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Scotia Howard Weil 2016 Energy Conference22 March 2016

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Forward-Looking Statements

Statements contained in this presentation that are not historical facts are forward-looking statements within the meaningof Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-lookingstatements include words or phrases such as “anticipate,” “believe,” “estimate,” “expect,” “intend,” “plan,” “project,”“could,” “may,” “might,” “should,” “will” and similar words and specifically include statements involving expected financialperformance, day rates, contract drilling expenses and backlog; estimated rig availability; rig commitments; contractduration, status, terms and other contract commitments; new rig commitments and construction; rig upgrades; scheduleddelivery dates for rigs; the timing of delivery, mobilization, contract commencement, relocation or other movement of rigs;benefits derived from expense management actions; estimated capital expenditures; rig retirements; rig stacking costs;and general market, business and industry conditions, trends and outlook. Such statements are subject to numerousrisks, uncertainties and assumptions that may cause actual results to vary materially from those indicated, includingcommodity price fluctuations, customer demand, new rig supply, downtime and other risks associated with offshore rigoperations, relocations, severe weather or hurricanes; changes in worldwide rig supply and demand, competition andtechnology; future levels of offshore drilling activity; governmental action, civil unrest and political and economicuncertainties; terrorism, piracy and military action; risks inherent to shipyard rig construction, repair, maintenance orenhancement; possible cancellation, suspension or termination of drilling contracts as a result of mechanical difficulties,performance, customer finances, the decline or the perceived risk of a further decline in oil and/or natural gas prices, orother reasons, including terminations for convenience (without cause); the outcome of litigation, legal proceedings,investigations or other claims or contract disputes; governmental regulatory, legislative and permitting requirementsaffecting drilling operations; our ability to attract and retain skilled personnel on commercially reasonable terms;environmental or other liabilities, risks or losses; debt restrictions that may limit our liquidity and flexibility; our ability torealize the expected benefits from our redomestication and actual contract commencement dates; cybersecurity risksand threats; and the occurrence or threat of epidemic or pandemic diseases or any governmental response to suchoccurrence or threat. In addition to the numerous factors described above, you should also carefully read and consider“Item 1A. Risk Factors” in Part I and “Item 7. Management’s Discussion and Analysis of Financial Condition and Resultsof Operations” in Part II of our most recent annual report on Form 10-K, as updated in our subsequent quarterly reportson Form 10-Q, which are available on the SEC’s website at www.sec.gov or on the Investor Relations section of ourwebsite at www.enscoplc.com. Each forward-looking statement speaks only as of the date of the particular statement,and we undertake no obligation to publicly update or revise any forward-looking statements, except as required by law.

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Agenda

• Current Market Conditions

• Proactive Steps to Address Downturn

• Outlook for Offshore Drilling

– attrition of older rigs

– efficiency & cost improvements

• Maintain and Widen Leadership Position

– #1 in customer satisfaction

– innovation

– efficient/cost-effective driller

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Current Market Conditions

Source: IHS Upstream Competition ServiceNotes: Majors and Large IOCs peer group includes 15 international oil companies; 2015 and 2016 based on estimates and initial guidance,respectively.

• Substantial reduction inE&Ps total capex since2013

• Expect E&Ps total capexfor 2016 to be ~30% loweryear over year

• Unprecedented decline inexploration spending

• Lower rig utilization & dayrates

• The significant pullback inspending will affect supplyin the future

$292

$262

$212

$149

$0

$50

$100

$150

$200

$250

$300

$350

$ billions

Total Corporate Capex ofMajors & Large IOCs

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• Customers

– reducing capex

– deferring projects

– early terminations/concessions for existing rig contracts

– re-engineering to increase efficiencies/reduce costs

– testing economics for future programs based on lower costs andstreamlined project management

• Drillers

– cutting costs & stacking/retiring rigs

– deferring rig deliveries

– speculators canceling rig orders

• Service companies

– strategic combinations to invest in technological innovations and processimprovements that increase efficiencies and drive out costs

Market Response

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• Capital Management

• Fleet Restructuring

• Expense Management

• Operational Excellence & Safety

– innovation

– process improvements

Taking DecisiveSteps To

PersevereThrough The

Downturn

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• Accessed the debt markets

– $1.25 billion offering in 3Q14

– $1.10 billion offering in 1Q15 to refinance 2016 maturities

• Increased revolver to $2.25 billion and extended to 2019

• Reduced dividend twice to improve liquidity and capital managementflexibility

• Deferred delivery of ENSCO DS-10 to 1Q17, delaying ~$300 millionin capex, and ENSCO 123 to 1Q18, delaying ~$200 million in capex

• $1.3 billion of cash and short-term investments as of year-end 2015

• Tender offer for certain debt maturities

Proactive Capital Management

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Debt Maturity Profile

$500

$900

$1,500

$625$700

$2,250

$0

$300

$600

$900

$1,200

$1,500

$1,800

$2,100

$2,400

$2,700

$3,000

2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2027 2040

$150$300

2044

Increased Revolving Credit Facilityto $2.25B; extended to 2019

$ millions

$1,025

No debtmaturitiesuntil 2Q19

Tender Process Ongoing

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S&P Credit Ratings

DO ESV NE RDC RIG ATW PACD ORIG SDRL

BBB+

BBB BBBBBB-

BB+

BB

B-CCC+

NotRated

InvestmentGrade

Source: Standard & Poor’s Ratings Services credit ratings as of March 2016

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Capital Expenditure Outlook

2016E 2017E 2018E

275350

225

25

50

50

15050

50

New rig construction Rig enhancements Minor upgrades and improvements

$ millions

$450 $450

Note: Estimates for 2016, 2017 and 2018; final capex estimates to be determined upon completion of annual budget process and subject to changebased on rig contracting; new rig construction represents contractual commitments plus anticipated capex associated with rig construction; 2016 rigenhancements capex is specific to a mooring upgrade for an additional ENSCO 8500 Series rig, while 2017 and 2018 rig enhancements are estimatesand not earmarked for any specific projects at this time; capex for minor upgrades and improvements are based on the currently active fleet.

$325

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Fleet Restructuring:Newbuild Deliveries

2012.75 2013.75 2014.75 2015.75 2016.75 2017.75 2018.75 2019.75

ENSCO DS-7

ENSCO 120

ENSCO 121

ENSCO 122

ENSCO 110

ENSCO DS-8

ENSCO DS-9

ENSCO 140

ENSCO 141

ENSCO DS-10

ENSCO 123

Drillships Premium jackups

2013 2016 20172014 2015 20202018 2019

5 yrs with Total5 yrs with Total

2 yrs on operating rate*2 yrs on operating rate*

2 yrs w/ Wintershall2 yrs w/ Wintershall

2 yrs with NAM2 yrs with NAM

2+ yrs with Nexen2+ yrs with Nexen

4 yrs with Total4 yrs with Total

Delivered &Contracted

UnderConstruction &Uncontracted

Delivered and OnOperating Rate

3 yrs with NDC3 yrs with NDC

*Note: Customer has terminated contract for its convenience. Per terms of contract for early termination, customer is required to make monthlypayments for two years equal to the operating day rate of approximately $550,000, which may be partially defrayed should Ensco re-contract the rigwithin the next two years and/or mitigate certain costs during this time period while the rig is idle and without a contract.

16 newbuild rigs delivered since 2010; four more under construction

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• 21 rigs sold since 2010 generating ~$675 million inproceeds– 7 rigs sold since September 2014

• 4 jackups sold for more than $200 million in proceeds during 3Q14,reducing exposure to Mexico jackup market

• 3 floaters >30 years of age sold for scrap value

• 12 rigs to be retired– 7 rigs in continuing operations – 6 jackups and 1 floater

– 5 rigs in discontinued operations – 2 jackups and 3 floaters

Fleet Restructuring:Divestitures & Scrapping

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• February 2015– 9% unit labor cost decrease for offshore workers

– 15% reduction of onshore positions

• $27 million in annualized savings

– full run-rate savings beginning 2Q15

• August 2015– +6 ppt improvement in offshore unit labor cost savings to 15% compared to 2014

levels; full run-rate savings beginning 1Q16

– 14% incremental reduction of onshore positions

• $30 million additional annualized savings from 2014 levels; full run-rate beginning 4Q15

• consolidated business unit reporting structure from five to three, centralizing certainfunctions and rationalizing office space

Expense Management Actions

15% reduction in offshore unit labor costs+

$60+ million annual savings in onshore support costs

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• Stacking rigs without near-term contracting opportunitiesreduces daily operatingexpenses

• Up-front costs to preservecold stacked rigs

– $1 million for jackups

– $5 million for semis

• 8500 Series semis coldstacking process includes:

– dehumidification

– prevention of hull corrosion

– key equipment preservation

Proactive Rig Stacking

Avg DailyOperatingExpenses

WarmStack

ColdStack

Drillship$40k

per day

<$10kper day

(ENSCO DS-1& DS-2)

Semi$32k

per day<$10k

per day

Jackup$20k

per day<$5k

per day

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Improved Expense Outlook

2Q15A 3Q15A 4Q15A 1Q16E

$503 million $434 million $398 million

Excl. $17 millionprovision for doubtfulaccounts related to

ENSCO DS-5 drillingservices contract

Prior estimate of$415 - 420 million

$385 – $390million

Contract Drilling Expense

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• We continue to invest inthree core programs:

1. improving the drillingprocess

2. asset uptime and efficiency

− Ensco Asset Management System

3. re-engineering the supportstructure

Investments in Innovation

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Excellent Safety Performance

Total RecordableIncident Rate

• Record 2015 TRIR

• Leading-edge safetymanagement systems

• Enhancing processsafety to drive furtherimprovements

0.0

0.2

0.4

0.6

0.8

1.0

1.2

2008 2009 2010 2011 2012 2013 2014 2015

Ensco Industry

Note: IADC industry statistics are as of 4Q15.

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Net Income MarginLargest Offshore Drillers

ESV SDRL NE RIG RDC DO

28%27%

21%19%

18%16%

Source: FactSet; sum of trailing eight quarters of net income divided by sum of trailing eight quarters of revenue. FactSet's data is based onaggregation of information collected from industry equity research analysts and may not be based on GAAP reported financial data; Ensco,Seadrill, Noble and Transocean adjusted for gains and losses on asset disposals, legal settlements and early termination and arbitration fees.

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High Levels of Customer Satisfaction

Rated #1• Total Satisfaction

• Safety & Environment

• Performance & Reliability

• Job Quality

• Special Applications

• Ultra-Deepwater Wells

• Deepwater Wells

• Harsh Environment Wells

• Horizontal & Directional Wells

• Shelf Wells

• North Sea

• Middle East

• Asia & Pacific Rim

20Source: IHS-ODS Petrodata as of March 2016; competitive marketed floaters and jackups (independent leg cantilever rigs); ‘contracted’ includesrigs currently under contract or with a future contract(1) Recent news reports suggest SETE Brasil program could be reduced to 10 newbuilds in total

Global Marketed Rig Fleet

Newbuilds

Floaters Jackups

Contracted 184 282

Idle/Other 69 105

Total 253 387

% Contracted 73% 73%

Under Construction 47 111

On Order / Planned 17 2

Total 67 113

% Contracted 51% 8%

ActiveFleet

29 / 43%by SETEBrasil(1)

70 / 62%by

Speculators

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Attrition of Older Floaters

• 88% attrition for rigs >35years of age historically

– 27 rigs >35 years of agescrapped

• 67% attrition for rigs 30-34years of age historically

– 12 rigs 30-35 years of agescrapped

• 11 rigs <30 years of agescrapped

– 8 rigs <20 yrs old scrapped

70 more floaters could be retired by year-end 2017 if attritioncontinues at similar rates observed over the past 15 months

Scrapped to Date50 floaters scrapped

since 3Q14

Currently Idle~35 floaters that are idlewithout follow-on work

could be retired

Expiring Contracts~35 floaters with

contracts expiring beforeYE17 without follow-onwork could be retired

• 27 rigs >35 years of age

x 88% attrition rate

~24 scrap candidates

• 18 rigs 30-34 years of age

x 67% attrition rate

~12 scrap candidates

• Floater utilization wouldimprove to 72% from 64%if ~35 rigs were scrapped

Source: IHS-ODS Petrodata as of March 2016; ‘retired’ includes scrapped rigs, announced scrapping and rigs converted to non-drilling units;utilization figures include non-marketed units

• 23 rigs >35 years of age

x 88% attrition rate

~20 scrap candidates

• 18 rigs 30-34 years of age

x 67% attrition rate

~12 scrap candidates

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Newbuild Floater Order Book

Source: IHS-ODS Petrodata as of March 2016; marketed competitive floaters

64 Total

5Uncontracted,

On Order

5Contracted

39%

19%

17SETE Brasil,

UnderConstruction

25Uncontracted,

UnderConstruction

8%

8%

12SETE Brasil,

On Order

26%Recent news reportssuggest SETE Brasil

program could bereduced to 10

newbuilds in total

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Attrition of Older Jackups

• 15 competitive jackups retired

• Between 1Q09 and 2Q14,another 13 competitivejackups were retired with anaverage age of 30 years

More than 100 additional jackups could be retired as expiring contractsand survey costs lead to the removal of older rigs from drilling supply

Retired to Date15 competitivejackups retired

since 3Q14

Currently Idle79 competitive

jackups >30 years ofage idle

Expiring Contracts71 jackups >30 years of

age have contractsexpiring before YE17without follow-on work

• 26 competitive jackups>30 years old have beenidle for at least one year

• 23 competitive jackups>30 years old have beenidle for six to 12 months

• 30 competitive jackups>30 years old have beenidle up to six months

• Jackup utilization wouldimprove to 76% from 65%if ~80 rigs were retiredSource: IHS-ODS Petrodata as of March 2016; competitive

jackups are independent leg cantilever rigs, ‘retired’ includesscrapped rigs, announced scrapping and rigs converted to non-drilling units; utilization figures include non-marketed units

• ~50% of these rigs areestimated to require amajor survey forrecertification within oneyear of contract expiration

• These surveys couldrequire significant capitalinvestment to meetclassification requirementsthat may prompt more rigretirements

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Newbuild Jackup Order Book

Source: IHS-ODS Petrodata as of March 2016; marketed competitive jackups (independent leg cantilever rigs)

113 Total

68Uncontracted,Speculators

34Uncontracted,

EstablishedDrillers

9Contracted,Established

Drillers

30%

8%

60%

2%2 Uncontracted,

On Order

Zero rigs beingbuilt in China byspeculators havebeen contracted

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Key Points to Remember

1. Deepwater production is 8% of global supply

2. Offshore reserves are a critical part of major E&P portfolios

3. Excessive costs/inefficiencies crept into sector during the $100+ oilenvironment

4. Industry is proactively responding to commodity price pressures

5. Breakeven commodity prices for offshore programs are declining

6. Unprecedented decline in E&P spending will lead to supply sidechallenges – the longer the duration of the pullback, the greater thechance of significant upward movements in commodity prices

Outlook for Offshore E&P

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• Shell has stated that deepwater is a key driver of growth– “Integrated gas and deepwater, which have been growth

priorities for Shell in recent years and will reach significantscale with BG's positions included, really accelerating the deliveryof the growth we had targeted there.” - Feb. 2016

• Shell’s acquisition of BG aligns with the company’spriorities in deepwater, particularly in Brazil– “Brazil is an absolutely outstanding upstream province … and at

this moment is the most exciting part of the industry.” - Apr. 2015

– “The potential is absolutely gigantic – there is much more tocome.” - Apr. 2015

Importance of Deepwater

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Other major E&Ps have made similar comments regarding theimportance of deepwater projects to future growth

– BP: “We don't think that the deepwater is played out … there's a widespectrum of quality in any resource category across the industry … it's notabout water depth; it's about the quality of our reservoirs. And we holdsome very strong deepwater investments going forward.” - Oct. 2015

– Chevron: “Major capital projects will still be required to sustain productionand renew the base … these projects offer diversity in location and assetclass including conventional, LNG, deepwater and heavy oil each of whichare expected to present profitable opportunities in the future.” - Mar. 2016

– Total: “A new direction is being taken to carry out deep offshoreoperations in even deeper waters … and at greater distances for multi-phase production transport … which is fully in line with the ambitious goalsof [the company’s] exploration and production [business] and supportsmajor technology-intensive assets such as Libra in Brazil.” - Apr. 2015

Importance of Deepwater

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• BP Mad Dog: Phase 2

– Cost estimates reduced to less than $10 billion from previousestimate of $22 billion

– Project re-engineering through standardization and scopeoptimization, coupled with industry deflation, resulted in significantly lesscapital required to develop approximately 90% of resources

• Shell Appomattox

– 20% reduction in project costs from supply chain savings, designimprovements, etc.

• Total Block 32

– Capital expenditure estimate reduced by $4 billion to $16 billion

– Optimized project design and contracting strategy

• Statoil

– “Standardization is the new innovation.”

Customers Re-Engineering Projects

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Recent strategic combinations/alliances among servicecompanies to drive greater efficiencies and lower the breakevencommodity prices for projects:

• Schlumberger/Cameron – strategic innovation, efficiencies and costreductions in deepwater projects; driving down breakeven commodity pricelevels

• GE Oil & Gas/McDermott – improve design/planning of offshore oil and gasfield developments

• OneSubsea/Subsea 7 – enhance project delivery, improve recovery andoptimize the cost and efficiency of deepwater subsea developments

• FMC Technologies/Technip – overhaul subsea field operations to driveefficiencies

• Baker Hughes/Aker Solutions – develop technology for production solutionsthat will boost output, increase recovery rates and reduce costs for subseafields

• Schlumberger/OneSubsea/Helix – optimize the cost and efficiency of subseawell intervention systems

Service Sector Response

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• Shallow water well programs have lower breakeven commodityprice points on average than deepwater projects

– less complex drilling requirements, shallower water depths and greateraccess to existing infrastructure

• More diverse customer base; shallow water demand a functionof customer- and region-specific factors

– increased rig demand in the Middle East from NOCs

– leases requiring continued drilling in areas like North Sea and WestAfrica have stabilized demand as exploration capex has been reduced

– well intervention now more economic in lower day rate environment

– U.S. Gulf of Mexico and Asia Pacific markets are challenged due tocapex reductions and uncontracted newbuild supply, respectively

• Drillers with established operational and safety track records havean advantage in contracting rigs

– zero newbuilds being built in China by speculators have been contracted

Jackup Market Dynamics

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• We have taken proactive capitalmanagement, fleet restructuring andexpense management decisions

• We believe our liquidity and balancesheet position gives us options

• We have invested in innovation andengineering to grow our leadershipposition for the future

• The offshore drilling industry will bereconfigured by this downturn – newerentrants and companies with weakerbalance sheets will struggle

Summary

In a very challengedmarket we believeour liquidity and

balance sheetprovide options

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