1 Investor Presentation 29 October 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 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, day rates and backlog, estimated rig availability; rig commitments; contract duration, status, terms and other contract commitments; new rig commitments and construction; scheduled delivery 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 stacking costs; 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 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; 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 2 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.
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 3
Current Market Conditions Global exploration spend of • Substantial reduction in 18 largest E&Ps $ billions E&P capex $58 $60 • Unprecedented decline in $50 exploration spending $41 $40 • Lower rig utilization & day $29 rates $30 • Expect 2016 capex to be $20 lower YoY $10 • The significant pullback in $0 spending will affect supply in the future 4 Source: IHS Upstream
Market Response • 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 5
• Capital Management Taking Decisive • Fleet Restructuring Steps To Be Resilient • Expense Management Through The • Operational Excellence & Safety Downturn – innovation – process improvements 6
Proactive Capital Management • 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 7
Debt Maturity Profile $ millions $3,000 $2,700 No debt Increased Revolving Credit Facility to $2,400 maturities $2.25B; extended to 2019 until 2Q19 $2,100 $1,800 $2,250 $1,500 $1,500 $1,200 $1,025 $900 $900 $625 $700 $500 $600 $300 $300 $150 $0 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2027 2044 2040 8
Credit Ratings • $1.1 billion of cash and short-term investments • $6.6 billion of contracted revenue backlog BBB BBB BBB- Investment BBB- Grade BB BB- B- CCC- Not Rated ESV DO NE RDC RIG ATW PACD ORIG SDRL Source: Bloomberg composite credit ratings as of October 2015; cash, short-term investments and contracted revenue backlog as of 30 September 9 2015
Declining Capital Expenditures $ millions $625* $555* 125 25 150 80 $205 $150* 475 55 325 30 150 120 4Q15 2016 2017 2018 New rig construction Rig enhancements Minor upgrades and improvements *Note: Preliminary estimates for rig enhancement and minor upgrade and improvements for 2016, 2017 and 2018; final capex estimates to be 10 determined upon completion of annual budget process and subject to change based on rig contracting; year-to-date capital expenditures through 30 September 2015: $1,130 million of new rig construction, $145 million of rig enhancements and $170 million of minor upgrades and improvements
Fleet Restructuring: Newbuild Deliveries 2012.75 2013.75 2014.75 2015.75 2016.75 2017.75 2018.75 2019.75 2014 2015 2016 2017 2018 2019 2020 2013 ENSCO DS-7 4 yrs with Total 4 yrs with Total ENSCO 120 2+ yrs with Nexen 2+ yrs with Nexen ENSCO 121 2 yrs w/ Wintershall 2 yrs w/ Wintershall Delivered & Contracted ENSCO 122 2 yrs with NAM 2 yrs with NAM 3 yrs with NDC 3 yrs with NDC ENSCO 110 5 yrs with Total 5 yrs with Total ENSCO DS-8 Delivered and On ENSCO DS-9 2 yrs on operating rate* 2 yrs on operating rate* Operating Rate ENSCO 123 Under ENSCO 140 Construction & ENSCO 141 Uncontracted ENSCO DS-10 Drillships Premium jackups *Note: Customer has terminated contract for its convenience. Per terms of contract for early termination, customer is required to make monthly 11 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.
Upgrades to Existing Floaters • 2014 floater upgrades benefitting 2015 results – ENSCO 5004 – ENSCO 5006 • Mooring upgrade for ENSCO 8503 contracted to Stone Energy and ENSCO 8505 contracted to Marubeni 3 rd ENSCO 8500 Series • floater to receive mooring upgrade in 2016 12
Fleet Restructuring: Divestitures • 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 13
Expense Management Actions 15% reduction in offshore unit labor costs + $57 million annual savings in onshore support costs • 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 14
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