annual EnergyPoint Research survey, our seventh consecutive year to win this award.

In addition to total satisfaction our customers rated Ensco number one in 11 other categories, including safety and the environment, performance and reliability, job quality, plus several other technical and geographical categories.

By delivering high levels of operational and safety performance, we strengthen our relationship with customers, which improves our chances of extending contracts and winning work from contracted rigs.

In 2016 we translated our strong operational results into approximately $1.2 billion of revenue backlog through new contracts and extensions with customers. Furthermore, during the downturn we've seen a customer preference for established drillers with operating and safety track records when contracting rigs for their offshore programs.

And we expect this trend to continue during the early stages of the market recovery. In terms of capital management our efforts in 2016 were largely focused on improving our capital structure and balance sheet by managing cash outlays, reducing debt, and increasing liquidity.

Early in the year we reduced our dividend to $0.01 per share, freeing up $130 million of annual liquidity.

We then repurchased $1.1 billion of debt at a 24% average discount through a combination of tender offers and open market purchases, raised $586 million through an equity offering, and extended a portion of our $2.25 billion revolving credit facility by one year into 2020.

We continued our efforts to streamline the organization's support structure, and we are achieving our targeted cost savings. In December we took further action to improve our financial position by issuing $850 million of convertible senior notes with 2024 maturities and launching a concurrent exchange offer for our nearest term debt maturities.

We completed this transaction in January with $650 million of principal exchanged for $332 million of new senior notes that mature in 2024 and $333 million of cash. As a consequence of these actions, we have reduced net debt by $1.9 billion and increased our liquidity by $1 billion since the end of 2015.

We have no debt maturities until 2019 and only $1.15 billion of net – of debt maturing over the next seven years, along with $300 million of remaining new build capital commitments following our January progress payment for ENSCO DS-10.

After adjusting for the completion of our debt exchange, liquidity was $4.5 billion at year end, composed of $2.3 billion of cash and a fully available revolver of $2.25 billion.

Most importantly, following these capital management actions, our increased liquidity and more manageable debt maturity schedule provides us with greater financial flexibility as we navigate the market downturn.

As we look forward to 2017, we expect that conditions will remain very challenging for the offshore drilling industry, as rig supply exceeds customer demand. We anticipate the profitability among the offshore drillers will decline as rigs complete contracts with higher day rates and are re-contracted at lower day rates or are idled.

And Ensco will not be immune to this trend. However, we believe that 2017 will be a pivotal year for the offshore industry, representing the beginning of a different phase of the cycle. Compared to a year ago, customers have expressed growing optimism towards their offshore projects.

And we have seen an increase in tenders and inquiries for new work beginning in 2018 and beyond.

Ensuring that we preserve our core competencies, namely operational excellence and safety, along with targeted investments in engineering and innovation will be critical at this point of the cycle, so that we are well positioned to win more than our fair share of work during the market recovery.

We expect that the recovery will be protracted and phased, beginning with improved commodity prices, leading to increased customer activity from cyclical lows. We anticipate that jackups will see an earlier uptick in demand, aided by shorter cycle times, proximity to existing infrastructure, and lower project breakeven prices.

While material improvement in floater demand is still a ways off, improved commodity prices will begin to provide additional free cash flow for customers. And we expect to see capital first deployed towards deepwater drilling on infield projects around existing infrastructure and then on larger programs.

Increased customer demand, coupled with the scrapping of additional rigs will lead to higher utilization across the global fleet and greater pricing power and eventually to higher day rates. While rig utilization may improve in the shorter term, we expect that return of pricing power and higher day rates is farther off in the future.

But we believe that the seeds for a recovery in the offshore drilling market are being planted now. Therefore, it is critical to begin positioning our fleet to participate in this recovery. So we are focused on winning new contracts in order to keep our rigs warm and ready to work.

Given the competitive intensity of the market, this requires us to stay in front of our customers to understand their drilling needs. And we will target short- and long-term opportunities with strategic clients in key growth markets, so that we improve utilization across our rig fleet to ensure we are well-positioned for the eventual market recovery.

Now I'll turn the call over to Carey..

Thanks, Carl. As Carl mentioned, Ensco has once again been recognized by our customers as the industry leader in customer satisfaction in an independent survey by EnergyPoint.

This achievement is the result of a continued focus and commitment to safe and efficient operations by our offshore crews and onshore personnel, as evidenced by operational and safety improvements that resulted in new company records in 2016.

Our preventive maintenance programs and the condition based monitoring of equipment on our rigs also play an important role in delivering high levels of uptime.

We've made significant investments in these areas, including implementing our proprietary Ensco asset management system to continue improving our operational and safety performance to further differentiate Ensco from our competition.

Our outstanding performance has also helped Ensco win several contracts and extensions for our rigs, totaling approximately 14 rig years of incremental work since our last conference call. Starting in the Middle East, we secured additional work for ENSCO 54, extending its current contract for five years into 2022.

We also reached agreements with customers to extend lower day rates for 2017 that will keep several rigs working in the region. The Middle East has been the most resilient market during the downturn and continues to be an important region for Ensco, as evidenced by our seven rigs currently under contract.

We also took top honors in the Middle East in the EnergyPoint survey, a reflection of the strong performance from our offshore crews in the region. Moving to the Asia Pacific market. ENSCO 106 will return to work for a new program offshore Indonesia that is estimated to take five years to complete.

Our prior operational performance for the customer in the region differentiated us from the competition and positioned us to win this work and return an uncontracted rig to our active fleet on a long-term project. In the North Sea we signed an 18-month contract for ENSCO 80 that is expected to start in May and will keep the rig busy well into 2018.

We also won three shorter-term extensions that added backlog on ENSCO 80, ENSCO 101, and ENSCO 121. Moving to the Gulf of Mexico. We recently signed several contracts for jackups and floaters in the region, adding approximately $60 million in backlog.

All three of our active jackups in the region, ENSCO 68, ENSCO 75, and ENSCO 87, have secured incremental work that will keep the rigs on operating day rates for most of the first half of 2017. On the floater side, ENSCO 8503 and ENSCO 8505 also added short-term contracts.

And ENSCO 8503 won work in Mexico, marking our entrance into the country's promising floater market. Both of these ENSCO 8500 series rigs offer the versatility of a moored DP configuration with sixth generation drilling equipment.

And this flexibility has proven to be a differentiating factor when marketing these rigs Given its popularity with customers in the Gulf of Mexico, we are outfitting a third ENSCO 8500 series rig, ENSCO 8504, with a hybrid moored DP package, so we can market this versatility to customers in the Asia Pacific region.

We previously purchased the mooring winches that we will use for this upgrade. And the minimal remaining cost to complete this work is included in the CapEx guidance Jon will provide later in the call.

Targeted investments to upgrade our existing fleet are part of our broader fleet management strategy that also includes new builds and the divestiture of less capable rigs that are not a part of our go forward fleet.

During the fourth quarter we accepted delivery of ENSCO 141, which along with sister rig ENSCO 140, will be warm stacked at the shipyard until they are contracted, with daily stacking costs covered by the shipyard for up to two years.

We also reached an agreement to extend the delivery date for ENSCO DS-10 and a portion of its final milestone payment to the first quarter of 2019. By extending the delivery date, we were able to minimize crew cost and other expenses, since we won't need to mobilize the rig from the shipyard to stack it elsewhere.

As part of the agreement we retain the option for an earlier delivery with 75 days' notice, should we contract the rig before 2019. We are actively marketing DS-10 at this time. ENSCO 94 and ENSCO 53, both previously classified as held for sale, were sold for salvage value and will be scrapped.

Our fleet management strategy is designed to position our fleet for the future market recovery by maintaining rig availability by region and asset class to capitalize on customer demand. As part of this strategy, we have preservation stacked several rigs and plan to reactivate them when the market can support additional supply.

During this stacking process we take several steps to preserve these rigs so that we can reduce time and lower cost during their eventual reactivation. As a reminder we make upfront investments to preservation stack each one of our rigs. We spend approximately $5 million per floater and approximately $1 million per jackup.

Plus ongoing costs associated with connecting the rig to a power source and periodic inspection and maintenance of large equipment by Ensco personnel. But we feel that the reactivation benefits will more than offset these costs. Turning now to global rig supply, which we cover in more detail in our investor presentation on our website.

Offshore drillers have announced the retirement of 75 floaters since the beginning of the downturn. There are a total of approximately 70 additional floaters that we consider as retirement candidates, all of which are over 30 years of age and idled or scheduled to roll off contract by the end of 2018.

This is over twice the number of new builds currently scheduled for delivery over the same period, excluding 13 rigs in Brazil with questionable deliveries. Similarly, there have been 31 competitive jackups retired since the start of the downturn. And we see approximately 155 retirement candidates based on age and contract status.

This compares to approximately 90 new builds currently scheduled for delivery by year-end 2018. However, the majority of these jackups are being built by speculators and have seen their deliveries repeatedly delayed, highlighting the uncertainty of when and if these rigs will be delivered into the competitive market.

While we have seen some rationalization of the global rig supply during the downturn, more retirements are needed in light of the oversupplied market for offshore drilling rigs.

Given market conditions, deliveries for uncontracted new builds are being pushed out, which along with the retirement of older, less capable rigs will help to bring supply and demand for offshore drilling rigs back into balance.

In closing, while market conditions remain challenging, there are signs that we are entering a different point in the cycle. First, commodity prices have increased significantly from the decade lows experienced early last year.

Second, customers have successfully reduced breakeven prices for many offshore projects to levels below current commodity prices. Third, we have seen an increase in the number of customer tenders and inquiries as compared to 2016 lows. And finally, the supply of offshore rigs has gradually been reduced, and we expect this trend to continue.

These factors, when combined with the lack of exploratory drilling and declining reserve replacement ratios, may create increased incentives for certain customers to take advantage of the lower day rate environment.

In the interim, Ensco offshore crews and onshore personnel remain focused on delivering high levels of uptime, along with safe and efficient operations, so that we can win new work for our rigs and maintain our core competencies in preparation for the eventual upturn in the market. Now I'll turn it over to Jon..

Thanks, Carey. Today I'll cover fourth quarter financial results, our outlook for the first quarter 2017, and actions we have taken since our last call to further strengthen our financial position.

Starting with fourth quarter results versus prior year, fourth quarter 2016 earnings per share from continuing operations were $0.10 compared to a loss of $10.23 a year ago.

As detailed in our press release several items influenced these comparisons, including a gain on a debt-for-equity exchange during fourth quarter 2016, discrete tax items that impacted results in both periods, A loss on impairment a year ago, and a customer dispute related to a contract for ENSCO DS-5 last year.

Total fourth quarter revenue was $505 million, versus $828 million last year. In the floater segment revenue was $303 million, compared to $490 million in fourth quarter 2015, primarily due to a year-over-year decline in reported utilization to 44% from 57% last year and a decline in average day rates to $358,000 from $397,000 a year ago.

Operational utilization for the floater segment, which adjusts for uncontracted days and planned downtime, was 98%, up from 96% a year ago. In the jackup segment revenue was $187 million, compared to $307 million last year. As reported utilization declined to 54% from 66% in 2015. And average day rates declined to $101,000 from $126,000 a year ago.

Operational utilization for the jackup fleet was 96%, compared to 99% a year ago. Total contract drilling expense declined to $289 million from $415 million in fourth quarter 2015.

Excluding a $17 million provision for doubtful accounts in the year ago period, contract drilling expense declined 27% due to fewer operating rig days and disciplined expense management. Depreciation expense was $110 million, in line with our expectations.

General and administrative expense of $25 million was in line with our outlook and down from $30 million a year ago, mostly due to lower compensation costs, including reduced personnel expenses following staff reductions completed late 2015 and 2016.

As detailed in our earnings release, interest expense was $56 million, compared to $57 million last year, as lower interest due to debt repurchases was partially offset by lower capitalized interest and interest on our newly issued convertible debt.

Other expense benefited from a $9 million gain on a previously announced debt for equity exchange, which was partially offset by foreign currency loss due to the devaluation of the Egyptian pound. As noted in our press release, the fourth quarter tax provision was influenced by $7 million of discrete tax expenses.

In contrast a loss on impairment and an $11 million discrete tax item benefited the tax provision a year ago. Now let's compare fourth quarter 2016 to third quarter 2016 sequentially.

Revenue declined 8% due to a decrease in utilization to 51% from 53%, as rigs completed contracts during the fourth quarter, and a decline in average day rates to $177,000 from $184,000 last quarter. Total contract drilling expense declined $9 million sequentially, due to fewer rig operating days and disciplined expense management.

Depreciation and G&A expense were both in line with prior quarter levels. Other expenses increased $15 million in the fourth quarter primarily due to a gain on debt repurchases in the third quarter.

As I just mentioned, the fourth quarter tax provision was influenced by $7 million of discrete tax expenses, compared to a $6 million discrete tax benefit in the third quarter. Moving to our outlook for first quarter 2017. Total revenues are expected to decline by approximately 8% from $505 million in the fourth quarter.

Average day rates for floaters and jackups in total are expected to decline 11% from fourth quarter levels of $177,000, due in part to a 25% lower day rate for ENSCO DS-7, following a previously announced customer notice of termination for convenience.

This decline in average day rates is expected to be partially offset by an increase in combined floater and jackup utilization to 57% from 51% in the fourth quarter, as several rigs begin new contracts.

We expect that higher utilization will increase contract drilling expense on a sequential basis and that first quarter contract drilling expense will be approximately $300 million, as we prepare rigs for new contracts and complete scheduled repairs for several rigs under contract.

We expect that second quarter 2017 contract drilling expense will decline to approximately $290 million, in line with fourth quarter 2016 levels. First quarter depreciation expense is expected to be in line with fourth quarter levels. And we expect G&A expense will be approximately $25 million.

Interest expense is estimated to increase by approximately $2 million to $58 million in the first quarter 2017, primarily due to our recent issuance of $850 million of convertible notes and $332 million of new notes that were issued as part of the debt exchange completed earlier this year, partially offset by interest expense savings from our recent debt exchange and higher capitalized interest from ongoing investments in construction.

We expect our first quarter tax provision will be approximately $17 million. As I mentioned on our prior conference call, in periods of declining profitability our income tax expense may not decline proportionally with income, which could result in higher effective tax rates.

Additionally, we may continue to incur income tax expense in periods in which we operate at a loss. Now I'll cover our capital management actions and our financial position. During the fourth quarter we opportunistically exchanged $25 million of long dated debt maturities for approximately 1.8 million shares, which resulted in a $9 million gain.

We announced the placement of $850 million at 3% convertible notes that mature in 2024 and launched an exchange offer for outstanding senior notes due between 2019 and 2021. On January 9 we completed the transaction with $650 million of principal exchanged for $332 million of 8% senior notes due 2024 and $333 million of cash consideration.

These new instruments will increase our annual interest expense going forward. On a GAAP basis, excluding the impact of capitalized interest, annual interest is expected to increase by $50 million in total. Under GAAP rules the $850 million convertible notes carry an estimated effective book interest rate of 8%, compared to the cash coupon rate of 3%.

And when combined with the $332 million of new 2024 notes, will increase annual book interest by approximately $81 million. This will be partially offset by interest savings of approximately $31 million for the $650 million of exchange notes that we repaid in part with cash.

On a cash basis annual interest is expected to increase by $13 million, as $52 million of interest for the convertible notes and new notes is partially offset by $39 million of annual cash interest savings from the exchanged notes.

Most importantly, the net impact of these actions reduced our near term maturities by $650 million and increased our cash balance by approximately $476 million.

In total, our capital management actions since year end 2015 have reduced our debt maturities over the next seven years to a more manageable $1.15 billion, down from $2.9 billion a year ago, and increased liquidity by $1 billion, greatly improving our financial position.

Our pro forma net debt-to-capital ratio following the completion of our debt exchange declined to 25%, a significant improvement over a net debt-to-capital ratio of 41% at the end of 2015.

Our pro forma liquidity at year end improved to $4.5 billion, composed of $2.3 billion of cash and short-term investments and a fully available $2.25 billion revolving credit facility. We can borrow up to $2.25 billion dollars under the revolver through September 2019 and up to $1.13 billion from September 2019 to September 2020.

We have $3.6 billion of contracted revenue backlog and no debt maturities until 2019. And all of our debt obligations are unsecured. Moving to capital expenditures. CapEx totaled $322 million in 2016, approximately $30 million lower than our prior outlook, primarily due to the deferral of new build CapEx into 2017.

2017 CapEx is expected to be $425 million in total.

New build CapEx is expected to be $335 million and includes a $234 million progress payment made in January for ENSCO DS-10, CapEx from the prior year that was deferred into 2017, and planned investments in patented technology to increase drilling efficiencies that we are testing on some of our new builds.

The remaining $90 million of 2017 CapEx is for rig enhancements and minor upgrades, which includes the mooring upgrade for ENSCO 8504 that Carey mentioned earlier, as well as the purchase of a fourth set of mooring winches that could be used to upgrade another ENSCO 8500 series rig to the hybrid moored DP configuration.

Since our last outlook, 2017 CapEx has declined by approximately $25 million, primarily due to the deferral of the $75 million final payment for ENSCO DS-10 into 2019, which is partially offset by deferred new build CapEx and investments in patented technology that I just mentioned.

In closing, our financial strategy during the downturn has been focused on managing our cash outlays, reducing debt, and increasing our liquidity. We completed several transactions during 2016 that strengthened our balance sheet and improved our competitive positioning, as we navigate through this part of the cycle.

As we move forward we will continue to evaluate opportunities to further enhance our capital structure and improve our competitive positioning in both the short- and long-term, so we're prepared for the eventual market recovery. Now I'll turn the call back over..

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

We will now begin the question-and-answer session. Our first question comes from Greg Lewis of Credit Suisse. Please go ahead..

Morning, Greg..

Yes. Thank you and – hi, good morning. Thank you. So a couple weeks ago at our conference, one of the big subjects was around potential M&A and the timing of that. Just as we look at Ensco's balance sheet, clearly you guys had a big 2016, doing what you needed to do to get the balance sheet where it needs to be.

How are you thinking about that over the next 12 months to 18 months?.

Okay. Well, I think the way you asked your question summarizes very much what our strategy was. In 2016, we very much wanted to get our balance sheet and liquidity in position. And we were very much aimed at building a bridge through to the recovery.

I think that now we find ourselves in 2017 with a little bit more confidence of an uptick in client activity that now we can start to look a little bit further forward and maybe use that liquidity in a little bit more of an offensive way.

But what I would reiterate is that first and foremost, our priority still remains on making sure we can manage our way through our near-term liabilities. And importantly in that is the $300 million that we still have remaining on our new build program to deliver the final two rigs, DS-10 and ENSCO 123.

Thereafter, what we have seen during the last couple of quarters is that when we have looked at our various opportunities to deploy capital, we have started to realize that we have quite a significant number of investment opportunities by investing in our own fleet. And on a risk/reward balanced basis, these seem to produce some very good returns.

So we have been looking at ways to modify and improve our current fleet. And we've referred to some of it in the prepared statement. So we are doing modifications on some of the rigs. We are adding offline handling to the ENSCO 140, ENSCO 141. We've had – as we've announced, we're going to add another mooring system to ENSCO 8504.

And we bought another set of the equipment – or we're going to buy another set of the equipment to give us the option on another modification of an ENSCO 8500. And we have some technologies that we've been working on in the background that we're going to basically bring to field trial this year.

So that investment in our own fleet structure has moved up our agenda. Now thereafter, I think we of course will look at opportunities for either company- or asset-based M&A. I think that thus far, the market, the pricing that people have wanted has not been attractive to us. And so we haven't acted at all.

I think that probably over the next 18 months or so there is going to be probably more activity in the marketplace. And it's beholden upon us to take a look at that. But as we've said before we are not compelled to do anything, given the investment we've made in our own fleet structure.

And we're going to be very careful and judicial about how we look at those opportunities..

Okay. Great, Carl. Hey, thanks for that detailed answer. And then just as we looked at the fleet status report from last week, clearly that was one of the better fleet status reports that the industry has seen in a while, just in terms of the overall number of fixtures, the activity that was in that.

As we think about 2017 playing that out, was partially that a function of sort of addressing some near-term issues? I guess what I'm trying to get at is in terms of the season, is there any seasonality driving here? Where post sort of the quick start to the year, could we see a little pause here before we see some pickups maybe for work in 2018? Or do we think we're kind of – on a go forward basis we should expect to see contracts generally being fixed throughout 2017?.

Okay. I mean this leads into a bit broader discussion on market conditions. And I think what I would refer back to is the point we made in the pre-prepared statements, which is that we certainly feel that we're in a different point in the cycle. And that 2017 is going to be a pivotal year, probably very much as we look at it in the rear-view mirror.

But it's not like the lights have suddenly come on. And I think that the – as we said we expect the recovery to be protracted and staged. And I can expand on that a little bit more in a second. But all that said, what we have seen is a broad-based pickup in client activity in terms of tender opportunities and inquiries.

It's much more marked in the jackup segment, where we are seeing tender activity that is – if you look at the fourth quarter versus – of 2016 versus the fourth quarter of 2015, we have seen over 100% increase in the number of tenders and inquiries. And we have seen the number of tendered days go up by over 3x, a factor of 3x.

So we're seeing a higher number of inquiries and the contract durations are longer. So I think it supports what we said in the last earnings call, while we felt that the jackup market would be the first to pick up and that there was the possibility that utilization would bottom out in 2017.

Now to kind of reinforce that a little bit literally whilst we are on the call, we have had a contract back and conformation of an award for the ENSCO 92 in the North Sea, which is an extension of this contract by four years. And as a result we now expect the rig to be working through to 2022.

And I think that's just indicative of the general pickup we're seeing across the jackup market. The – and I don't think that that is necessarily seasonal. And I think we will continue to see that if commodity prices remain where they are and certainly if they improve.

What I would add is that we're actually seeing quite a number of these inquires of the start-ups in 2018. And I think that a certain amount of these inquiries will take a while to arrive at awards, because a lot of them have basically been used to test the market and test new projects and new economics.

And so not all of them are going to convert into tenders. But I think it's a pretty broad based pickup. The floater segment is different. We have seen a pickup in the number of tenders recently. I think there's been a lot of reference to – we've seen several new tenders come out for projects in Brazil. We've seen some more for West Africa.

But it's still low by comparison to the number of rigs that will be rolling off or ending contract this year. So I think in the floater segment we still expect to see global utilization for throughout 2017, before maybe beginning to turn some point, 2018, 2019.

But we don't have quite the visibility on the floater segment yet that we do on the jackups..

Okay. Hey, perfect, guys. Thank you very much for the time..

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

Yes. Good morning, gentlemen..

Morning, Scott..

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

What are the chances that some of these rigs go back into service this year?.

Well, for some of those markets it's early. But I think that if we see the trend continuing that we see here, we would be – we're hopeful that we will start to see some of these rigs back to work in the second half of the year.

In Jon's comments we referenced the fact that our CD&E costs in Q1 will be a little bit higher than maybe people have expected. But in part that is because we're actually proactively prepping a few rigs in anticipation of more work in H2, which is as yet uncontracted.

But we just feel on the general trend that it's probably time to get an early start on some of that to get rigs ready for potential work, H2. And I think the two markets you picked out, the North Sea and the Middle East, is where we will be hoping to get more placements as we go through the next quarter or so.

There's certainly quite a lot of tendering activity, which suits our rigs in those markets..

It's obviously in the Middle East then that would be jackup demand.

Is there jackup demand in the North Sea as well, as you're prepping some of these high-spec jackups?.

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

Got it. And just on that topic and as we turn to the floaters, I think you guys have discussed in the past the $25 million to $35 million reactivation as you pull the rigs out of preservation stack mode. And I know that the demand pickup as you mentioned is late this year into 2018.

But how do you think about striking the balance between the customer desire to contract hot rigs and your own desire to receive a payback on the restart investment? So if your active floater fleet becomes more fully utilized, would you reactivate some of the preservation stacked rigs speculatively to keep one 8500 series or one drill ship ready? Or do you wait and demand a full payback on a certain contracts before you reactivate? How do you think about striking that balance?.

Okay. So, Scott, first of all, on that $25 million to $35 million guidance we gave on reactivation. I think that the more we now work with these stacked rigs that the more we feel confident that's the right range. In fact, what we now are beginning to understand is that the actual true reactivation cost is actually probably less than $10 million.

The rest is made up of catch-up on maintenance that you would have to have done anyway and maybe some upgrades to make the rig applicable to the client's program. So that's just to give you a little bit more color on that.

The – with respect to keeping rigs warm, yes – and having rigs ready to go, we are inclined to always have at least one or two rigs of any class ready to go for work. Now remember thus far, we still have rigs like DS-7 and DS-9, which are ready to go to work. And if you take the case of DS-7, it's warm, ready to go.

But we would be prepared if we saw the right market conditions to proactively bring out maybe one additional drill ship and one additional ENSCO 8500 series warm and ready in anticipation of work and not require the first project to carry all the cost of doing that. Now that's something we can do, because we have the financial wherewithal to do it.

Not necessarily everyone is in that same position. And it's also – is very much why we have driven to make sure we have the liquidity to see through the cycle, because we want to be able to make that proactive investment to have rigs ready..

Got it. I appreciate the color..

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

Hey, morning, gentlemen..

Morning, Haithum..

Morning..

Jon, you were able to extend a portion of the revolver last year I think, which was somewhat of a surprise just on an unsecured basis at least. And that was before the OPEC decision. Curious to know, since then obviously the market has – or the capital markets have definitely improved.

Is there any upside to be able to either extend that revolver further or increase the availability under that one year extension?.

Yeah, sure. So the revolver extension this year, just to kind of frame how that works. We – for our full revolver we have 14 lenders comprising that $2.25 billion facility that we have today. When we originally entered into that facility, we had two one-year options at our election to call the options and a lenders' option then to extend.

And so what we did this time here was we actually exercised one of those options. And each of those 14 banks within the revolver were given the choice to extend or not to extend. And so we were approximately half, so the $1.13 billion extended for the additional year.

So within that existing revolver under those terms, we still have one of those options remaining. And we continue to evaluate if and when the right time to go back to lenders for that. We monitor the markets for the – for bank lending. The revolver was put in place under investment grade terms.

At this point we are not an investment grade company, so we have been downgraded by S&P and Moody's to sub-investment grade. And so those extensions aren't necessarily given, given the change in credit profile. But we do have a very strong relationship with our banks.

And I think that our banks view Ensco very favorably from a credit standpoint within the industry. And so we continue to have those conversions with the banks to see the appropriate time to ask for any further extensions or to potentially even ask for an increase..

I appreciate that color. And I guess to shift gears to the ENSCO 8503, congrats on that initial contract in Mexico. I'm curious if you can expand a little bit on what you're seeing in the Mexican market? And specifically for that rig, I mean is it relatively easy for a floater to move between the U.S.

and Mexico side from a customs and tax and all that kind of perspective? And then also do you think – how do you think about – the operators are thinking about their contractor selection in Mexico? Are they kind of importing kind of their preferred providers from the U.S.

or internationally? Or kind of just any color around that would be helpful?.

All right. I'll take that first and then maybe I'll let Carey add a little bit more color on some of the practicalities. So firstly, I mean I think there were a couple of key capitalistic markets for helping in the recovery here. One of them is Mexico, the other one is Brazil.

And we've mentioned this before, primarily because the legal and physical conditions are changing there and allowing more international capital to come in. And unblocking the constraints that have existed of having one major national operator. And so I think over time both those markets are going to become important during the recovery.

Neither is going to be just – instantaneously and drastically affect 2017. Both of them are going to be a bit slower burns. But they are going to over the next couple of years begin to take in more floaters.

With respect to the last part of your question on what we're seeing, is certainly the customers that we're talking to do have a preference to use the international drilling companies that they work with and have an ongoing relationship with. And that is one of the things that has allowed us to go in with the ENSCO 8503.

I think it's probably a little bit different for jackups. But we've even had a lot of conversations with clients who work on the U.S. Gulf of Mexico side that going into Mexico now that would ultimately like to take companies like us with them. They may end up using local companies, but that's the tenor of the conversation..

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

Okay. Understood. I appreciate that. Thank you..

The next question comes from Ian Macpherson of Simmons. Please go ahead..

Hi, thank you. Congratulations on the fresh four-year extension on the ENSCO 92. I know there's a reason why day rates are becoming more private now. And I won't be so brash as to ask you to tell us your private day rates.

But when you – when we look at the ENSCO 92, when we look at the ENSCO 106, can you help us understand your strategy for bidding long-term contracts? Are they fixed rates for these multiyear programs? Are they variable? Are they performance linked? Or are – is there an index? Can you provide any color around these recent pictures?.

Yeah. A little bit but without as you say going – we've made the decision on the fleet status report now to not issue pricing and day rates on an ongoing basis. And maybe if I just add a little bit more to that, I think very clearly we're in a very competitive market condition and pricing is quite a sensitive issue.

So we've decided to do that for competitive reasons. But I think the other is that all with – I think what we're doing is really formalizing and making it just very clear on a go forward basis, what is starting to become a pretty normal practice now amongst certainly a lot of our peer group.

And rather than selectively picking and choosing some contracts to announce and some not to. And allowing then there to be speculation about why we've disclosed some and not others, we just decided to be systematic and consistent.

Now with respect to our bidding strategy on the jackups, I think that we are quite prepared to put some of our rigs away on long-term contracts. Certainly where we think that the day rate is still appealing for us at – over those long durations. And where we think they're working with key customers in key basins.

And what we will do is we run a bit of a portfolio approach, so having locked away a few on longer-term contracts, we wouldn't do that on every single rig. But I think you should view this as a bit of a portfolio approach.

And having some of our rigs on good long-term contracts, which are cash generative, I think at this stage of the cycle is something we're happy to do. And in this particular case we've been working – the ENSCO 92, we've been working for this customer for three decades in the North Sea.

We have a very strong ongoing relationship with them and a very strong confidence that this will be an important client for us and a profitable relationship. Now the nature of our contracts all are slightly different. We have some that are just flat day rate. We have others that tier over with each year. And we have some that have a performance element.

So unfortunately I can't give you a clear cut, because every one is slightly different. But I can tell you this. We're not in the mode of locking away a rig for a four- or five-year contract if we think it's not going to be making a contribution..

Got it. I think that answered the question. And then with regard to the third and potentially a fourth mooring upgrade for the ENSCO 8500s. You make the case that you're getting a reasonable payback on those investments, based on the day rates that are available to those rigs right now.

Or should we think of that as more of a long-term investment and something that improves your utilization profile through the trough?.

I think it's the latter. It's a long-term improvement and adding flexibility to the rig. I think we have been very pleasantly surprised by the client response to that and the number of opportunities that it opens up. Now clearly at the moment it's a very low day rate environment.

But we think that as we go forward what this will do is it will provide a market niche for some of our ENSCO 8500s that other rigs can't easily compete in. And where we're not going head to head with the drill ships.

It increases the demand for the type of work that we think that they will do in the future, which is to do a lot of work around existing infrastructure, where they're going to be drilling infill wells, step-out wells, re-entry onto wells on existing deepwater assets.

And we think that that's going to be an important part of the market going forward and one of the areas that will recover earlier in (52:21) the floater segment. Because I think what we are quite clearly hearing from our customers is that they're going to prioritize investment around existing basins and existing blocks.

And they're going to put money back to where they have existing producing assets, because the incremental barrel costs there are much lower than the new development. And so I think you should view this as us making a more long-term investment in the future of the ENSCO 8500 series rigs.

And trying to place them to a very specific market demand that we think is going to be building..

That makes sense. Thanks for the color, Carl. I'll turn it over..

Thank you..

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

Hey, thank you, and good morning or good afternoon.

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

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

And so if you were to run a delta on that, that's not only that. But that's the material part of the difference that you see in a quarter-over-quarter in that guidance..

Yeah. What I would add, that if you – it may have been a little bit buried in the statements, but a relatively important factor is that in Q1, we expect to go up – our utilization, our average utilization across the fleet to go up from 51% in Q4 to 57% in Q1. So we are seeing – so some of the cost increase is actually just activity based CD&E.

And the other is as we said is some preemptive preparation for – well, some of it is actually rigs starting those – the investments we're making to get those rigs ready to work. The other is a little bit of preemptive work, because we are seeing generally a little bit of a pickup in our utilization. And we want to have rigs ready to move on that.

And to that end, a point I was going to make earlier is just that we have taken a series of fleet rationalization decisions in the past in 2016. But I think we are very much out of the mode of preservation stacking now.

I think from what we see in the market, any rigs, any of our core fleet that comes off contract now, we are going to be keeping it warm stacked, ready to go back to work at this point, unless we were to see a material step down in the market conditions or a major fall off in commodity price. That's very much the mode we're in..

I appreciate all that color. So just quickly regarding your comment about the preemptive costs for potential startup.

Is it fair to ask if that first half cost guidance, if there's any allowance for the reactivation of a preservation stacked rig or two?.

Sorry. I'm not quite sure we follow..

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

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

Great. Thank you very much..

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

Thanks. So just to follow up on that a little bit. You've obviously taken a lot out of the cost structure the last couple years.

And this, I'm sure, isn't the first time I've asked you this, but is the signaling in your prepared remarks on that first half guide basically saying on a per rig basis, we've bottomed in terms of OpEx reductions? I mean that would seem consistent with your view as you just stated with the preservation priority versus now the hot stacks.

Is it fair to say that we've perhaps hit bottom on that per rig basis for OpEx?.

I think on an operating basis, yes, we're probably pretty close. I won't say we've driven out every little bit. And we're still working on some other ways to reduce some of our support overhead cost and so the operating cost. But I think you shouldn't expect major reductions going forward further on an operating basis.

And on our CD&E, our CD&E going forward is going to be very dependent on how many rigs we have operating and what our utilization is. So if our utilization starts to come back up, you will see CD&E go up accordingly, because we will have more operating rigs. I think – I hope that answers where you were going..

Yeah..

So first, I think there are two things at play at the moment, as we look at our CD&E. The first one is that we are seeing the continuing effect of actions we took in 2015 and 2016 that really – where we changed and cut our support structure costs and our structural elements across the whole company.

And some of that is still playing out as we go through the next couple of quarters. Because we took some cost actions in 2016, where we still aren't seeing the full effect yet.

What is offsetting that a little bit is, as we start rigs back up and our utilization comes back up, then we have a corresponding offset in just the actual operating cost of running a rig..

Exactly. Okay. No, that's very clear. And then just one last one on the DS-10.

I was just curious if you could maybe give us a little peak into the decision tree, as you're thinking about the choice in terms of the duration of the delay, alternative options, stacking? Just curious how we think about – how that thought process unfolded?.

I think first and foremost, what we've looked to do is reduce our ongoing cost over the next kind of year or so, of having the rig at the shipyard. And we've ended up with an agreement that has reduced that cost versus what we would have incurred if we'd have taken it ourselves. On the duration I don't think you should read too much into that.

It's partially just a mutual agreement we came to with the shipyard. We are still marketing that rig. And I know this may seem strange in the current market environment. But given that it's one of the most capable drill ships in the global fleet, we still have had client interest in that rig. So we're continuing to market it.

And our hope and intent is still that we can bring it out before the official delivery date at the beginning of 2019..

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

The next question comes from Colin Davies of Bernstein. Please go ahead..

Good morning. Yeah, just reflecting on some of the prepared remarks and comments for the Q&A. And a noticeable change of tone. So just thinking about your earlier comments around industry rig scrapping and particularly potential further candidates within the Ensco fleet.

Are there still sort of a prioritized list there, that might move to scrap, they come off contract? Or can I take from your comments that the thinking within Ensco now is to really hold most of that portfolio for the turnaround in the market?.

I think – well, first of all largely we – as we've gone through this cycle, we guided very clearly to rigs that we think are not in our core fleet. And we have pulled those off into held for sale or discontinued ops. And we have – and as they become idle that we have announced that we intend to scrap them or sell them.

So for example in the floater fleet, ENSCO 5000, ENSCO 5001, ENSCO 5002, ENSCO 6000, ENSCO 6003. So there's a list of rigs that we have – and DS-1 and DS-2 and ENSCO 7500. We have clearly said that we will remove them from the fleet when they came available.

The others within our floater fleet I think that we are very comfortable with where we sit today. And we intend to keep that floater fleet as our core fleet.

On the jackups there are a few of our old jackups that we will assess as they come to the end of their contracts on the cost of any SPS or renewal versus what we expect for renewal rates or extension rates. And we will make some decisions at that point. But largely the fleet structure that we have – we – is that we're comfortable to go forward with.

And we have – and the what – we've very clearly indicated the rigs that we have been removing..

That's very helpful, thanks. And then just to change to tack slightly. You'd mentioned through the Q&A and the remarks as well around a pickup in tender activity and inquiry activity. And obviously you said the jackup activity is stronger. But you did say I think that you are having more conversations around floater opportunities.

I'm intrigued where that's coming from in light of lower CapEx amongst the IOCs.

Are you seeing a pickup more in sort of NOCs and independents rather than the IOCs?.

We're seeing a mixture. But I would go back to what I said, which is that the macro trend is still for utilization on the global fleet to drop through 2017. The number of inquiries that we've seen and tenders coming out is a step up than we saw through 2016 and 2015. But that's coming off an extremely low base.

And the number of inquiries we've seen are not enough that we have seen to offset the number of deepwater rigs which will have contracts ending this year. So that's important to put in context. Now what we have seen is Brazil, we've seen a number of new inquiries and tenders coming out for Brazil.

We've seen a few shorter term ones around Africa, around East and West Africa. And we're seeing one or two in Mediterranean and Asia..

Okay. That's very clear..

I think one of the big differences is that where in the jackup market, we've seen an increase in activity and duration of contracts being offered. It's the opposite in drill ships. In the average duration of a drillship contract that is out and being tendered now is lower than it was a year ago.

So we're seeing a lot of shorter duration contracts come out. And some of that is customers taking advantage of current pricing to do certain bits of activity, where they have to do it or they already have the capital committed.

The other thing that's coming to play is that a lot of people have announced flat or slightly lower E&P spending in the offshore in 2017. But because the cost and supply chain basis is a lot lower, in some cases that's flat activity..

Interesting, yeah, yeah. That's very helpful. Thank you..

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

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

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