Pacific Drilling (PACD) 6-K Current report (foreign)

Exhibit 99.1

Creditor Presentation January 2, 2017

Disclaimer 2 Disclaimer THIS PRESENTATION IS NOT AN OFFER OR INVITATION TO BUY OR SELL SECURITIES IN ANY JURISDICTION. This presentation contains summary information only and does not purport to be comprehensive and is not intended to be (and should not be used as) the sole basis of any analysis or other evaluation. No representation or warranty, express or implied, is made or given by or on behalf of us or any of our respective directors, officers, employees, agents, affiliates, advisors or any person acting on their behalf, as to, and no reliance should be placed on, the accuracy, completeness or fairness of the information or opinions contained in this presentation and no responsibility or liability is assumed by any such persons for any such information or opinions or for any errors or omissions. All information presented or contained in this presentation is subject to verification, correction, completion and change without notice. In giving this presentation, neither we nor any of our respective directors, officers, employees, agents, affiliates, advisors or any person acting on their behalf, undertakes any obligation to amend, correct or update this presentation or to provide the recipient with access to any additional information that may arise in connection with it. Neither we nor any of our respective directors, officers, employees, agents, affiliates, advisors or any person acting on their behalf, shall have any liability whatsoever (in negligence or otherwise) for any loss whatsoever arising from any use of this presentation, or otherwise arising in connection with this presentation. This presentation has been prepared for information purposes only, and does not constitute or form part of, and should not be construed as, any offer, invitation or recommendation to purchase, sell or subscribe for any securities in any jurisdiction and neither the issue of the information nor anything contained herein shall form the basis of or be relied upon in connection with, or act as an inducement to enter into, any investment activity. This presentation does not purport to contain all of the information that may be required to evaluate any investment in the company or any of its securities and should not be relied upon to form the basis of, or be relied on in connection with, any contract or commitment or investment decision whatsoever. This presentation is intended to present background information on our company, its business and the industry in which it operates and is not intended to provide complete disclosure upon which an investment decision could be made. The terms “Adjusted EBITDA” and “Adjusted EBITDA Margin” used in this presentation are non–GAAP financial measures, and the reconciliations to the most comparable GAAP financial measures are available on our website at www.pacificdrilling.com. Forward-looking Statements Certain statements and information contained herein constitute “forward-looking statements” within the meaning of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995, and are generally identifiable by the use of words such as “believe,” “estimate,” “expect,” “forecast,” “our ability to,” “plan,” “potential,” “projected,” “target,” “would,” or other similar words, which are generally not historical in nature. The forward-looking statements speak only as of the date hereof, and we undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise. Our forward-looking statements express our current expectations or forecasts of possible future results or events, including our future financial and operational performance; revenue efficiency levels; market outlook; forecasts of trends; future client contract opportunities; contract dayrates; our business strategies and plans and objectives of management; estimated duration of client contracts; backlog; our ability to repay our debt; expected capital expenditures and projected costs and savings. Although we believe that the assumptions and expectations reflected in our forward-looking statements are reasonable and made in good faith, these statements are not guarantees and actual future results may differ materially due to a variety of factors. These statements are subject to a number of risks and uncertainties, many of which are beyond our control. Important factors that could cause actual results to differ materially from our expectations include: the global oil and gas market and its impact on demand for our services; the offshore drilling market, including reduced capital expenditures by our clients; changes in worldwide oil and gas supply and demand; rig availability and supply and demand for high-specification drillships and other drilling rigs competing with our fleet; costs related to stacking of rigs; our ability to enter into and negotiate favorable terms for new drilling contracts or extensions; our substantial level of indebtedness; possible cancellation, renegotiation, termination or suspension of drilling contracts as a result of market changes or other reasons; and the other risk factors described in the Company’s filings with the SEC, including the Company’s Annual Report on Form 20-F and Current Reports on Form 6-K. These documents are available through the Company’s website at www.pacificdrilling.com or through the website of the U.S. Securities & Exchange Commission at www.sec.gov.

Contents I. Company Overview II. Oil and Offshore Rig Market Outlook III. Summary of Illustrative Scenarios Scenario A Scenario B 3

I. Company Overview 4

5 Incorporated in 2008, operational since 2010 The only pure-play high specification ultra-deepwater offshore driller Proven experience in Nigeria, US GOM and Brazil with leading deepwater operators Strong, experienced management team 7 drillships of the highest specification No newbuild commitments ~1,000 employees Pacific Drilling at a Glance Pacific Drilling is well positioned to benefit from the market’s recovery

6 Modern, competitive, and homogeneous fleet Pacific Mistral (Construction completed 2011) Pacific Bora (Construction completed 2010) Pacific Scirocco (Construction completed 2011) Pacific Santa Ana (Construction completed 2011) Pacific Khamsin (Construction completed 2013) Pacific Sharav (Construction completed 2014) Pacific Meltem (Construction completed 2014)

Pacific Drilling distinguished by operational excellence and cost management Operational excellence more important than ever: expect market to be very tough for at least 18 months - Clients want rigs that deliver - PACD management focused on minimizing downtime and maximizing rig efficiency - PACD has highest average rig capability and industry-leading UDW operating performance Cost management is key, while maintaining longer-term optionality and marketability - Cost savings initiatives generating > $160 million in annual run rate savings compared to 2014 peak, which is a reduction of >30% - Opex reduced by approximately $54,000 per day per operating rig since beginning of 2014 - Maintaining ability to restart idle rigs within 90 days of contract award, while significantly reducing smart stacking costs to ~$30k per day per rig Succeeding in a Tough Market 7

Clients want rigs that deliver Mean 96.4% Exceptional Service Quality and Revenue Capture 8 Last 19 rig-years at >95% average uptime Highest efficiency rigs in the industry - Sharav ran two casing strings in excess of 2 million pounds - Bora, Mistral and Scirocco completed 5-Year regulatory class inspections with no impact on revenue and no significant capex - Khamsin added a second BOP onboard, fully commissioned in-house Post-shakedown fleet revenue efficiency Mean 96.4% (%) 100 95 90 85 80 75 70 65 60 55 50 2014 Q2 2014 Q3 2014 Q4 2015 Q1 2015 Q2 2015 Q3 2015 Q4 2016 Q1 2016 Q2 2016 Q3 97.1 95.9 98.4 95.2 95.5 90.8 97.3 97.7 99.0 97.0

Strong Cost Management 9 Daily Rig Opex ($’000) 9 120,000 130,000 140,000 150,000 160,000 170,000 180,000 190,000 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16

PACD Has Led the Industry with Smart Stacking, which Is Operationally Comparable to Hot Stacking 10 Pre-Smart Stack (Ramp Down) Initial stage critical to success of eventual Ramp-Up Total top down cleaning of rig Comprehensive equipment health-check is performed 1-year Preventive Maintenance System (PMS) routine performed at minimum for all equipment 5-yearly PMS routine performed on all drilling equipment Any PMS routines due in next 2.5 years are performed Smart Stacking keeps the rig in an advanced hot status – ready to work in 90 days Smart stacking efficiencies have lowered daily costs from initial forecasted levels of $80-$100k/d to ~$30k/d Smart-Stack Period All equipment is kept in hot condition and periodically functioned Minimum crew of 15 persons is retained on board to maintain Class compliance and perform maintenance 90-day Back-to-Work List is continuously monitored to ensure Ramp Up will be executed in the time frame “Marketing crew” maintained for immediate deployment to any contracted rig Post-Smart Stack (Ramp Up) 90-day ramp up includes mobilization, country-specific approval/permits and 3rd party installation Crew Ramp-Up assembles full rig crew and includes refresher training and maintenance Maintenance routines are reactivated to operational mode Drilling Simulation tests and client acceptance testing is performed 10

II. Oil and Offshore Rig Market Outlook 11

Market Outlook Summary 12 Anticipated Supply Gap Will Drive Deepwater Drilling Recovery Demand growth, combined with declining production, is expected to create a ‘supply gap’ that will require significant new production, a large portion of which must be achieved through offshore / deepwater exploration and production Uninterrupted growth in demand for oil continues The significant drop in wells drilled (~44%) is expected to keep decline rates above historical levels in the near term Current exploration activity is not adequate to replace reserves Offshore / Deepwater is Essential to Future Global Oil Supply and is Becoming More Cost-Competitive The future supply gap that is being created through expenditure cuts will increase the call on offshore / deepwater Pressure on OPEC to reduce supply, and non-OPEC supply declining Deepwater is critical to the majors Offshore/deepwater a substantial portion of commercial reserve base Insufficient alternatives to offshore/deepwater The current low number of new offshore project sanctions and reduced spending must ultimately be reversed The majors have achieved significant cost reductions, making deepwater projects more attractive at lower oil prices Shell: Project breakevens for pre-FID deepwater projects have been reduced to $45 per barrel on average Statoil: Average breakeven prices for future projects on Norwegian continental shelf have been reduced from $70 per barrel to approximately $40 per barrel BP (Mad Dog Phase 2, GoM): Cost estimates reduced to less than $9 billion from prior estimate of $20 billion

Market Outlook Summary (Cont’d) 13 Offshore Services Industry is Cutting Costs and Increasing Efficiency, Contributing to Deepwater Competitiveness Raft of strategic combinations and alliances among offshore service companies aimed at driving down costs and enhancing production efficiency through process efficiencies, standardisation, new technology and consolidation, for example: Merger of FMC and Technip (integrated “wellhead to topside” approach) Schlumberger’s OneSubsea JV and subsequent acquisition of Cameron (integrated “reservoir to wellhead” approach) OneSubsea’s SURF and offshore well intervention alliances with Subsea 7 and Helix, respectively Rebalancing of Offshore Rig Supply is Already Underway Retirement of older, less capable assets already underway Significant number of rigs have already left the market and more will follow: 60+ floaters have been retired since Q3 2014 30+ floaters > 30 years that are idle without follow-on work could be retired 20+ floaters > 30 years that have contracts expiring before YE 2017 could also be retired Large number of newbuild delays and cancellations 6G and 7G rigs will become increasingly important Modern high-spec drillships are already preferred in all water depths Path to supply-demand balance is visible Historical data shows that when marketed utilisation reaches c88%, dayrates increase exponentially Pacific Drilling is Well Positioned to Continue to be a Leader as the Market Recovers Pacific Drilling, with its young, high spec fleet is competitively well positioned to produce significant cash flow in a recovering market

Oil Supply-Demand Balance Forecast through 2020 Forecast Note: assumes 5% decline rate on existing production 2018-2020 Demand Growth Combined with Increasing Decline Rates Will Require Significant New Production 14 65 70 75 80 85 90 95 100 105 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Million Barrels per Day Supply Supply Inventory Demand New Demand (+1.2mmb/d)

mmb/d Year-over-year change in world demand varies but averages ~1.3 mmb/d in recent years Growth still expected to remain strong from an historical perspective, even though macro events have caused a projected reduction in the rate of growth Non-OECD Asia is expected to be the major source of oil demand growth Uninterrupted Growth in Demand for Oil Continues 15 Source: IEA Oil Markets Reports World oil demand has never declined y-o-y on an absolute basis in modern history 1.1 1.2 1.3 1.0 1.8 1.4 1.3 0 0.5 1 1.5 2 2011 2012 2013 2014 2015 2016 2017 Year - Ov er - Year mmb/d Growth in World Oil Demand Historic Oil Demand Growth Projected Oil Demand Growth

16 The Significant Drop in Wells Drilled (~44%) is Expected to Keep Decline Rates Above Historical Levels Wells Drilled Globally Average Decline Rates for Mature Oil non-OPEC fields, %

Current Exploration Activity Not Adequate to Replace Reserves 17 Conventional Oil and Gas Discoveries Bn-bbl US-$bn Conventional Exploration Expenditure 0 10 20 30 40 50 60 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 Oil and condensate Gas 0 20 40 60 80 100 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016

~1mmb Resource development needs to start >3 years in advance of production to fill gap Supply Growth Potential Supply- Demand Gap The Expected Supply Gap Will Require All Available Sources and Increase the Call on Offshore/Deepwater 18 ~4mmb ~7mmb According to the EIA, OPEC supply rose to a record 33.6 mb/d in September 2016, but the OPEC group has agreed to cut supply to between 32.5 mb/d and 33 mb/d, with the details to be set by end-November 2016. Non-OPEC supply is forecast to drop by 0.9 mb/d in 2016, affected significantly by changes in U.S. tight oil production, which has high decline rates for production and relatively short investment horizons 0 5 10 15 20 2018 2019 2020 Potential Call on Deepwater beyond Sanctioned Projects Demand Gap (prev slide) Opec Spare Capacity 50% of Disruptions back Online Shale (+1mmb annually) Conventional Storage to Normal Levels Offshore Sanctioned

Offshore Greenfield Project Commitments Historically low project sanctions in 2016 Less than half volumes from 2011-2014 The Current Low Number of New Offshore Project Sanctions and Reduced Spending Must Ultimately be Reversed 19 Oil Production Capex Forecast Spending is projected to drop ~60% from 2014-16, then recover at a ~16% CAGR Cost deflation (including rig dayrates) means spending estimates portray a stronger demand for rigs and services than the top line numbers indicate Analyst estimates for offshore capex show a 10-15% decline in 2017, with a 10-15% recovery in 2018 US-$bn

Costs have declined to ~2007 levels Index has fallen ~30% but this decline only represents realized changes Brownfield/tie-back projects have even greater cost deflation due to drilling costs as a percent of total costs More than 400 deepwater discoveries have yet to be developed Deepwater cost reductions have not fully worked through the system due to long term nature of offshore projects Standardization, development redesigns, cost deflation, and supplier consolidation can deliver sustainable project improvements The Majors Have Achieved Significant Cost Reductions Making Deepwater Projects More Attractive at Lower Oil Prices 20 Cost Index (2000=100) $/BOE -20% -20% 100 120 140 160 180 200 220 240 2000 2002 2004 2006 2008 2010 2012 2014 2016 IHS Upstream Capital Cost Index 0 25 50 75 2014 costs Near-term realized costs Mid-term potential costs Avg. GOM Greenfield Break - even Costs Development Drilling Facilities Equipment Subsea Operating expense Government take

8 Contracted vs Available Rigs by Generation Contracted 6th gen Contracted 5th gen Contracted Below 5th gen Demand, ranged (source: Analyst Range) 2016 2017 2018 2019 2020 Uncontracted 6th gen Uncontracted 5th gen Uncontracted Below 5th gen Expected Cold Stacking/Scrapping Undelivered Newbuilds 21 Rebalancing of Offshore Rig Supply Already Underway Recovery Timeframe Late 2017 – Mid 2019

# of Rigs Delivered Total # of Floaters in Fleet Significant Number of Old Rigs Have Already Left the Market and More Will Follow 22 0 40 80 120 160 200 240 280 320 0 5 10 15 20 25 30 35 40 1970 1975 1980 1985 1990 1995 2000 2005 2010 2015 2020 Floater Fleet by Delivery Year Removed From Fleet Total Floater Fleet (RHS)

Projected Floater Fleet Changes Note: Cold stacking is assumed after a rig is stacked for more than six months or after announced Abs. Growth % Change 6th Gen + 11 11% 5th Gen -31 -39% 4th Gen -19 -55% 3rd Gen - -111 -74% Additions include 40 newbuilds (7 Sete) to be delivered through 2018, though we believe all are at risk for delays and some for cancellation Additions Removals (355) (206) 6G and 7G Rigs Will Become Increasingly Important 23 103 49 15 40 End of 2018 92 79 34 150 2015 Peak Fleet -100 -80 -60 -40 -20 0 20 40 Prior Scrapped Prior Cold Stacked 2016 2017 2018

Floater Fleet Utilization Modern High-Spec Drillships are Already Preferred in All Water Depths 24 60% 34% 6% High - Spec Floater Operating Depth Less than 4,500 4,500-7,499 7,500 or greater 23% 9% 68% Current Floater Market Areas Harsh Environment Niche Market Global Temperate 30% 40% 50% 60% 70% 80% 90% 100% 2008 2009 2010 2011 2012 2013 2014 2015 2016 Utilization 0-10 years (~6th Gen) Utilization 10-20 years (~5th Gen) Utilization 20-30 years (~4th Gen) Utilization >30 years (~3rd Gen)

8 Contracted vs Available Rigs by Generation Contracted 6th gen Contracted 5th gen Contracted Below 5th gen Demand, ranged (source: Analyst Range) 2016 2017 2018 2019 2020 Recovery Timeframe Late 2017 – Mid 2019 Note: marketed utilization of 88% excludes undelivered newbuilds Uncontracted 6th gen Uncontracted 5th gen Uncontracted Below 5th gen Undelivered Newbuilds 88% marketed utilization Mid Demand Scenario Low Demand Scenario High Demand Scenario 25 Path to Supply-Demand Balance Is Visible X X X X

Percentage of fleet composition by rig capability and type Pacific Drilling Rig Classification Index (Specification Scale Exclusively Floaters) PACD Has the Newest and Most Capable Fleet To Address this Market Demand 26 100% 79% 40% 42% 30% 20% 18% 13% 15% 14% 14% 8% 21% 20% 18% 15% 7% 8% 27% 13% 46% 7% 43% 42% 21% 47% 18% 87% 63% Pacific Drilling Ocean Rig Seadrill Atwood Transocean Noble Diamond Offshore Rowan Ensco High Spec Standard Spec Low Spec Jackup

III. Summary of Illustrative Scenarios Scenario A Scenario B 27

Illustrative Scenarios Pacific Drilling generally does not publicly disclose detailed prospective financial information. However, in connection with its discussions of a restructuring with its creditors and their advisors, Pacific Drilling developed illustrative financial scenarios reflecting two different scenarios for the timing and speed of a drilling market recovery. These scenarios do not constitute financial forecasts or reflect management’s expectations of its forecast financial performance. Management of Pacific Drilling prepared these illustrative financial scenarios from information provided by industry market data providers and internal financial information based on reasonable expectations, beliefs, opinions, and assumptions of management at the time they were made. The illustrative financial scenarios were not prepared with a view towards public disclosure and were not prepared in accordance with generally accepted accounting principles (“GAAP”) or published guidelines established by the American Institute of Certified Public Accountants for preparation and presentation of “prospective financial information.” The inclusion of the illustrative financial scenarios in this presentation should not be regarded as an indication that Pacific Drilling or any other person considered, or now considers, this information to be predictive of actual future results, and does not constitute an admission or representation by any person that such information is material, or that the expectations, beliefs, opinions, and assumptions that underlie such illustrative financial scenarios remain the same as of the date of this Current Report on Form 6-K, and readers are cautioned not to place undue reliance on the prospective financial information. Neither the independent auditor of Pacific Drilling or any other independent accountant has examined, compiled, or performed any procedures with respect to the prospective financial information contained herein and, accordingly, none has expressed any opinion or any other form of assurance on such information or its achievability and none assumes any responsibility for the prospective financial information. The prospective financial information: - is speculative by its nature and was based upon numerous expectations, beliefs, opinions, and assumptions, as further described below, which are inherently uncertain and many of which are beyond the control of the Companies and may not prove to be accurate; - does not necessarily reflect current estimates or expectations, beliefs, opinions, or assumptions that the management of Pacific Drilling may have about prospects for the Companies’ business, changes in general business or economic conditions, or any other transaction or event that has occurred or that may occur and that was not anticipated at the time the information was prepared; - may not reflect current results or future performance, which may be significantly more favorable or less favorable than as set forth below; and - is not, and should not be regarded as, a representation that any of the expectations contained in, or forming a part of, the illustrative financial scenarios will be achieved. All of the financial information contained in this section entitled “Summary of Illustrative Scenarios” is forward-looking in nature. The information is subjective in many respects and thus subject to interpretation. Further, the information relates to multiple future years and such information by its nature becomes less predictive with each succeeding year. Pacific Drilling cannot provide assurance that the financial projections will be realized; rather, actual future financial results may vary materially from the forward-looking information presented herein. Except as required by law, Pacific Drilling does not currently intend to update or revise publicly any of the information presented herein to reflect circumstances or other events occurring after the date the financial projections were prepared or to reflect the occurrence of future events. These considerations should be taken into account in reviewing the illustrative financial scenarios, which were prepared as of an earlier date. For additional information on factors that may cause actual future financial results to vary materially from the information presented herein, see the section entitled “Cautionary Note Regarding Forward-Looking Statements” on the first slide of this presentation. The following information was prepared for the particular purpose of undertaking discussions with creditors and not for the purpose of assessing the value or investment merits of our debt or equity and so should not be used for that purpose. 28

Overview of Illustrative Scenarios Revenue Drivers The Company has prepared two illustrative scenarios (the “Illustrative Scenarios”) (i) A scenario (“Scenario A”) which is consistent with the “Low Demand Scenario” illustrated in the Market Outlook section presented earlier (see page 25) (ii) A second more conservative scenario (“Scenario B”) which assumes that the recovery reflected in Scenario A is deferred by approximately one year (even though Scenario A is based on the “Low Demand Scenario”) Key revenue drivers include the following 29 Average dayrate for New Contracts ($’000) Rigs Employed on New Contracts (#) The sole existing contract beyond H1 2017 is for the Sharav at $551k/day, ending in Q2 ‘19 New Contracts Only 100 150 200 250 300 350 400 450 500 550 600 1H 17 2H 17 1H 18 2H 18 1H 19 2H 19 1H 20 2H 20 1H 21 2H 21 1H 22 2H 22 - 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 1H 17 2H 17 1H 18 2H 18 1H 19 2H 19 1H 20 2H 20 1H 21 2H 21 1H 22 2H 22 - 500 2H 16 1H 17 2H 17 1H 18 2H 18 1H 19 2H 19 1H 20 2H 20 1H 21 2H 21 1H 22 2H 22 Scenario A Scenario B Scenario C

Overview of Illustrative Scenarios Other Key Assumptions Key operating cost and other cash flow drivers include the following 30 Fleet Opex Between $135k and $151k per day for contracted vessels1 $30k per day for smart-stacked rigs Depreciation c.$37m per vessel per year Other Expenses Shore-based expenses – Between $21m and $39m per annum SG&A – Between $53m and $58m per annum Survey costs – c.$3m per annum CapEx $16m in 2H 2016, $29m in 2017, $4m in 2018, $16m in 2019 Working Capital Receivable days: 50 – 60 Payable days: 30 – 40 Taxes 1.5% (GoM and Brazil) or 6.0% (Nigeria) of contract drilling revenue Other Operating Assumptions (1) Excludes MPD

Scenario A Overview Summary Earnings and Cash Flows Scenario A projects the beginning of a market recovery in 2018 and significantly increased revenue and Adjusted EBITDA during the period 2019 through 2022 The reduction in Adjusted EBITDA that began in 2016, reflecting lower utilization and day rates as existing contracts roll off, is expected to bottom in 2017 31 Revenue ($m) Adjusted EBITDA ($m) 5.3 5.1 3.8 5.5 7.0 7.0 Rig years 2.0 7.0 106 117 103 22 62 92 109 44 109 7.0 Actuals Forecasts Adj. EBITDA / rig year - 200 400 600 800 1,000 1,200 1,400 2014 2015 2016 2017 2018 2019 2020 2021 2022 - 200 400 600 800 1,000 1,200 1,400 2014 2015 2016 2017 2018 2019 2020 2021 2022

Scenario A Overview Summary Unlevered Free Cash Flow Projected unlevered free cash flow is expected to reflect a positive pattern, beginning in 2018, similar to that of projected Adjusted EBITDA 32 Annual Unlevered Free Cash Flow ($m) Cumulative Unlevered Free Cash Flow ($m) - 100 200 300 400 500 600 700 800 900 2017 2018 2019 2020 2021 2022 - 500 1,000 1,500 2,000 2,500 3,000 2017 2018 2019 2020 2021 2022

Scenario B Overview Summary Earnings and Cash Flows 33 Revenue ($m) Adjusted EBITDA ($m) Scenario B projects the beginning of a market recovery in early 2019 and increased revenue and Adjusted EBITDA during the period 2019 through 2022, albeit at lower levels than in Scenario A until 2022 when normalized results are expected again The reduction in Adjusted EBITDA that began in 2016, reflecting lower utilization and day rates as existing contracts roll off, is expected to bottom in 2018 rather than in 2017 as it is in Scenario A 5.3 5.1 3.8 1.5 6.0 7.0 7.0 Rig years 1.5 7.0 106 117 103 31 39 80 109 Adj. EBITDA / rig year 50 107 Actuals Forecasts - 200 400 600 800 1,000 1,200 1,400 2014 2015 2016 2017 2018 2019 2020 2021 2022 - 200 400 600 800 1,000 1,200 1,400 2014 2015 2016 2017 2018 2019 2020 2021 2022

Scenario B Overview Summary Unlevered Free Cash Flow Projected unlevered free cash flow in Scenario B is expected to reflect a positive pattern beginning in 2019 similar to that of projected Adjusted EBITDA, albeit at lower levels than in Scenario A until 2022 when normalised results are expected again 34 Annual Unlevered Free Cash Flow ($m) Cumulative Unlevered Free Cash Flow ($m) (100) - 100 200 300 400 500 600 700 800 900 2017 2018 2019 2020 2021 2022 - 500 1,000 1,500 2,000 2,500 2017 2018 2019 2020 2021 2022