Investor Presentation March 2015 Forward-Looking Statements - - PDF document

investor presentation
SMART_READER_LITE
LIVE PREVIEW

Investor Presentation March 2015 Forward-Looking Statements - - PDF document

1 Investor Presentation March 2015 Forward-Looking Statements Statements contained in this presentation that are not historical facts are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E


slide-1
SLIDE 1

1

Investor Presentation

March 2015

slide-2
SLIDE 2

2

Statements contained in this presentation 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 regarding expected financial performance and return of capital, effective tax rate, day rates and backlog; the timing of delivery, mobilization, contract commencement, relocation or other movement of 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 or suspension 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; 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

  • ur liquidity and flexibility; our ability to realize the expected benefits from our redomestication and actual

contract commencement dates; 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, 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.

Forward-Looking Statements

slide-3
SLIDE 3

3

Profile

  • #1 in customer satisfaction – five consecutive years
  • Highest net income margins among major competitors
  • Best ever total recordable incident rate in 2014
  • High-quality fleet of floaters and jackups
  • Broad diversification: customer, geography, rig type
  • Capital management flexibility

– $1.4 billion of cash and short term investments – $2.25 billion revolving credit facility – investment grade credit ratings – $9.7 billion of contracted revenue backlog

  • 2%+ dividend yield
slide-4
SLIDE 4

4

4Q14 Results

  • $546 million cash flow from operating activities

– 98% operational utilization for jackups – 90% operational utilization for floaters

  • Fleet highgrading continues

– classified 4 rigs as discontinued operations – cold stacking 7 held-for-sale rigs to quickly reduce expenses

  • $3.9 billion total non-cash impairments

– $3.0 billion goodwill – $925 million asset

  • Total debt-to-capital ratio increased to 42%
slide-5
SLIDE 5

5

Additional Actions Taken in Response to Market Downturn

  • Reduced quarterly dividend to $0.15 per share to improve capital

management flexibility during downturn

  • Decrease operating expenses by cold stacking four rigs in

continuing operations – three jackups in U.S. Gulf of Mexico and ENSCO 8502 – with limited near-term contracting opportunities

  • Reducing offshore discretionary compensation and onshore

support costs

– 9% unit labor cost decrease beginning 2Q15 for offshore compensation – 15% Reduction in Force for onshore personnel including corporate staff

  • $27 million annualized savings beginning in 2Q14
  • $5 million up-front severance costs in 1Q14 to achieve savings
  • Negotiating with vendors and suppliers to lower costs
slide-6
SLIDE 6

6

Market Environment

  • Sharp drop in commodity prices accelerated beginning late fourth quarter

2014

  • New lows/increased volatility for oil prices during customers’ budget

season

  • Capital expenditures will decline in 2015 as customers re-evaluate

programs in light of lower commodity prices

  • Customers shortening contracts where permitted and requesting

concessions

  • Uncontracted newbuilds and customer sublets creating additional supply
  • Aging of current global fleet should lead to more retirements and stacking,

especially as rigs approach 30/35 year surveys

  • Some newbuilds being cancelled and others being delayed
slide-7
SLIDE 7

7

Declining Commodity Prices and Increasing Volatility

Source: Thomson One; commodity prices indexed to 31 December 2013 close prices; data through 23 February 2015

  • 60%
  • 50%
  • 40%
  • 30%
  • 20%
  • 10%

0% 10% 20%

Brent WTI

slide-8
SLIDE 8

8

Current Market

Newbuilds

Floaters Jackups

Contracted 238 338 Uncontracted 28 33 Stacked Marketed Rigs 20 38 Total 286 409 % Contracted 83% 83% Under Construction 58 101 On Order / Planned 25 17 Total 83 118 Contracted 55% 8% Uncontracted 45% 92%

Active Fleet

Source: IHS-ODS Petrodata as of February 2015; competitive marketed floaters and jackups; jackups are independent leg cantilever rigs

slide-9
SLIDE 9

9

Newbuild Jackup Order Book

Source: IHS-ODS Petrodata as of February 2015; marketed competitive jackups

118 Total

67 Uncontracted, Non-Established Drillers 42 Uncontracted, Established Drillers 9 Contracted, Established Drillers

35% 8% 57%

slide-10
SLIDE 10

10

Jackup Supply

352 394 399 355 57 77 121 172

  • Feb. 2015
  • Feb. 2016
  • Feb. 2017
  • Feb. 2018

< 35 years old >= 35 years old 45% CAGR

Source: IHS-ODS Petrodata as of February 2015; marketed competitive independent leg cantilever jackups

slide-11
SLIDE 11

11

Newbuild Floater Order Book

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

83 Total

37 Uncontracted 46 Contracted 55% 45%

slide-12
SLIDE 12

12

Floater Supply

238 266 285 291 48 50 53 65

  • Feb. 2015
  • Feb. 2016
  • Feb. 2017
  • Feb. 2018

< 35 years old >= 35 years old 7% CAGR

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

slide-13
SLIDE 13

13

Newbuild Deferrals and Cancellations

Atwood

  • Delivery dates for 2 drillships with 2015 expected deliveries delayed by

six months each Transocean

  • Delivery dates for 5 jackups with 2016 and 2017 expected deliveries

delayed by ten months on average Other

  • Reports suggest up to 12 floaters under construction for SETE Brasil

program may be cancelled

  • 6 jackups ordered by non-established drillers were cancelled in 2H14
slide-14
SLIDE 14

14

Increase in Rig Retirements and Cold Stacking

18 5 1 2 10 3 5 10 15 20 25 30 1Q14 2Q14 3Q14 4Q14 YTD15 Retired Cold Stacked

Floaters

Source: IHS-ODS Petrodata; includes announced retirements

2 1 1 1 1 4 6 7 2 4 6 8 10 12 1Q14 2Q14 3Q14 4Q14 YTD15 Retired Cold Stacked

Jackups

slide-15
SLIDE 15

15

Ensco’s Proactive Fleet Management

2Q14

  • Moved five floaters to held for sale to proactively reduce expenses; one

sold for scrap value 3Q14

  • Sold four jackups for more than $200 million

4Q14

  • Moved three rigs to held for sale and cold stacking rigs to quickly reduce
  • perating expenses

YTD15

  • Cold stacking four rigs in continuing operations
slide-16
SLIDE 16

16

Well Positioned to Manage Through Downturn

  • Fleet highgrading

– 7 newbuild rigs with differentiated designs under construction – major upgrade investments expected to benefit 2015 – mooring capability to be added to select ENSCO 8500 Series rigs – 7 held-for-sale rigs as of 4Q14; 19 rigs sold since beginning of 2010 – 2015 results to benefit from newbuilds and prior upgrades

  • Expense management discipline
  • Leading net income margins among major competitors
slide-17
SLIDE 17

17

Well Positioned to Manage Through Downturn

  • Capital management flexibility
  • Global presence and diverse customer base

– operations across six continents – extensive customer relationships: NOCs, Majors, IOCs

slide-18
SLIDE 18

18

Organic Growth: Newbuild Contracts/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 DS-8 ENSCO DS-9 ENSCO 110 ENSCO DS-10 ENSCO 123 ENSCO 140 ENSCO 141 Drillships Premium jackups

2013 2016 2017 2014 2015 2020 2018 2019

5 yrs with Total 5 yrs with Total 3 yrs with ConocoPhillips 3 yrs with ConocoPhillips 2 yrs w/ Wintershall 2 yrs w/ Wintershall 2 yrs with NAM 2 yrs with NAM 2+ yrs with Nexen 2+ yrs with Nexen 3 yrs with Total 3 yrs with Total

Contracted

slide-19
SLIDE 19

19

9 11

PREMIUM JACKUPS ULTRA & DEEP WATER DRILLSHIPS MOORED SEMISUBMERSIBLES DYNAMICALLY POSITIONED SEMISUBMERSIBLES

Note: Includes rigs under construction and excludes managed rigs and rigs in discontinued operations

High Quality Fleet

63 Rig Fleet

3 40

slide-20
SLIDE 20

20

U.S. Gulf of Mexico

Ships

3

Semis

6

Jackups

7 Africa

Ships

3

Jackups

1 Europe & Mediterranean

Semi

1

Jackups

11 Middle East

Jackups

9 Asia Pacific

Semi

3

Jackups

8 Brazil

Semis

4 Under Construction

Ships

3

Jackups

4

20

Global Platform

Held for Sale

Ships

1

Semis

4

Jackups

2

slide-21
SLIDE 21

21

Backlog Diversification

Drillships

40% 30% 30%

North & South America Africa Brazil

27% 13% 24% 15%

Europe & Med Asia Pacific

11%

National Oil Companies Majors Independents

25% 29% 46%

Middle East

10%

Premium Jackups Semis

Note: Contract revenue backlog as of 31 December 2014 plus drilling contracts signed and shortened through 23 February 2015

slide-22
SLIDE 22

22

Uptime = Net Inc. Margin = Customer Satisfaction

Source: Thomson One. 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. For our reported net income and revenue, please see our Annual Report on Form 10-K filed on March 2, 2015.

ESV SDRL DO NE RIG RDC 30% 28% 19% 18% 18% 15%

Net Income Margin

slide-23
SLIDE 23

23

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

Industry Leader in Customer Satisfaction

slide-24
SLIDE 24

24

  • Leading-edge safety

management systems

  • Major competitive

advantage; especially versus non-established drillers

Safety, Health & Environment

0.0 0.2 0.4 0.6 0.8 1.0 1.2 2008 2009 2010 2011 2012 2013 2014

Ensco Industry

Total Recordable Incident Rate

Note: 2014 TRIR for Industry is as of 4Q14

slide-25
SLIDE 25

25

Capital Management and Financial Position

  • Reduced quarterly dividend to $0.15 from $0.75
  • Investment-grade credit ratings from Moody’s/S&P
  • $9.7 billion of contracted revenue backlog
  • 42% total debt-to-capital ratio
  • $1.4 billion of cash and short-term investments
  • $2.25 billion available revolving credit facility

Note: as of 31 December 2014

slide-26
SLIDE 26

26

Contracted Revenue Backlog

2015 2016 2017 2018+ $3.9 $2.8 $1.7 $1.3

$ billions

Note: Contract revenue backlog as of 31 December 2014 plus drilling contracts signed and shortened through 23 February 2015

slide-27
SLIDE 27

27

Capital Expenditures

2015 2016 2017

1.60 0.40 0.25 TBD TBD 0.25 TBD TBD

Newbuild construction Rig enhancements Sustaining

$ billions

Note: Final rig enhancement and sustaining project capital expenditure budgets for 2016 and 2017 TBD once budgets are completed. Zero capital expenditures for newbuild construction in 2017.

~$2.1B <$1.0B

slide-28
SLIDE 28

28 $35 $1,020 $5 $5 $505 $905 $1,500 $625 $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

Debt Maturity Profile

2027 2040 $150 $300 2044 $625

Note: As of 31 December 2014

Raised $1.25B in September 2014 Upsized RCF to $2.25B in September 2014

$ millions

slide-29
SLIDE 29

29

  • Leader in customer satisfaction – five consecutive years
  • Highest net income margins among major competitors
  • Best ever total recordable incident rate in 2014
  • High-quality fleet of floaters and jackups

– 10 year average age for go-forward floater fleet

  • 4 year average age for ultra-deepwater fleet
  • Technology advantages, e.g. ENSCO 120 Series jackups and

Samsung GF 12,000 drillships

  • $9.7 billion of contracted revenue backlog
  • Disciplined expense management
  • Capital management flexibility

Ensco’s Strengths

slide-30
SLIDE 30

30