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Barclays CEO Energy ConferenceCarl Trowell – CEO & President

9 September 2015

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Forward-Looking Statements

Statements contained in this presentation that are not historical facts are forward-looking statements within themeaning 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 statementsinvolving expected financial performance, day rates and backlog, estimated rig availability; rig commitments;contract duration, status, terms and other contract commitments; new rig commitments and construction; scheduleddelivery dates for rigs; the timing of delivery, mobilization, contract commencement, relocation or other movement ofrigs; benefits derived from expense management actions; estimated capital expenditures; rig stacking costs; andgeneral 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 offshorerig operations, relocations, severe weather or hurricanes; changes in worldwide rig supply and demand, competitionand technology; 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 mechanicaldifficulties, performance, customer finances, the decline or the perceived risk of a further decline in oil and/ornatural gas prices, or other reasons, including terminations for convenience (without cause); the outcome oflitigation, legal proceedings, investigations or other claims or contract disputes; governmental regulatory, legislativeand permitting requirements affecting drilling operations; our ability to attract and retain skilled personnel oncommercially reasonable terms; environmental or other liabilities, risks or losses; debt restrictions that may limit ourliquidity and flexibility; our ability to realize the expected benefits from our redomestication and actual contractcommencement dates; cybersecurity risks and threats; and the occurrence or threat of epidemic or pandemicdiseases or any governmental response to such occurrence or threat In addition to the numerous factors describedabove, you should also carefully read and consider “Item 1A. Risk Factors” in Part I and “Item 7. Management’sDiscussion and Analysis of Financial Condition and Results of Operations” in Part II of our most recent annualreport on Form 10-K, as updated in our subsequent quarterly reports on Form 10-Q, which are available on theSEC’s website at www.sec.gov or on the Investor Relations section of our website at www.enscoplc.com. Eachforward-looking statement speaks only as of the date of the particular statement, and we undertake no obligation topublicly 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– efficiency & cost improvements– attrition of older rigs

• Maintain and Widen Leadership Position– #1 in customer satisfaction– best in innovation– most efficient/cost-effective driller

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Current Market Conditions

Source: IHS Upstream

$0

$10

$20

$30

$40

$50

$60

$ billions

Global exploration spend of 18 largest E&Ps

$29

$41

$58

• Substantial reduction in E&P capex

• Unprecedented decline in exploration spending

• Lower rig utilization & day rates

• Expect 2016 capex to be lower YoY

• The significant pullback in spending will affect supply in the future

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• Drillers– cutting costs & stacking/retiring rigs– deferring rig deliveries– speculators canceling rig orders

• Service companies– strategic combinations to invest in technological innovations and process

improvements that increase efficiencies and drive out costs• 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 and

streamlined project management

Market Response

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• Capital Management

• Fleet Restructuring

• Expense Management

• Operational Excellence & Safety– innovation– process improvements

Taking Decisive Steps To Be

Resilient Through 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 quarterly dividend to improve capital management flexibility

• Deferred ENSCO DS-10 delivery to 1Q17, delaying ~$300 million in capex

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

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2027 2040

$150$300

2044

Increased Revolving Credit Facility to $2.25B; extended to 2019

$ millions

$1,025

No debt maturitiesuntil 2Q19

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Credit Ratings

ESV DO NE RDC RIG SDRL

BBB+ BBB+

BBB- BBB-

BB+

NotRated

Investment Grade

Source: Bloomberg composite credit ratings as of August 2015; cash, short-term investments and contracted revenue backlog as of 30 June 2015

• $1.3 billion of cash and short-term investments• $7.4 billion of contracted revenue backlog

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Declining Capital Expenditures

2H15 2016 2017 2018

600450

350

100

2580

100

170150

150

New rig construction Rig enhancements Minor upgrades and improvements

$ millions$800

$645*$580*

*Note: Preliminary estimates for rig enhancement and minor upgrade and improvements for 2016, 2017 and 2018; final capex estimates to be determined upon completion of annual budget process and subject to change based on rig contracting; year-to-date capital expenditures through 30 June 2015: $682 million of new rig construction, $115 million of rig enhancements and $117 million of minor upgrades and improvements

$150*

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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 123

ENSCO 140

ENSCO 141

ENSCO DS-10

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

Under Construction & Uncontracted

Delivered and On Operating 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 monthly payments for two years equal to the operating day rate of approximately $550,000, which may be partially defrayed should Ensco re-contract the rig within the next two years and/or mitigate certain costs during this time period while the rig is idle and without a contract.

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• 2014 floater upgrades benefitting 2015 results– ENSCO 5004– ENSCO 5006

• Mooring upgrade for ENSCO 8503 contracted to Stone Energy

Upgrades to Existing Floaters

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• 20 rigs sold since 2010 generating ~$675 million in proceeds– 6 rigs sold in the past 12 months

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

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

• 6 rigs currently held for sale– 4 floaters– 2 jackups

Fleet Restructuring:Divestitures

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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; full run-rate beginning 4Q15• consolidated business unit reporting structure from five to three, centralizing certain

functions and rationalizing office space

Expense Management Actions

15% reduction in offshore unit labor costs+

$57 million annual savings in onshore support costs

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• Stacking rigs without near-term contracting opportunities reduces daily operating expenses

• Up-front costs to preserve cold stacked rigs– $1 million for jackups– $5 million for semis

• 8500 Series semis cold stacking process includes:– dehumidification– prevention of hull corrosion– key equipment preservation

Proactive Rig Stacking

Avg Daily Operating Expenses

Warm Stack

Cold Stack

Drillship $40kper day

<$10kper day

(ENSCO DS-1 & DS-2)

Semi $32kper day

<$10kper day

Jackup $20kper day

<$5kper day

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Improved Expense Outlook

2Q15A 3Q15E 4Q15E

Contract Drilling Expense

$503 million $450 – $455 million

Prior estimate ~ $463 million

$435 – $440 million

Expense cuts more than offset a 7%

projected increase in rig operating days

v. 3Q15 (4Q15 includes

scheduled start of ENSCO DS-8 in mid-November)

Note: 3Q15 estimates exclude severance costs of approximately $5 million in contract drilling expense

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• Proprietary asset management system– improve operational

performance by increasing uptime

– reducing maintenance costs

– lower lifetime equipment costs

• Leverages standardization

Innovation During the Downturn

Ensco Asset Management System

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Excellent Safety Performance

0.0

0.2

0.4

0.6

0.8

1.0

1.2

2008 2009 2010 2011 2012 2013 2014 YTD2015

Ensco Industry

Total RecordableIncident Rate

Note: 2015 TRIR for industry is as of 1Q15.

• Leading-edge safety management systems

• Enhancing process safety to drive further improvements

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Net Income Margin

ESV SDRL NE RIG DO RDC

31%

26% 25%

19%16% 16%

Source: Thomson One; sum of trailing eight quarters of net income divided by sum of trailing eight quarters of revenue. Thomson One's data is based on aggregation of information collected from industry equity research analysts, and may not be based on GAAP reported financial data; excludes Seadrill’s $440 million gain on disposal of West Auriga to Seadrill Partners in 1Q14

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High Levels of Customer Satisfaction

Rated #1• Total Satisfaction

• Health, Safety & Environment

• Technology

• Special Applications

• Deepwater Drilling

• Shelf Wells

• Non-Vertical Wells

• Harsh Environment Wells

• North Sea

• Latin America & Mexico

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Key Points to Remember

1. Deepwater production is 7% 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+ oil environment

4. Industry is proactively responding to commodity price pressures

5. Breakeven commodity prices for offshore programs are declining

6. Unprecedented decline in E&P exploration spending will create pent up demand and a future snapback in spending

Outlook for Offshore E&P

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• Shell has stated that deepwater is a key driver of growth– “Our growth priorities follow two strategic themes: integrated

gas and deepwater. These will provide our medium-term growth and we expect them to become core engines in the future.”

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

this moment is the most exciting part of the industry.”– “The potential is absolutely gigantic – there is much more to

come.”

Importance of Deepwater

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

– BP: “In order to deliver long-term growth, we will continue to maintain a disciplined investment approach into three distinctive classes of assets: deepwater, gas value chains and giant fields. We will continue to maintain a balanced portfolio of opportunities.”

– Chevron: “New supply will increasingly come from more complex and remote sources with higher full-cycle development costs [including] arctic, deepwater, heavy, sour and the like.”

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

Importance of Deepwater

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• BP Mad Dog: Phase 2– Cost estimates reduced to less than $10 billion from previous

estimate of $22 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

• Shell Appomattox– 20% reduction in project costs from supply chain savings, design

improvements, 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 service companies to drive greater efficiencies and lower the breakeven commodity prices for projects:

• Schlumberger/Cameron – strategic innovation, efficiencies and cost reductions in deepwater projects; driving down breakeven commodity price levels

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

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

• FMC Technologies/Technip – overhaul subsea field operations to drive efficiencies

• Baker Hughes/Aker Solutions – develop technology for production solutions that will boost output, increase recovery rates and reduce costs for subsea fields

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

Service Sector Response

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Rig Years Contracted 2015 2016 2017+ Total

Global Fleet 93 86 106 285

Ensco 12 8 10 30

2015 YTD Contract Activity

Source: IHS-ODS Petrodata

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• Shallow water well programs have lower breakeven commodity price points on average than deepwater projects– less complex drilling requirements, shallower water depths and greater

access to existing infrastructure

• More diverse customer base; shallow water demand a function of customer- and region-specific factors– increased rig demand in the Middle East from NOCs– leases requiring continued drilling in areas like North Sea and West

Africa 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 to

capex reductions and uncontracted newbuild supply, respectively

• Drillers with established operational and safety track records have an advantage in contracting rigs– zero newbuilds being built by speculators have been contracted

Jackup Market Dynamics

28Source: IHS-ODS Petrodata as of August 2015; competitive marketed floaters and jackups (independent leg cantilever rigs); ‘contracted’ includes rigs currently under contract or with a future contract

Global Marketed Rig Fleet

Newbuilds

Floaters JackupsContracted 214 316Idle/Other 56 77Total 270 393

% Contracted 79% 80%

Under Construction 52 105

On Order / Planned 19 9

Total 71 114% Contracted 52% 7%

ActiveFleet

29 / 41% by SETE Brasil

66 / 58% by Speculators

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Attrition of Older Floaters

• 88% attrition for rigs >35 years of age– 23 rigs >35 years of age

scrapped (26 uncontracted as of June 2014)

• 67% attrition for rigs 30-34 years of age– 10 rigs 30-34 years of age

scrapped (15 uncontracted rigs as of June 2014)

• 7 rigs <30 years of age scrapped (5 rigs <20 yrs old)

~100 floaters could be retired by year-end 2017 if attritioncontinues at similar rates observed over the past 12 months

Scrapped to Date40 floaters scrapped

since 3Q14

Currently Idle25 – 30 floaters that are

idle without follow-on work could be retired

Expiring Contracts35 – 40 floaters with

contracts expiring before YE17 without follow-on work could be retired

• 19 rigs >35 years of agex 88% attrition rate~17 scrap candidates

• 15 rigs 30-34 years of agex 67% attrition rate~10 scrap candidates

• Floater utilization would improve to 80% from 73% if ~27 rigs were scrapped

Source: IHS-ODS Petrodata as of August 2015; ‘retired’ includes scrapped rigs, announced scrapping and rigs converted to non-drilling units

• 27 rigs >35 years of agex 88% attrition rate~24 scrap candidates

• 21 rigs 30-34 years of agex 67% attrition rate~14 scrap candidates

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Newbuild Floater Order Book

Source: IHS-ODS Petrodata as of August 2015; marketed competitive floaters

71 Total

7Uncontracted,

On Order

9Contracted

36% 17%

17SETE Brasil,

Under Construction

26Uncontracted,

Under Construction

13%

10%

12SETE Brasil,

On Order

24%

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Attrition of Older Jackups

• 4 competitive jackups retired

• Between 1Q09 and 2Q14, another 13 competitive jackups were retired with an average age of 30 years

100+ jackups could be retired as expiring contracts and survey costs lead to the removal of older rigs from drilling supply

Retired to Date4 competitive

jackups retiredsince 3Q14

Currently Idle60 competitive

jackups >30 years of age idle

Expiring Contracts90 jackups >30 years of

age have contracts expiring before YE17 without follow-on work

• 14 competitive jackups >30 years old have been idle for at least one year

• 18 competitive jackups >30 years old have been idle for six to 12 months

• 28 competitive jackups >30 years old have been idle up to six months

• Jackup utilization would improve to 77% from 67% if ~60 rigs were retiredSource: IHS-ODS Petrodata as of August 2015; competitive

jackups are independent leg cantilever rigs, ‘retired’ includes scrapped rigs, announced scrapping and rigs converted to non-drilling units

• ~50% of these rigs are estimated to require a major survey for recertification within one year of contract expiration

• These surveys could require significant capital investment to meet classification requirements that may prompt more rig retirements

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Newbuild Jackup Order Book

Source: IHS-ODS Petrodata as of August 2015; marketed competitive jackups (independent leg cantilever rigs)

114 Total

60Uncontracted, Speculators

37Uncontracted, Established

Drillers

8Contracted, Established

Drillers

32%

7%

53%

9On Order,

All Uncontracted

8%

Zero rigs being built by speculators

have been contracted

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• We have taken proactive capital management, fleet restructuring and expense management decisions

• Our liquidity and balance sheet position gives us resilience and options

• We will invest in innovation and engineering to grow our leadership position for the future

• The offshore drilling industry will be reconfigured by this downturn - newer entrants and companies with weaker balance sheets will struggle

Summary

In a very challenged market our liquidity and balance sheet provide resilience

and options

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