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Section 1: 425 (425)

 

Filed by Ensco plc

Pursuant to Rule 425 under the Securities Act of 1933

and deemed filed pursuant to Rule 14a-12

under the Securities Exchange Act of 1934

 

Subject Company: Atwood Oceanics, Inc.

Commission File Number: 001-13167

 

 

TRANSCRIPT

 

The following is a transcript of the second quarter 2017 earnings conference call held by Ensco plc (“Ensco”) at 10:00 a.m. Central time on July 27, 2017. While every effort has been made to provide an accurate transcription, there may be typographical mistakes, inaudible statements, errors, omissions or inaccuracies in the transcript.  Ensco believes that none of these inaccuracies is material. A replay of the recorded conference call will be accessible for a limited time through Ensco’s web site at www.enscoplc.com.

 



 

75325_Ensco_20170727_1100AME Earnings Conference Call 2Q 17

Chad, Nick Georgas, Carl Trowell, Carey Lowe, Jon Baksht, Greg Lewis, Ian Macpherson, Praveen Narra, Blake Hancock, Haithum Nokta, Colin Davies

 

Chad, Operator:                                                        Good day everyone and welcome to Ensco PLC’s Second Quarter 2017 Financial Results conference call. All participants will be in a listen-only mode. Should you need assistance, please signal our conference specialist by pressing the star key, followed by zero. After today’s presentation, there will be an opportunity to ask questions. To ask a question, you may press star then 1 on your telephone keypad. To withdraw your question, please press star, then 2. Please note this event is being recorded. I would now like to turn the call over to Mr. Nick Georgas, Director of Investor Relations, who will moderate the call. Please go ahead, sir.

 

 

Nick Georgas:                                                                    Welcome everyone to Ensco’s Second Quarter 2017 conference call. With me today are Carl Trowell, CEO; Carey Lowe, our Chief Operating Officer; John 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 define risk factors and other events that could impact future results.

 

Also, please note that the company takes no duty to update forward looking statements. During this call we will refer to GAAP and non-GAAP financial measures. Please see the earnings release on our website for additional information. As a reminder, we issued our most recent fleet status report on July 20th. An updated investor presentation is also available on our website. Now, let me turn the call over to Carl Trowell, CEO and President.

 

Carl Trowell:                                                                          Thanks, Nick and good morning everyone. Before Carey takes us through our recent contract awards and Jon gives an overview of our financial results, I will discuss some key developments since our last earnings conference call, starting with an update on our planned acquisition of Atwood. We received U.S. antitrust regulatory clearance in June, and integration teams continue planning for a smooth transition. As is customary in these types of transactions, we are working with the SEC to respond to their comments on our merger proxy. And following Ensco and Atwood shareholders meetings to approve the transaction, we expect to close later this quarter.

 

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While oil prices have declined since the announcement of our planned acquisition, we remain committed to the transaction for several reasons. By acquiring Atwood, we significantly enhance the drilling capabilities of our floaters and refresh our jackups. Atwood has four best-in-class drillships that we believe will be the type of rigs that go back to work first as market conditions improve. These drillships have features such as dual derricks, and two BOPs that create efficiencies for customers as they complete deepwater projects. And we expect future customer demand will be highest for rigs that offer these capabilities.

 

Additionally, Atwood’s versatile semisubmersibles have established themselves by d delivering high levels of operational performance to customers, and their jackups are well suited for opportunities that are developing during the early stages of the shallow-water recovery that is underway.

 

Furthermore, we expect to recognize significant synergies from the transaction. We anticipate run rate expense synergies of $65 million on an annual basis beginning in 2019, and $45 million of synergies in 2018. After adjusting for approximately $100 million of transaction costs, we calculate that these synergies create more than $400 million of present value at a 10 percent discount rate. As we have learned more about the Atwood organization during integration planning, our confidence in these synergy targets and transaction cost estimates has increased. And as a result, we believe this transaction creates meaningful value for shareholders.

 

Finally, we evaluated different scenarios as we considered the acquisition, including a scenario where material pricing power for floaters does not return until after 2020. And in each scenario the transaction was accretive to Ensco shareholders on a discounted cash flow basis. For these reasons, we believe that the proposed acquisition of Atwood is compelling for Ensco shareholders and we look forward to completing the transaction.

 

Upon closing the transaction, our fleet management strategy will shift in light of the new composition of our rig fleet. First, we will further rationalize legacy Ensco assets and we expect to retire several rigs over the next three years given the refresh that the acquisition will bring to our fleet. Second, we will be highly selective in reactivating rigs until market conditions and pricing improve. After closing, winning new work for Atwood’s delivered

 

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floaters will be our top priority so that we position these assets for the eventual market upturn

 

Third, further enhancements to our floater fleet will be limited. At this time we expect to upgrade ENSCO DS-7 with a second BOP in anticipation of work beginning in the first quarter of 2018. Coupled with the rig’s dual activity capabilities, this upgrade will improve the marketability of the asset over its useful life. Since we already have a spare BOP in inventory, we expect this cost will be less than $10 million.

 

We may incur additional capex for ENSCO DS-9 in the event that we contract the rig, or if we elect to put a managed pressure drilling kit on another drillship. But our investments to date have already positioned our drillships among the most capable ultra-deepwater rigs in the market. Coupled with our highly competent crew and enhanced operational and safety systems these high-specification assets solidify our position as a key service provider for offshore customers globally.

 

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

 

Returning ENSCO DS-7 to the active fleet for a short-term job also positions this rig for follow-on work that we expect will increase its utilization during 2018. Among our jackups, multi-year contracts for ENSCO 120, 110, and 102 in strategic shallow-water basins have added backlog and improved future utilization. We have also continued to reposition our premium jackups into markets where the current supply is older and less capable. This includes our decision to move ENSCO 109 to West Africa and ENSCO 104 to the Middle East, and more recently our decision to move ENSCO 102 from the North Sea to the U.S. Gulf.

 

We expect that the recovery in the offshore sector will be prolonged and phased, and bridging our assets to better market conditions has been a priority over the past year. We expect that active, high-specification rigs which can provide efficiencies for customers’ drilling programs and are operated by drillers with

 

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enhanced operational and safety systems will be the rigs that win contracts as the market recovers. As utilization for this subset of global supply improves, we believe these rigs will be the first to see increasing pricing power.

 

More broadly, the market cycle continues to play out as expected. Established offshore drillers are winning a disproportionate amount of new work, and there is a bifurcation amongst offshore drillers as larger customers are focusing on a select group of service providers.

 

While recent volatility in commodity prices could present challenges at the onset of customers’ 2018 budget season, we continue to see signs of improvement in customer activity. New contract awards and inquiries for future work have increased year-to-year, albeit off a very low base, and more projects have reached final investment decision sanctioning this year than did for all of 2016, providing a pipeline for future offshore work in the years ahead.

 

While customer activity has increased, market conditions remain extremely challenging and we are in the midst of a sector-changing downturn. And we expect this will reconfigure the offshore drilling industry. We anticipate that the recent trend of customers contracting rigs with established, well-capitalized drillers that have the technology, systems, scale, and diversification to help customers lower their development costs while persevering through the industry cycle will continue. We believe that offshore drillers must adapt to this new reality or they will be competitively disadvantaged and, in certain cases, obsolete.

 

Therefore it is incumbent upon our management team to best position Ensco for this new reality. By acquiring Atwood and investing to enhance our own fleet, we significantly improve our assets and technology, bettering our ability to meet customer requirements when demand returns to higher levels in the future. In the interim, we remain focused on delivering high levels of operational uptime and safety performance to customers so that we continue to win new contracts to keep our rigs ready to capitalize on improving market conditions. Now, I’ll turn the call over to Carey.

 

Carey Lowe:                                                                          Thanks, Carl. Since our first quarter earnings call, our offshore

 

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crews and onshore personnel have stayed focused on delivering high levels of operational uptime and safety performance to our customers. Operational utilization was 99% in the second quarter, in line with first quarter levels and our safety metrics are tracking better than last year’s record results.

 

We recently secured new work in several regions … including three drillship contracts. In total, we have added approximately 19 rig years of backlog year-to-date. Ensco ranks first among all offshore drillers in new contracts during this time period, capturing approximately 20 percent of total rig years awarded industry-wide.

 

Starting in West Africa, ENSCO DS-4 is expected to commence a two-year contract offshore Nigeria in August, with an option for one additional year of work. This contract award is highly significant, as it marks the first time we have reactivated a drillship since the start of the downturn, demonstrating our ability to win work for preservation stacked rigs ahead of competitors’ rigs that are active or warm stacked. The rig is well-suited for the customer’s needs and is outfitted with dual derricks. In addition to the rig’s capabilities, our detailed reactivation plans contributed to winning this contract.

 

We activated DS-4 on time and within the previously announced cost guidance for returning a preservation stacked floater to the active fleet. Additionally, this process validates our stacking and reactivation procedures. We believe that as we move through the cycle we will be able to do the same for our remaining preservation stacked rigs.

 

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

 

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

 

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rig of ENSCO DS-8, which is also operating offshore West Africa and has consistently delivered high levels of operating performance since commencing its initial contract in fourth quarter 2015.

 

These contracts also underscore the importance of having a strong local partner in the Nigerian market. By forming a partnership with OES, a local drilling contractor with rigs operating in country, we have improved our ability to meet customer needs offshore Nigeria through our joint venture ODENL. And we believe our partnership better positions our rigs for follow-on opportunities in Nigeria.

 

In addition to these contracts, ENSCO DS-7 will return to work to complete a short-term project with its existing customer offshore Ivory Coast, with an expected commencement date in August. This allows us to return DS-7, which was previously warm stacked, to an operational state in advance of anticipated work beginning in first quarter 2018.

 

In the Middle East, ENSCO 110 has been awarded a three-year contract in Qatar. The Middle East has been the most resilient market for jackups during the downturn, and we have a strong reputation with customers in the region as evidenced by our No. 1 rating for total satisfaction in an independent industry survey.

 

Moving to the North Sea, ENSCO 120 received customer approval to commence its three-year contract. Also in the region, ENSCO 121 and ENSCO 122 secured new contracts that will keep each rig busy into first quarter 2018. ENSCO 102 has been awarded a 400-day contract in the U.S. Gulf of Mexico that is expected to start in November, and the rig is currently mobilizing from the North Sea in advance of this contract.

 

Among our floaters in the Gulf of Mexico, ENSCO 8503 recently drilled the Zama-1 prospect offshore Mexico, the first offshore exploration well drilled by the private sector in the country’s history which resulted in a world-class discovery. The customer has chosen to extend the contract for two months of operation on the U.S. side of the Gulf of Mexico starting later on this year. ENSCO 8505 has been contracted for short-term work and we are actively marketing the rig for follow-on opportunities.

 

Finally, ENSCO 52 completed operations in Malaysia and was

 

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classified as held-for-sale. ENSCO 56, 90, and 99, all previously classified as held-for-sale, were sold and will be scrapped. ENSCO 86 was sold to an operator, effectively removing the rig from the competitive supply.

 

Turning now to the broader rig market, the number of new contract awards for floaters globally has increased over each of the past four quarters. Tenders and inquiries, a leading indicator for new contract awards for shallow-water work, have continued their recent upward trend compared to a year-ago. Project sanctioning has also increased, including three deepwater projects that were approved in the second quarter alone.

 

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

 

On the supply side of the market, 78 floaters and 32 jackups have been retired since the start of the downturn. We see another 65 older, less capable floaters and 155 jackups as candidates to be retired over the next 18 months. While retirements have slowed lately, we believe much of this attrition is occurring silently, as companies have no incentive to announce when they no longer plan to return a rig to the active fleet, particularly for jackups, given their lower stacking costs. We expect that deliveries of un-contracted new builds will continue to be delayed until demand recovers.

 

In closing, Ensco continues to capture an outsized share of new contracts awarded in a highly competitive market. This stems from consistently delivering the highest levels of service quality and operational excellence to our customers. At the same time, we have invested in our assets and technology to improve the drilling process and create efficiencies for offshore projects, helping to set Ensco apart as the driller of choice with customers. Now, I’ll turn it over to Jon.

 

Jon Baksht:                                                                               Thanks, Gary. Today I’ll cover second quarter 2017 financial results, our outlook for third quarter, and a summary of our financial position including our capital expenditure outlook for the remainder of the year. Starting with second quarter results versus

 

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prior year, a loss of $0.15 per share compared to earnings per share of $2.04 in the year-ago period.

 

As detailed in our press release, several items influenced these comparisons, including $10 million related to the settlement of a previously disclosed legal contingency arising from a customer dispute that was included in second quarter 2017 contract drilling expense; $6 million of discrete tax expense included in the second quarter 2017 tax provision; $4 million of transaction costs related to the proposed acquisition of Atwood included in second quarter 2017 G&A; a $261 million gain included in second quarter 2016 other income, related to the repurchase of senior notes; and $205 million of early contract termination settlements included in second quarter 2016 revenue.

 

Excluding these items, an adjusted loss of $0.10 per share compared to adjusted earnings of $0.51 per share a year ago. Total second quarter revenue was $458 million versus $910 million last year.

 

In the Floater segment, revenue was $264 million compared to $636 million in second quarter 2016. Revenue in the year-ago period included $205 million of early contract termination settlements for ENSCO DS-9 and ENSCO 8503. Fewer rig operating days led to a decline in reported utilization to 43 percent from 57 percent a year ago. And the sale of ENSCO 6003 and 6004, both of which operated during second quarter 2016, also contributed to lower year-to-year revenues. Finally, the average day rate for floaters declined to $339,000 from $360,000 in second quarter 2016.

 

Operational utilization for the floater segment, which adjusts for un-contracted days and planned downtime, was 99 percent, equal to a year ago.

 

In the Jackup segment , revenue was $179 million compared to $251 million a year ago, due to fewer rig operating days and a decline in the average day rate to $89,000 from $112,000 last year. While the total number of operating days declined, reported utilization increased by one percentage point to 64 percent, due to the retirement of several jackups since last year.

 

Operational utilization for the jackup fleet was 98 percent

 

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compared to 99 percent a year ago. Total contract drilling expense declined to $291 million in second quarter 2017 from $350 million a year ago, as lower personnel and other activity-based costs due to fewer rig operating days more than offset expenses related to contract preparation costs for rigs returning to work and the settlement referenced earlier. Depreciation expense declined to $108 million from $112 million a year ago due to the extension of useful lives for certain contract.

 

General and administrative expense increased to $31 million in second quarter 2017 from $27 million a year ago, due to $4 million of transaction costs for the proposed acquisition of Atwood. Interest expense in second quarter 2017 was $60 million, net of $14 million of interest that was capitalized, compared to interest expense of $54 million in second quarter 2016, net of $13 million of interest that was capitalized. The increase in interest expense is largely due to the convertible notes issued in fourth quarter 2016, partially offset by debt repurchases.

 

As mentioned previously, second quarter 2016 other income included a $261 million gain on the repurchase of $940 million of senior notes at an average discount of approximately 27 percent. Tax expense declined to $19 million in second quarter 2017 from $37 million a year ago due to lower profitability.

 

Now, let’s compare Second Quarter 2017 to First Quarter 2017 sequentially. Revenue declined 3 percent due to a two percentage point decline in reported utilization, and a slight decrease in the average day rate as ENSCO 5004 was placed on a standby rate for a portion of the second quarter. Contract drilling expense increased $13 million sequentially, primarily due to the following items: $10 million of higher costs for jackup surveys, shipyard projects and scheduled repairs, and a $10 million settlement that I mentioned earlier.

 

This was partially offset by lower reactivation costs for the ENSCO DS-4 and reduced costs for the ENSCO 5004 while the rig is on standby. Excluding the settlement I just mentioned, contract drilling expense for second quarter 2017 was slightly higher than our prior guidance range, primarily due to DS-7 re-activation expenses in advance of a new contract that will return the rig to operation. This work and the related re-activation expenses were not contemplated in our prior guidance.

 

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Reactivation costs for ENSCO DS-4 are expected to total $28 million, in line with our prior cost guidance for returning a preservation stacked floater to the active fleet. Approximately $18 million of these costs have been included in contract drilling expense to date, and we anticipate the remaining $10 million will be incurred over the next few quarters as we refurbish spare parts that were used in the rig’s reactivation. In terms of the rig’s total reactivation costs approximately $6 million was for de-preservation and $22 million is deferred maintenance that would have been incurred if the rig had remained warm stacked.

 

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

 

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

 

We expect third quarter contract drilling expense will be between $295 and $305 million. The increase in contract drilling expense is primarily due to contract preparation costs for ENSCO 102 before the rig commences a contract in the U.S. Gulf of Mexico later this year; higher maintenance costs as jackups complete surveys and shipyard projects; a partial quarter of operations for ENSCO DS-7, which will result in higher daily costs; and the refurbishment of spare parts. These increased costs will be partially offset by a $10 million decline related to the settlement of a customer dispute during the second quarter.

 

The third quarter is somewhat unique, in that we have four jackups undergoing surveys during the quarter combined with higher spare refurbishment activity and contract preparation costs. We expect that contract drilling expense will decline from third quarter levels to approximately $275 to $280 million in the fourth quarter. Excluding transaction costs related to the proposed acquisition of Atwood, G&A expense is expected to decline by $2 million

 

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quarter to quarter, primarily due to the timing of certain annual incentive-based grants.

 

We anticipate that interest expense will decline to approximately $48 million from $60 million in the second quarter, primarily due to increased capitalized interest as we prepare ENSCO DS-10 for its maiden contract.

 

We expect our third quarter tax provision will be approximately $19 million. As I mentioned on our prior conference call, we are likely to incur income tax expense in periods where we operate at a loss. Please note that the third and fourth quarter guidance I just reviewed is for Ensco only, and does not include any impact from the proposed acquisition of Atwood.

 

Turning now to a summary of our financial position, as of June 30th, cash and short-term investments totaled $1.9 billion. We also have a fully available $2.25 billion revolving credit facility available through September 2019; $1.13 billion of which is available from September 2019 to September 2020.

 

In addition to this liquidity, we have $3.3 billion of contracted revenue backlog in line with our backlog at the end of the previous quarter. Year to date, we have added more than $600 million to our backlog, or approximately 20 percent of rig years awarded globally during this time period. We believe that we will continue to see a flight to quality as customers award more work to offshore drillers with established operational and safety track records and strong balance sheets. Additionally, we believe that our recent contract wins position us well for follow-on opportunities, bridging our rig fleet to better market conditions.

 

During the second quarter we opportunistically repurchased approximately $190 million of debt, maturing between 2019 and 2021 on the open market and we now have less than $1.0 billion of maturities before 2024.

 

Moving to our capital expenditure outlook, we expect total capex for the second half of 2017 to be approximately $300 million, inclusive of $210 million of new rig construction costs, primarily due to the recently announced contract for ENSCO DS-10.

 

Remaining capital expenditures for the rig are expected to total

 

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approx. $190 million, inclusive of a $75 million final milestone payment to the shipyard; $35 million of capitalized interest; a second seven-ram blowout preventer and other customer-requested upgrades; mobilization from the shipyard to Nigeria; plus customer acceptance testing upon arrival in Nigeria.

 

We expect to incur $170 million of these costs in the second half of 2017, with the remaining $20 million occurring in the first quarter of 2018.

 

In addition to new rig construction, capex for rig enhancements and minor upgrades is expected to total $90 million for the remainder of 2017. This includes $10 million of remaining capital for the reactivation of ENSCO DS-4; the proactive purchase of a modular MPD package that positions us for upcoming contract opportunities, as well as other customer-specific upgrades.

 

Our capital expenditure outlook for the balance of the year may increase if we are successful in contracting additional rigs. These targeted investments better position our fleet to meet future customer demand as we expect that active , high-specification rigs owned by established offshore drillers with enhanced operational and safety systems and financial strength will be the most competitive in winning future contracts even if the market remains tight.

 

Finally, I will provide some further detail on our planned acquisition of Atwood. As mentioned in our press release, integration planning is well underway and we expect the transaction to close during the third quarter. We estimate that we will achieve $45 million of expense synergies in 2018 and run rate synergies of $65 million on an annual basis beginning in 2019. We expect to achieve these synergies primarily through the consolidation of offices and shore-based headcount.

 

Atwood’s onshore support costs total approximately $85 million on an annual basis, including $50 million of G&A expense and another $35 million of costs classified as contract drilling expense. Certain corporate support costs including Engineering, Supply Chain, and Asset Management are generally charged to contract drilling expense along with onshore support costs incurred in field offices that directly support operations.

 

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Since we expect to support our combined fleet using Ensco’s existing support structure, we believe that $65 million of synergies is an achievable target and we will continue refining our estimates as integration planning progresses. There may be other operational and fleet management synergies that lead to improved utilization in the future, but these benefits have not been included in our synergy targets.

 

As of March 31st, Atwood’s balance sheet included more than $400 million of cash on hand, an outstanding revolver balance of $850 million, and approximately $450 million of 2020 senior notes. We expect to repay the outstanding balance on the revolver using a portion of Ensco’s cash upon closing. We also anticipate that the 2020 senior notes, which have a put option on change of control, will be retired.

 

Adjusting for these debt payments, Ensco’s pro forma liquidity would be more than $3.2 billion, including $1.0 billion of cash, with less than $1.0 billion of debt maturing before 2024. Following the delivery of ENSCO DS-10, remaining pro forma new build capital commitments to the shipyard, excluding customer acceptance testing, mobilization and capitalized interest costs would be approximately $495 million. We would also maintain the option to extend final payments totaling $250 million for two Atwood drillships to late 2022.

 

In closing, our financial strategy entering the downturn was focused on extending our runway, reducing debt, managing cash outlays, and increasing our liquidity. We successfully strengthened our balance sheet and improved our competitive positioning to prepare the company for a protracted recovery in the offshore sector. Our financial strength has given us the flexibility to evaluate a variety of investment opportunities.

 

We have leveraged this position to pursue the acquisition of Atwood and make targeted investments in our assets, technology, systems and processes that will significantly enhance our fleet so that we can better meet customers’ drilling requirements in the future.

 

I’d like to also note that when evaluating the acquisition of Atwood, we considered the combination through scenarios that ranged from a more rapidly rebounding environment to an even

 

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longer and protracted recovery than we are expecting. Irrespective of the market environment, we believe the acquisition is accretive on a discounted cash flow basis, inclusive of synergies expected to create more than $400 million of present value at a 10 percent discount rate.

 

While we have pursued these counter-cyclical investments, we have maintained strong liquidity and manageable debt maturities, giving us the financial wherewithal to bridge the company through to better market conditions. We will preserve our financial flexibility through prudent liquidity and liability management as we navigate industry cyclicality with a focus on delivering the highest return to our shareholders. Now, I’ll turn the call back over to Nick.

 

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

 

Chad:                                                                                                              Thank you. We will now begin the question and answer session. To ask a question, you may press star then 1 on your touchtone phone. If you are using a speaker phone, please pick up your handset before pressing the keys. To withdraw your question, please press star, then 2. At this time we will pause momentarily to assemble our roster. The first question today will come from Gregory Lewis with Credit Suisse. Please go ahead.

 

Gregory Lewis:                                                               Yes, thank you and good morning, gentlemen. Carl, could you talk a little bit about the reactivation of the DS-4 and how that opportunity came to happen? And really I’m just trying to understand, I mean this was a preservation stacked rig. I think one of the big themes in the sector has been the ability of hot rigs to win work as opposed to stacked rigs, and I’m just trying to understand what enabled the DS-4 to be reactivated and really when that work, which is a nice solid to your contract.

 

Carl Trowell:                                                                          First of all, at a high level Greg, I think what you should view is the positioning we’ve done of some of our rigs, DS-4 included, and DS-10 has been because we have decided that we want to have the right rigs working in the places with the right clients. And that positions us well for what we expect to be an increasing level of activity as we go forward over the next couple of years. And as we said going back a couple of quarters, we will be prepared to invest to put rigs into key markets, but once they were there, we expected them to be cash generative. And that is true of the contracts that we

 

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announced for the drillships recently.

 

With respect to DS-4, I think we also came to the idea that on a balance portfolio basis, we actually would like DS-4 to be out and active because it was a very competitive rig, and that we would keep then DS-3 and DS-5 in preservation stat. So a little bit more on that award, it was a competitive award. It wasn’t directly negotiated and DS-4 did win the work against hot rigs. And I think when we decided we would stack rigs and certainly preservation stack of them, we said at that time that we felt we could be competitive bringing them out against other rigs. And I think we’ve proven that.

 

And part of that was we took upfront investments to make sure that the rigs were very well preserved against a series of very carefully planned procedures, that we had already a detailed procedure for bringing them back that we were able to demonstrate to the client; and that we were able to put the rig back to work as it would be and to the level that it would have been, if it had been warm stacked within the time duration. So I think we are very pleased to have that rig back working. And as we said, once it gets to Nigeria we expect to be generating cash for the business once it’s there.

 

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

 

Greg Lewis:                                                                                 Okay, great. And then you touched on it in your prepared remarks about the pending acquisition of Atwood. I noticed in the 10Q this morning about some potential lawsuits against Atwood and regarding the merger. Does that have any impact in the timing of the potential closing of the deal? I’m just trying to understand it. I see these things in the Q; I’m just trying to understand is that sort of normal course of any M&A transaction, or is that… I’m just trying to understand. And those were against Atwood, not Ensco, correct?

 

Carl Trowell:                                                                          Yes. Greg, these are within the normal scope and expectation of M&A activity. There is nothing unusual there, nothing that we think is going to delay the process. And they are all from Atwood primarily. One of them does actually name Ensco as a counterparty as part of that deal, partially because of the way the deal structure

 

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is done. But nothing [inaudible] [00:37:58] nothing that we expect is going to cause any problems on the closing of the deal.

 

Greg Lewis:                           Okay, perfect. Thank you very much, gentlemen.

 

Carl Trowell:                         Thanks, Greg.

 

Chad:                                                                                                              The next question will come from Ian McPherson with Simmons; please go ahead.

 

Ian Macpherson:                                                   Hey, thank you. Congratulations on the recent contract wins. I wanted to ask you Carl, or Carey if you care to weigh in, how you think about generating a return for the DS-10, given that you have to spend close to $200 million from here forward to complete the rig, and whether the one year plus five year of customer options provides a basis for getting an acceptable return on approximately $200 million, given where rates are today.

 

Carl Trowell:                                                                          Maybe I’ll take it first and see if Carey wants to add anything. First of all, we have to bear in mind that these are very long-lived assets, and so therefore the returns, we’re not loading the return on the first year’s contract, quite obviously. We think that the investments we’ve made there will make a good return for us for the investment and for the shareholders over the duration — over the next few years and over the life of the asset.

 

The options on that contract in the out-years are priced; are tiered to go up. And I think that if the options were taken, then we would feel relatively pleased on the placement of that rig and at the rates that we would get for it. But we’re not loading everything on the firm contract or the, say, year or two-year option extension.

 

Ian Macpherson:                                                   Okay. I was curious if the different customer options —

 

[Crosstalk]

 

Jon Baksht:                                                                                Ian, just one thing to add just to clarify the capex remaining. So on the DS-10, it’s actually $190 million. The $210 million number I mentioned in the prepared remarks, only a portion of that was the DS-10. And of the $190 million, 35 of that is capitalized interest so really its interest would be paying anyway, so it’s not all incremental cash spend. So just wanted to clarify.

 

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Carl Trowell:                         And also additionally, a lot of those expenses we would have had whenever we brought the rig out.

 

Jon Baksht:                                                                               Right, the customer acceptance testing mobilization; those type of things, too.

 

Ian Macpherson:                                                   Understood, thanks. I was really mainly curious what the mechanisms are of the customer options, if they are variable or on oil price or any other market conditions or if they’re just sort of fixed with some price escalation.

 

Carl Trowell:                         Without going into the exact details of it, they’re not variable on oil; they step up over time.

 

Ian Macpherson:                                                   Okay. And then lastly for me, Carl, you mentioned that pending closing of the deal that filling up Atwood’s fleet would be job one, and that you would be examining more retirements within the legacy Ensco fleet. Could you describe which rigs could fall into that bucket?

 

Carl Trowell:                         No, we’re not going to go into it specifically at this point, Ian. One is because we’re refining that plan; secondly some of those rigs are working on contract with clients. But you should expect as we go forward post closing that we’ll give some more insight into that. But broadly speaking, I think you can fully expect us to retire a few more of our older jackups as we have done recently with ENSCO-52. We are one of the real positives of the Atwood transaction is that it would bring in five highly capable, younger jackups that fit into a real sweet spot that we’re seeing for marketing now at the moment as the jackup market begins to recover.

 

And we would take that opportunity to refresh and renew our jackup fleet, and probably pass a few more of the older ones. A lot of these rigs are — some of our most aged ones — very heavily written down or very low NBV anyway; things that we wrote down a few years ago. So I think that become a relatively straightforward decision. And we will take a look at assessing some of the floaters as well, once we close and we work through this a little bit more. But we’ll give you more news as we refine the plan.

 

Ian Macpherson:                                                   Understood, thank you.

 

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Chad:                                                                                                              The next question will come from Blake Hancock with Howard Weil. Please go ahead.

 

Blake Hancock:                                                        Thank you, good morning guys. Jon, maybe the first one for you here. On the 4Q cost guide, the 275 to 280, can you help us quantify how much reactivation is still left in there; incremental cost that isn’t standard operating cost?

 

Jon Baksht:                                                                               Yeah, there’s a bit in there. Just to provide some broad guidance, because there’s still some variability that could go into it, but in the mid single digits would probably be where I guide you.

 

Blake Hancock:                                                        Okay, that’s perfect. And then the next one, Carey you talked about kind of the growing tenders year-over-year still. Do you get this as a function of the operators are more or less having to start moving forward with projects to kind of meet production targets, 2019, 2020? Or is this more of a function of just the offshore cost structures have come down this much, they might as well move forward with all these assets?

 

Carey Lowe:                                                                          Blake, I think it’s a bit of all of that. Offshore costs have come down. The drilling costs are being reengineered and brought down. The fact that opportunities are there for in-field type work is creating some demand. And the fact that a number of projects had not been sanctioned in the past two years and at some point the oil companies have to start drilling again is causing operators to start making plans to drill and coming out with tenders.

 

Carl Trowell:                         Blake, maybe I can take the opportunity to just give a broader picture about the market on the back of that. So, first thing to say is despite the swoon in the oil price, the dip down and then a little bit of recovery recently, we haven’t actually seen any major interruptions to the tendering activity that we’d seen during Q1 and Q2. Now, in many cases that’s also because a lot of these things were already in process.

 

But we’ve just come off the back of [inaudible] [00:44:55] review of all of our opportunities, new tenders and market conditions here. And I think probably somewhat surprising to everyone out there is actually it’s gone up quarter over quarter, despite the recent downturn in the oil prices.

 

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Now, it’s coming up below base as we said in our prepared statements, and we don’t think that this is leading to a sort of hockey stick recovery by any means. But I think broadly speaking, we feel now that the shallow water has bottomed and in a recovery phase as far as activity is concerned. We think that the next area we expect to see pick up now is in the deeper water around existing infrastructure. So this is types of things like interventions or new subsidy tieback. I think that which will encourage what we are seeing in the market is reflected by some of the commentary from some of the big, major service companies like Schlumberger Cameron, plus FMC. And we think that’s the next area that will pick up a bit.

 

And as far as the deeper water is concern and the flow-to segment as a whole, we don’t think it’s changed from a quarter or two ago, despite the increase in the tenders. We think the number of rigs rolling of contract this year is going to mean that we’re going to see further global utilization fall off in the floater segment. But as we look at ‘18 and ‘19, we are seeing a number of new opportunities come. And interestingly, in the last few months we have seen some new short come work come to the table that didn’t exist and wasn’t on our radar at all three months ago.

 

A lot of this seems to be price response to our customers being able to contract deepwater rigs, plus all of the spread cost services at rate [inaudible] not going to be sustainable for a very long time. And it’s driving some less [inaudible] demand. We have now seen several new tenders for activity in ‘18 on one, two, three well programs around existing infrastructure in the deep water. So that’s the general market conditions. And it’s because of that that we do feel we’re in a bottoming point cycle at different bits for different segments. And it’s why we believe that it’s time to start making some investments for the future.

 

Ian Macpherson:                                                  That’s great. Thank you guys; I appreciate it.

 

Chad:                                                                                                               The next question will come from Haithum Nokta with Clarksons. Please go ahead.

 

Haithum Nokta:                                                       Hey, good morning. Carl, I just wanted to pick up on your last point there. I guess just to kind of confirm, it sounds like despite the oil price weakness over the last call it three months, it hasn’t really been a change in maybe the outlook for opportunities that

 

19



 

may be in the pre tender phase. And has there been a difference at all between how the jackup customers or shallow water customers versus the deepwater customers have reacted to that?

 

Carl Trowell:                         Haithum, not really. Now, it’s maybe a bit early, especially the deepwater. People make decision processes quite a long time in advance and so you don’t see it switch on and switch off so quickly. But I think purely from what we’ve seen, I don’t think we can make a comment that we’ve seen it fall off. I think in the jackup shallow water segment, we’re seeing now quite a lot of customers start pushing projects through for FID and beginning to look at that increased activity level, and partially have adapted to a new reality of both oil prices and cost inputs.

 

And we’ve seen a lot of simplification of projects, a lot of streamlining, and a lot of efficiency built in. And accordingly, I think that oil prices within the range that they have been still support the continued investment in the shallow water.

 

With respect to the deeper water, I think a lot more will rest on the sentiment going into the 2018 planning cycle for a lot of our customers a we get two to three months down the line than the fall-off that we saw over the last quarter as affecting our outlook for ‘18 and ‘19. So I think we probably have more comments to say and more feel of that in a quarter or so, once we understand where the sentiment from some of our big customers is, as far as their planning for ‘18 is concerned.

 

Haithum Nokta:                                                       Appreciate that. And just back to the DS-4 reactivation, and I know you got into it a little bit but is there any particular reason why the 3 and the 5 were not chosen, and it was the 4 that kind of went ahead? I’m curious just on the $15 million that is going to be capitalized; what the nature of those upgrades were and whether or not they’re part of — I think many of us would consider that part of the reactivation but still a little bit on why the 4 and not the 3 or the 5.

 

Carey Lowe:                                                                          Haithum, this is Carey. The tender required a dual activity rig and the DS-4 is dual activity, whereas 3 and 5 are not. So that drove us — one of the reasons it drove us to DS-4. As for the capital upgrades, some [inaudible] [00:50:57] customers have specific requirements, well head connectors, lift frames, coil tubing frames, and so on; equipment related to the completion process. And then

 

20



 

there were some additional tubulars that were required and were contract-specific.

 

Carl Trowell:                         Yeah, and I think the way we viewed this, Haithum, is that there are very much three buckets you can consider for reactivation of a rig. The first one is how much does it really cost to basically deep preserve it or deep pickle it, and actually that’s relatively small on the scale of things; I think it’s on the order of about $6 million. Then there is effectively catch-up on surveys, maintenance, and refurbishment of equipment, which is actually the biggest part, of which most of those costs would have been incurred if the rig had been warm.

 

And then there’s a third bucket which is one that you’re talking to, which is are there any further enhancements, which are not necessarily required to reactivate the rig but either are enhancements for the rig of the future, or required for the contract for the basin it’s going to. And I think in this particular case, we are prepared to make those investments, those additional investments because we think they also add value to the rig in the long term.

 

And we do believe one of the reasons we have picked these contracts with these clients in that area is because we have relatively good visibility to ongoing work led beyond the contract. So we do think that there’s a very good chance that we will continue to work within either Nigeria or that West African market on that type of project.

 

Just as a point to further call out, we are actually declining with the contracts in other places in the world that are shorter duration where the client is requesting what we think is actually completely over specked, or in some cases quite ridiculous upgrades or enhancements to the rig that they expect the contractors to make for what are often quite short term contracts. And we don’t think the investments there are warranted or would be recovered over the life of the rig because they’re often very, very specific to that client or that contract.

 

And in that case, we’re actually no-bidding some of these contracts. And we have c stepped up the number of no-bids we’ve done over the past quarter or two. So we have been very specific about which contracts we will move into and will invest for and

 

21



 

which ones we won’t.

 

Haithum Nokta:                                                       Appreciate that, Carl; very interesting. And just one last quick one: did I hear correctly that the DS-7, there’s potential fall-on work in the first quarter of ‘18 for that as well?

 

Carl Trowell:                         We are anticipating some work, yes. And it’s also why we’re quite pleased to have the rig go back to work for its existing customer to go from its warm stack to fully active status.

 

Haithum Nokta:                                                       Got it. Perfect, thank you.

 

Chad:                                                                                                              The next question will come from Praveen Narra with Raymond James. Please go ahead.

 

Praveen Narra:                                                              Good morning, guys. I guess just sticking to the DS-4 commentary, in terms of the reactivation cost on that, you mentioned $6 million for de-pickling. If we go on further for let’s say cold stacked or preservation stacked for two years and beyond, do you think we would still be able to hold that $30-35 million? I assume the de-pickling goes up but the remainder stays very constant? How do we think about that?

 

Carey Lowe:                                                                          Praveen, this is Carey. The $25-35 million estimate we gave you is good for a five-year timeframe. There’s a point when you don’t have to do any more maintenance; you’re not consuming hours on equipment or increasing the amount of overhauls you have to do, and it kind of flattens out. So we’ve estimated those numbers based on a five-year timeframe.

 

Praveen Narra:                                                              Okay, perfect. And then in terms of the contract on that, you guys mentioned that the two-year contract was something that was important to you in terms of the term. I guess what kind of hurl rate on term would have been acceptable to go through the reactivation process?

 

Carey Lowe:                                                                          Do you mean the duration of the term?

 

Praveen Narra:                                                              Correct. Would you guys have done it for a one-year term along with the potential for follow-on work behind it?

 

Carl Trowell:                         The simple answer to that, Praveen, is yes if it was the right client, right basin with follow-on work, which is sort of what we said.

 

22



 

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

 

Praveen Narra:                                                              Okay, perfect. Thank you, guys.

 

Chad:                                                                                                              The next question will come from Colin Davies from Bernstein; please go ahead.

 

Colin Davies:                                                                       Hello. I just wanted to come back to the deal. You mentioned that you’d run a range of scenarios to test the thesis around the deal. And you mentioned a downside scenario of no pricing power emerging in the rig market. Can you give us some sense and put that in a more macro context as to what kind of oil price environment would you be running at for that sort of downside scenario to still make sense?

 

Jon Baksht:                                                                                Sure, I’ll take a stab at that. And just generally speaking, when we evaluate all investment opportunities, so not just Atwood, we do screen things against many scenarios. And so some more rapidly recovering and some lower for longer, if you will. And so the ones that were in the merger proxy were the two that we relied on for there, but internally we looked at other various scenarios that we evaluated just from a management standpoint. And I can tell you from the lower for longer scenario, we do test fairly bearish scenarios.

 

And so while I won’t pin an exact oil price on there, I think at the lower oil price to translate into recovery, I think the way we would look at it is lower utilization for longer and lower day rates for longer. And that could be loosely coupled to oil price, but you could call it more bearish than the forward strip is today. And the recovery that — if you look in the proxy, the case we showed was various recovery scenarios for jackups and floaters so we also screened it against scenarios that the recovery was further out than those presented.

 

Carl Trowell:                                                                          I think the thing is it’s probably a good point, Colin, to make a broader statement which is that in some ways, we’re less sensitive to a specific oil price in the sense that what we are seeing now is that our clients in the general market is adapting to the new reality offshore of a lower oil price. And we’ve touched on this before of how costs have come down for a lot of offshore development. And

 

23



 

what we’re seeing is a lot of the developments that are coming to the tables are ones which are at the top of the queue and they’re optimized for current oil prices.

 

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

 

Colin Davies:                        Yeah, that makes sense. But just to try and clarify that a little bit more, is that downside scenario still assuming that we continue where we are but the, for example, deepwater economics are able to proceed at a sustained lower cost base?

 

Jon Baksht:                                                                               Sure. And again, it’s a bit loosely coupled. Obviously we have some fairly detailed models that we use, basin by basin and from an activity level standpoint, that activity level turns on and turns off based on oil pries. And then we use that to extrapolate rig demand, and then we look at global rig demand supply against that. And ultimately, then we have some judgment on what that environment would look like from a utilization standpoint and how that translates into data rates.

 

And so to broadly answer; yes, we do look at that. I can’t tell you it’s as precise as I think you might be characterizing because there is some judgment involved in the process. But we do look at it and we do look at scenarios where it translates into more downside than our current day rates reflect, and more downside than the current utilization that we’re experiencing today.

 

Carl Trowell:                                                                          And I’ll use the opportunity to make another broad point, which is that we’ve looked at more aggressive recoveries and slower recoveries than we currently estimate at the moment. But we’re not naïve in expecting there to be a rapid recovery here to make the Atwood acquisition a success. Our belief is that the market will gradually recover over time. We think that the level of investment now three years and possibly going into four years of quite material pullback investment outside of OPEC and onshore U.S. is going to lead to a supply issue.

 

And the longer that goes on, the greater the chance for a

 

24



 

dislocation on the supply side. And there will be, over time, a recovering investment in offshore and the offshore is going to be viable, and especially because the cost base, breakeven cost structure, is coming down. But the future is not going to look like the past. We don’t assume that all of the companies that exist in our sector today are going to exist, and that all the rigs that are working today, or have been working over the past few years, are going to work in the future.

 

And therefore… and there’s going to be a new reality. And we are going to be asked by clients to play a greater role in helping their drilling efficiencies and bringing down costs. And we’re goin to be asked to probably take on some new contracting models, including potentially the integration of other services around our rigs. What we need to do as management is prepare ourselves for that, and make investments at this point in the cycle to be ready for it. And that means having the highest quality fleet, it means investing in technology and innovation, and it means investing in the ability to undertake a different contract model if required.

 

And that’s what we’re doing at the moment. We work within a cyclical, asset-intensive business. And you can argue that the drilling sector has tended to make investments at the wrong point in the cycle, at the peaks. If you’re in that type of business, we need to be looking to make investments that are countercyclical and at the bottom of the cycle. That takes some bravery and it takes some foresight, because that’s exactly when certainties are at the greatest and market sentiment is at its lowest.

 

But that’s where we need to  [inaudible] [01:03:16] on us as a management team to make some decisions and make some investments. And it’s in that context that you should view the acquisition of Atwood and our investment in our fleet, and the continued investment we’re making in technology and innovation that we are going to be rolling out and putting on some of our rigs later this year and the beginning of next year.

 

Colin Davies:                        That’s great; really helpful context. Thank you very much. I’ll hand it back.

 

Chad:                                                                                                               Alright ladies and gentlemen, this concludes our question and answer session. I’d like to turn the conference back over to Nick Georgas for any closing remarks.

 

25



 

Nick Georgas:                       Okay, thank you Chad and thank you to everyone for your participation on today’s call. We look forward to speaking with you again when we report our third quarter 2017 results. Have a great day.

 

Chad:                                                                                                              The conference is now concluded. Thank you for attending today’s presentation. You may now disconnect.

 

[End of Audio]

 

Duration: 65 minutes

 

26



 

Forward-Looking Statements

 

Statements included in this release regarding the proposed transaction, benefits, expected synergies and other expense savings and operational and administrative efficiencies, opportunities, timing, expense and effects of the transaction, financial performance, accretion to discounted cash flows, revenue growth, future dividend levels, credit ratings or other attributes of Ensco following the completion of the transaction and other statements that are not historical facts, are forward-looking statements (including within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended).  Forward-looking statements include words or phrases such as “anticipate,” “believe,” “contemplate,” “estimate,” “expect,” “intend,” “plan,” “project,” “could,” “may,” “might,” “should,” “will” and words and phrases of similar import.  These statements involve risks and uncertainties including, but not limited to, actions by regulatory authorities, rating agencies or other third parties, actions by the respective companies’ security holders, costs and difficulties related to integration of Atwood, delays, costs and difficulties related to the transaction, market conditions, and Ensco’s financial results and performance following the completion of the transaction, satisfaction of closing conditions, ability to repay debt and timing thereof, availability and terms of any financing and other factors detailed in the risk factors section and elsewhere in Ensco’s and Atwood’s Annual Report on Form 10-K for the year ended December 31, 2016 and September 30, 2016, respectively, and their respective other filings with the Securities and Exchange Commission (the “SEC”), which are available on the SEC’s website at www.sec.gov.  Should one or more of these risks or uncertainties materialize (or the other consequences of such a development worsen), or should underlying assumptions prove incorrect, actual outcomes may vary materially from those forecasted or expected.  All information in this release is as of today.  Except as required by law, both Ensco and Atwood disclaim any intention or obligation to update publicly or revise such statements, whether as a result of new information, future events or otherwise.

 

Important Additional Information Regarding the Transaction

 

In connection with the proposed transaction, Ensco has filed a registration statement on Form S-4, including a joint proxy statement/prospectus of Ensco and Atwood, with the SEC.  INVESTORS AND SECURITY HOLDERS OF ENSCO AND ATWOOD ARE ADVISED TO CAREFULLY READ THE REGISTRATION STATEMENT AND PROXY STATEMENT/PROSPECTUS (INCLUDING ALL AMENDMENTS AND SUPPLEMENTS THERETO) WHEN THEY BECOME AVAILABLE BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT THE TRANSACTION, THE PARTIES TO THE TRANSACTION AND THE RISKS ASSOCIATED WITH THE TRANSACTION.  A definitive joint proxy statement/prospectus will be sent to security holders of Ensco and Atwood in connection with the Ensco and Atwood shareholder meetings.  Investors and security holders may obtain a free copy of the joint proxy statement/prospectus (when available) and other relevant documents filed by Ensco and Atwood with the SEC from the SEC’s website at www.sec.gov.  Security holders and other interested parties will also be able to obtain, without charge, a copy of the joint proxy statement/prospectus and other relevant documents (when available) by directing a request by mail or telephone to either Investor Relations, Ensco plc, 5847 San Felipe, Suite 3300, Houston, Texas 77057, telephone 713-430-4607, or Investor Relations, Atwood Oceanics, Inc., 15011 Katy Freeway, Suite 800, Houston, Texas 77094, telephone 281-749-7840.  Copies of the documents filed by Ensco with the SEC will be available free of charge on Ensco’s website at www.enscoplc.com under the tab “Investors.”  Copies of the documents filed by Atwood with the SEC will be available free of charge on Atwood’s website at www.atwd.com under the tab “Investor Relations.”  Security holders may also read and copy any reports, statements and other information filed with the SEC at the SEC public reference room at 100 F Street N.E., Room 1580, Washington D.C. 20549. Please call the SEC at (800) 732-0330 or visit the SEC’s website for further information on its public reference room.

 



 

Participants in the Solicitation

 

Ensco and Atwood and their respective directors, executive officers and certain other members of management may be deemed to be participants in the solicitation of proxies from their respective security holders with respect to the transaction.  Information about these persons is set forth in Ensco’s proxy statement relating to its 2017 General Meeting of Shareholders and Atwood’s proxy statement relating to its 2017 Annual Meeting of Shareholders, as filed with the SEC on 31 March 2017 and 9 January 2017, respectively, and subsequent statements of changes in beneficial ownership on file with the SEC.  Security holders and investors may obtain additional information regarding the interests of such persons, which may be different than those of the respective companies’ security holders generally, by reading the joint proxy statement/prospectus and other relevant documents regarding the transaction, which will be filed with the SEC.

 

No Offer or Solicitation

 

This release is not intended to and does not constitute an offer to sell or the solicitation of an offer to subscribe for or buy or an invitation to purchase or subscribe for any securities or the solicitation of any vote in any jurisdiction pursuant to the proposed transaction or otherwise, nor shall there be any sale, issuance or transfer of securities in any jurisdiction in contravention of applicable law.  Subject to certain exceptions to be approved by the relevant regulators or certain facts to be ascertained, the public offer will not be made directly or indirectly, in or into any jurisdiction where to do so would constitute a violation of the laws of such jurisdiction, or by use of the mails or by any means or instrumentality (including without limitation, facsimile transmission, telephone and the internet) of interstate or foreign commerce, or any facility of a national securities exchange, of any such jurisdiction.

 

Service of Process

 

Ensco is incorporated under the laws of England and Wales.  In addition, some of its officers and directors reside outside the United States, and some or all of its assets are or may be located in jurisdictions outside the United States.  Therefore, investors may have difficulty effecting service of process within the United States upon those persons or recovering against Ensco or its officers or directors on judgments of United States courts, including judgments based upon the civil liability provisions of the United States federal securities laws. It may not be possible to sue Ensco or its officers or directors in a non-U.S. court for violations of the U.S. securities laws.

 

Investor and Media Contact(s):

Ensco plc

 

Nick Georgas

 

Director — Investor Relations and Communications

 

713-430-4607

 

 

 

Ensco plc

 

Tim Richardson

 

Manager — Investor Relations

 

713-430-4490

 

 

 

Atwood Oceanics, Inc.

 

Mark W. Smith

 

Senior Vice President and Chief Financial Officer

 

281-749-7840

 


 

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