1

Investor Presentation

October 2016

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Forward-Looking Statements

Statements contained in this press release that are not historical facts are forward-looking statements within the meaning

of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking

statements 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 financial

performance, effective tax rate, expected expense savings, day rates and backlog, estimated rig availability; rig

commitments and contracts; contract duration, status, terms and other contract commitments; estimated capital

expenditures; letters of intent or letters of award; scheduled delivery dates for rigs; the timing of delivery, mobilization,

contract commencement, relocation or other movement of rigs; our intent to sell or scrap rigs; and general market,

business and industry conditions, trends and outlook. Such statements are subject to numerous risks, uncertainties and

assumptions that may cause actual results to vary materially from those indicated, including commodity price

fluctuations, customer demand, new rig supply, downtime and other risks associated with offshore rig operations,

relocations, severe weather or hurricanes; changes in worldwide rig supply and demand, competition and technology;

future levels of offshore drilling activity; governmental action, civil unrest and political and economic uncertainties;

terrorism, piracy and military action; risks inherent to shipyard rig construction, repair, maintenance or enhancement;

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, or other reasons,

including terminations for convenience (without cause); the cancellation of letters of intent or letters of award or any

failure to execute definitive contracts following announcements of letters of intent or letters of award; the outcome of

litigation, legal proceedings, investigations or other claims or contract disputes; governmental regulatory, legislative and

permitting requirements affecting 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 to realize the expected benefits from our redomestication and actual contract commencement dates;

tax matters including our effective tax rate; cybersecurity risks and threats; and the occurrence or threat of epidemic or

pandemic diseases or any governmental response to such occurrence 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 Results of Operations” in Part II of our most recent

annual report on Form 10-K, as updated in our subsequent quarterly reports on Form 10-Q, which are available on the

SEC’s website at www.sec.gov or on the Investor Relations section of our website 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

• Market Conditions

• Decisive actions to persevere through the downturn

– capital & expense management

– fleet restructuring

– investments in engineering and innovation to improve operational &

safety performance

• Outlook for offshore drilling

– efficiency & cost improvements

– attrition of older rigs & deferral/cancellation of newbuild deliveries

– catalyst markets

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$218

$208

$181

$126

$120

$0

$50

$100

$150

$200

$250

$ billions

Major & European IOCs’ Upstream Capital Spending Outlook

Market Conditions

Source: IHS Energy as of August 2016

Notes: Group of Major & European integrated oil companies includes BP, Chevron, Eni, ExxonMobil, OMV, Repsol, Shell/BG, Statoil and Total;

historical years include acquisitions; 2016 and 2017 estimates exclude acquisitions

• Substantial reduction in

upstream capex among

Major & European IOCs’

since 2013

− unprecedented decline in

exploration spending

• 2016 upstream capex for

Major & European IOCs’

expected to decline ~30%

year-over-year, but

bottoming in 2017

• Significant pullback in

spending will affect supply

in the future

- 45%

5

• Capital management

• Expense management

• Fleet restructuring

• Investments to improve

operational & safety

performance

– engineering & innovation

– process improvements

Decisive

Actions To

Persevere

Through The

Downturn

6

• Accessed the debt markets twice to bolster liquidity and refinance near-term debt maturities

• Increased revolver to $2.25 billion and extended to 2019; then extended maturity of $1.13 billion of revolver commitments by one year to 2020

• Reduced capital expenditures and dividend to preserve cash

• Delayed delivery of newbuilds, postponing ~$500 million of final milestone payments

• Repurchased debt at discounts resulting in ~$550 million of pre-tax cash savings

• Raised equity to further enhance liquidity position

• Significantly reduced leverage

Proactive Capital Management

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Benefits of Recent

Capital Management Actions

Note: Net debt is a non-GAAP financial measure defined as long-term debt less cash and short-term investments. Non-GAAP financial measures should

be considered as a supplement to, and not as a substitute for, or superior to, financial measures prepared in accordance with GAAP. 4Q15 net debt-to-

capital is calculated as follows: long-term debt of $5.9 billion, less $1.3 billion of cash and short-term investments, divided by the sum of long-term debt

of $5.9 billion plus shareholders’ equity of $6.5 billion, minus $1.3 billion of cash and short-term investments. 3Q16 net debt-to-capital is calculated as

follows: long-term debt of $4.7 billion, less $1.8 billion of cash and short-term investments, divided by the sum of long-term debt of $4.7 billion plus

shareholders’ equity of $8.0 billion, minus $1.8 billion of cash and short-term investments.

2.25 2.25

1.3

1.8

4Q15 3Q16

Liquidity

Revolver Cash + Short-term investments

$ billions

4Q15 3Q16

Net Debt-to-Capital Ratio

$3.55

$4.0541%

27%

$1.6 billion

reduction in

net debt

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Debt Maturity Schedule

$438

$681 $683$623

$669

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

$300

2044

$ millions

$1,001

No debt

maturities

until 2019

$150

Note: Reflects principal amount outstanding as of September 30, 2016, as adjusted to give effect to $24.5 million aggregate principal amount of 2044

senior notes that were exchanged for 1.8 million shares on October 3, 2016.

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Capital Expenditure Outlook

$70

$375

$225

4Q16E 2017E 2018E 2019E

Newbuild Capital Expenditures

New rig construction

$ millions

$0

Note: Estimates for 2016, 2017, 2018 and 2019; final capex estimates to be determined upon completion of annual budget process and subject to

change based on rig contracting; new rig construction represents contractual commitments plus anticipated capex associated with rig construction;

2017 and 2018 rig enhancements capex are estimates and not earmarked for any specific projects at this time; capex for minor upgrades and

improvements are based on the currently active fleet.

2050 50

2550

4Q16E 2017E 2018E

Other Capital Expenditures

Rig enhancements Minor upgrades & improvements

$ millions

$20

$75$100

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2015 Actions

• 15% reduction in offshore unit labor cost

• $60+ million of annual savings from 27% reduction in onshore support

headcount

– consolidated business unit reporting structure from five to three

– centralized certain functions

• $100+ million of additional contract drilling and G&A expense savings

– repair and maintenance rate reductions and lower rig insurance premiums

– other savings through negotiated discounts with vendors

Recent Actions

• Recently instituted a lower base salary structure for new hire offshore crews

• Further streamlining organizational structure: reduced onshore support costs

and compensation expense that is expected to result in more than $50 million of

annualized cost savings per 3Q16 earnings release

Expense Management Actions

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Fleet Management Strategy

• Leverage record uptime/safety performance to negotiate extensions for contracted rigs

• Maintain warm stacked rig availability in each region in order to bid into new opportunities, examples include:

– West Africa: ENSCO DS-7

– U.S. Gulf of Mexico: ENSCO 8503, ENSCO 68 & ENSCO 87*

– Asia: ENSCO DS-9, ENSCO 8504* & ENSCO 106

– Middle East: ENSCO 140/1 & ENSCO 110*

– North Sea: ENSCO 120, ENSCO 121* & ENSCO 102*

• Preservation stack excess high-spec rig capacity to prudently reduce expenses, yet maintain high-spec capacity that may be reactivated within 90 – 120 days

• Retire older, less capable rigs as they roll off contract as part of continuous high-grading/expense management

*Note: Current contract expires in November 2016.

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Stacking & Reactivation Costs

Rig Type

Upfront Cost

to

Preservation

Stack

Average Estimated Daily

Operating Expenses Estimated Cost

to ReactivateWarm

Stack

Preservation

Stack

Drillship $5 million$40k

per day

$15k

per day$25 - $35 million

8500 Series

Semi$5 million

$32k

per day

<$10k

per day$25 - $35 million

High-Spec

Jackup$1 million

$20k

per day*

<$5k

per day$5 million

*Note: ENSCO 140 daily stacking costs covered by shipyard for up to two years.

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(1) Includes ENSCO DS-10 newbuild currently scheduled for delivery in 1Q17

(2) Includes ENSCO 7500 that is expected to be retired from Ensco’s go-forward fleet

Note: adjusted for 2011 acquisition of Pride International; ultra-deepwater defined as 7500 ft. or greater

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Fleet Restructuring: Floaters

Newbuilds(1)

Current

Fleet

Year-End

2009

Retirements

& Sales(2)

+13 -10 20

16.8 years Lower average fleet age

Greater drilling capabilities

9.8 years

4 ultra-deepwater

capable floaters

7 floaters with

15k psi BOPs

15 ultra-deepwater

capable floaters

18 floaters with

15k psi BOPsEnhanced well control

14

51

Fleet Restructuring: Jackups

Current

Fleet

Year-End

2009

+5 -26 30

ENSCO 141Scheduled Delivery: 4Q16

ENSCO 123Scheduled Delivery: 1Q18

Under Construction

Jackup sales since 2009 have

generated ~$600 million in proceeds

Newbuilds(1)

Retirements

& Sales(2)

(1) Includes ENSCO 140 newbuild that was delivered in August 2016

(2) Includes ENSCO 53, ENSCO 56, ENSCO 81, ENSCO 82, ENSCO 86, ENSCO 90, ENSCO 94 & ENSCO 99 that are expected to be retired from

Ensco’s go-forward fleet

Note: adjusted for 2011 acquisition of Pride International

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Investment in Engineering:

8500 Series Mooring Upgrade

Source: IHS-ODS Petrodata as of October 2016; Ultra deepwater defined as 7500 ft. or greater

Dynamically Positioned

294

Rig CountGlobal Floater

Fleet

Ultra-deepwater capable

15K+ psi & 6+ ram BOP

8 mooring

winches

194

162

130

9

• Low-cost mooring

upgrade increases the

versatility of our 8500

Series rigs, placing

them among a select

group of floaters with

superior technological

capabilities and the

ability to operate in a

dynamically

positioned and/or

moored capacityENSCO 8503

ENSCO 8505

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• We continue to invest in

three core programs:

− improving the drilling

process

− asset uptime and efficiency

• Ensco Asset Management

System

− re-engineering the support

structure

Investment in Innovation:

Operational & Safety Results

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Improved Operational Utilization

98.5%

99.0%99.1%

99.3%

2013 2014 2015 YTDSep16

Jackups

92.0% 92.9%

94.0%

99.1%

2013 2014 2015 YTDSep16

Floaters

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Excellent Safety Performance

Total Recordable

Incident Rate

• Record 2015 and

YTD16 TRIR

• Leading-edge safety

management systems

• Enhancing process

safety to drive further

improvements

0.0

0.2

0.4

0.6

0.8

1.0

1.2

2008 2009 2010 2011 2012 2013 2014 2015 YTD2016

Ensco Industry

Note: IADC industry statistics are as of 2Q16.

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Net Income Margin

Largest Offshore Drillers

ESV SDRL RDC NE RIG DO

24% 24%

20%

17%16% 16%

Source: FactSet as of October 2016; sum of trailing eight quarters of net income divided by sum of trailing eight quarters of revenue. FactSet's

data is based on aggregation of information collected from industry equity research analysts and may not be based on GAAP reported financial

data. Ensco financials as of 3Q16, all other drillers as of 2Q16.

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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

21

Outlook for

Offshore Drilling

22

Offshore Exploration & Production

• Offshore production is ~33% of global supply

• Offshore reserves are a critical part of major E&P portfolios and

are vital to the economies of several countries

• Excessive costs/inefficiencies crept into sector during the $100+

oil environment

• Industry is proactively responding to commodity price pressures

and breakeven commodity prices for offshore programs are

declining

• Unprecedented decline in E&P spending will lead to supply side

challenges – the longer the duration of the pullback, the greater

the chance of significant upward movements in commodity prices

23

Catalyst

Markets

Offshore

Rig Supply

Path to Recovery

Breakeven Economics

Commodity

• Improvement /

stabilization in oil

prices

• Re-engineering /

standardization /

innovation

• Cost deflation

and efficiency

gains

• Brazil opens pre-

salt to more

players

• Mexico offshore

lease sales and

entrance of

international

operators

• Retirement of

older, less

capable assets

• Deferral and

cancellation of

newbuild

deliveries

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• Cost estimates reduced to less than $9 billion from prior

estimate of $20 billion

• Project re-engineering through standardization and scope

optimization, coupled with industry deflation, resulted in

significantly less capital required to develop approximately

90% of resources

Offshore Breakeven

Economics Improving

BP

Mad Dog

Phase 2

Shell

Vito

Statoil

Johan

Castberg

• Lowered estimated breakeven cost from >$60/bbl to $45/bbl

through project re-scoping

• Reduced breakeven cost from >$80/bbl to <$45/bbl through

supply chain savings, optimized project design and

standardized and simplified solutions

Recent Customer Commentary on Deepwater ProjectsOffshore Outlook

• Customers attention

has turned to project

re-engineering,

efficiency gains and

better expense

management

• Cost deflation across

supply chain:

operators, service

companies

• Break-even

economics are

improving

significantly for

offshore projects

Sources: Statoil 4 February 2016 Capital Markets Day; BP 17 June 2016 Bloomberg interview; Shell Capital Markets Day 7 June 2016

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• Cost reductions have led to an average project breakeven

of $40 to $45 per barrel

• Average breakeven prices for future projects on

Norwegian continental shelf have been reduced from $70

per barrel to approximately $40 per barrel

• Project breakevens for pre-FID deepwater projects have

been reduced to $45 per barrel on average

− Brazilian pre-salt project breakevens under $40 per barrel on

average

Offshore Breakeven

Economics Improving

Sources: Shell Capital Markets Day 7 June 2016; Maersk Earnings Release 12 August 2016; Statoil 29 August 2016 Upstream Interview; Chevron

29 April 2016 earnings conference call

• Deepwater single-well breakeven economics between $20

per barrel and $40 per barrel for brownfield developments

in U.S. Gulf of Mexico

26

Strategic Combinations & Alliances

Among Offshore Service Companies

Strategic combinations and alliances drive greater efficiencies and lower the

breakeven commodity prices for offshore projects

Innovation, efficiencies

and cost reductions in

deepwater projects

Enhance project delivery,

improve recovery and

optimize cost/efficiency of

subsea developments

Overhaul subsea field

operations to drive

efficiencies

Integrated FPSO solutions

to reduce costs of offshore

developments

Optimize the cost and

efficiency of subsea well

intervention systems

Develop production

solutions to boost output,

increase recovery rates

and reduce costs for

subsea fields

27

Attrition of Older Rigs

60 more floaters could be retired by year-end 2017 if attrition

continues at similar rates observed throughout the downturn

Retired to Date

67 floaters retired

since 3Q14

Currently Idle

~35 floaters >30 years of

age idle without follow-

on work could be retired

Expiring Contracts~25 floaters >30 years of

age have contracts expiring

before YE17 without follow-

on work could be retired

Source: IHS-ODS Petrodata as of October 2016

Note: (1) ‘Retired’ includes scrapped rigs, announced scrapping and rigs converted to non-drilling units; (2) Competitive jackups are independent leg cantilever rigs; (3) Historical

attrition ratio of 88% for floaters older than 35 years of age and 67% for floaters between 30 and 35 years of age applied annually to rigs that are currently idle or rolling off contract

for each age category.

Up to 145 additional jackups could be retired as expiring contracts and

survey costs lead to the removal of older rigs from drilling supply

Retired to Date

23 competitive

jackups retired

since 3Q14

Currently Idle91 competitive

jackups >30 years of age idle without follow-

on work could be retired

Expiring Contracts54 jackups >30 years of

age have contracts expiring

before YE17 without follow-

on work could be retired

FLO

AT

ER

SJA

CK

UP

S

28

Newbuild Floater Order Book

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

2

Uncontracted,

On Order

3

Contracted

44%

8 – 29

SETE Brasil27

Uncontracted,

Under

Construction

5%

3%

48%

News reports suggest

SETE Brasil program

could be reduced to 8

newbuilds in total

29

Newbuild Jackup Order Book

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

? – 62

Uncontracted,

Speculators

35

Uncontracted,

Established

Drillers

5

Contracted,

Established

Drillers

34%

5%

61%

Zero rigs being

built in China by

speculators have

been contracted

30

Jackup Delivery Deferrals

05

1015202530

1Q

14

2Q

14

3Q

14

4Q

14

1Q

15

2Q

15

3Q

15

4Q

15

1Q

16

2Q

16

3Q

16

4Q

16

1Q

17

2Q

17

3Q

17

4Q

17

1Q

18

2Q

18

3Q

18

4Q

18

1Q

19

2Q

19

3Q

19

4Q

19

1Q

20

2Q

20

3Q

20

4Q

20

May 2014 Delivery Schedule

Delivered Under Costruction

05

1015202530

1Q

14

2Q

14

3Q

14

4Q

14

1Q

15

2Q

15

3Q

15

4Q

15

1Q

16

2Q

16

3Q

16

4Q

16

1Q

17

2Q

17

3Q

17

4Q

17

1Q

18

2Q

18

3Q

18

4Q

18

1Q

19

2Q

19

3Q

19

4Q

19

1Q

20

2Q

20

3Q

20

4Q

20

October 2016 Delivery Schedule

Delivered Under Costruction

Source: IHS-ODS Petrodata as of October 2016

Note: October 2016 delivery schedule includes 20 new orders and excludes 11 orders cancelled since May 2014.

108 Scheduled Deliveries46 Actual Deliveries

119 Scheduled Deliveries 26 Scheduled Deliveries

31

Future Catalyst Markets: Brazil

• Following Senate approval earlier this

year, the Brazilian House recently passed

a bill that would eliminate requirement for

Petrobras to manage all pre-salt

operations and hold a minimum 30%

stake in pre-salt projects

• More recently, Statoil conditionally

acquired Petrobras’ 66% operating

interest in BM-S-8 offshore Brazil

including the Carcará discovery for $2.5

billion

• Diversification of customer base offshore

Brazil is ongoing with outstanding tenders

from Premier, Total and Chevron

“We believe in the strong

fundamentals of Brazil

and the fundamentals of

its geology. We will be

looking at a substantial

part of our production

from Brazil.”

– Ben van Beurden,

Shell CEO

February 2016

32

Future Catalyst Markets: Mexico

• During 4Q15, an auction was completed

for shallow-water blocks offshore Mexico,

awarding licenses to several exploration

and production companies

• Deepwater blocks are scheduled to be

auctioned in late 2016 with 26 E&Ps

registered for participation including

several integrated oil companies

“Regardless of what

happens in the

international context,

Mexico will move forward

with the energy reform

implementation.”

– Enrique Peña Nieto,

President of Mexico

February 2016

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Recap

• Proactive steps to:

– improve capital structure

– reduce expenses

– restructure fleet

– invest in engineering and innovation that improves operational and safety

performance

• Positive steps taken by the offshore sector to reduce breakeven

economics are building the foundation for future market recovery

• Rig attrition improving rig supply dynamics

• Our actions and investments position Ensco to capitalize as we

navigate through the market cycle

34