GHS100 Energy Conference June 25, 2012

GHS100 Energy ConferenceChris Beckett, CEOJune 25, 2012

Disclaimer • 1• This presentation contains statements that express opinions, expectations, beliefs, plans, objectives, assumptions or projections of Pacific Drilling S.A. (the “Company” or “Pacific”) regarding future events or future results, in contrast with statements that reflect historical facts. Examples include discussion of our strategies, financing plans and growth opportunities. In some cases, we have identified such forward-looking statements with typical conditional words such as “anticipate,” “intend,” “believe,” “estimate,” “plan,” “seek,” “project” or “expect,” “may,” “will,” “would, “could” or “should,” the negative of these terms or other comparable terminology. These forward-looking statements are not a guarantee of performance and you should not place undue reliance on such statements. We have based these forward-looking statements largely on our current expectations and projections about future events. Forward-looking statements are subject to many risks, uncertainties and other variable circumstances that may cause the statements to be inaccurate and readers are cautioned not to place undue reliance on such statements. Many of these risks are outside of our control and could cause our actual results and experience to differ materially from those we thought would occur. The forward-looking statements included in this presentation are made only as of the date hereof. We do not undertake, and specifically decline, any obligation to update any such statements or to publicly announce the results of any revisions to any of such statements to reflect future events or developments.• This presentation does not constitute an offer to sell or a solicitation of an offer to buy the Company’s common shares. 2

Who is Pacific Drilling? Focus on the Growing Ultra- Deepwater Market Pure-Play Commitment Ultra-Financial to DeepwaterStrength Shareholder Drillship Value Asset Base Dedication to Operational Excellence 3

A Global Growth Market Areas With Active Ultra-deepwater Rig Programs In 2012 Core Areas US Gulf of Mexico • Attractive fiscal terms • Lower Tertiary ultra-deep wells Brazil • Pre-salt success • Light oil & gas West Africa • Long-lead time developments Emerging Areas East Africa • Major gas discoveries Other West Africa HQ • Increasing activity in Ghana, Liberia, Namibia, Cote d’IvoireOperations Mexico • Similar geology to US GOM Support Under-explored Regions • Mediterranean, Malaysia, Core areas Brunei, Indonesia, India, S. Emerging areas China Sea, Black Sea, Atlantic Canada / Greenland, Suriname and Guyana Pacific Drilling present in all core ultra-deepwater areas 4

Advanced Drillships Deliver on Industry Requirements Industry Trends Over 50% Of Floaters Greater than 10 Years Old•1 Challenges of remote drilling sites•2 Drilling deeper and with longer offsets 40%•3 Greater drilling efficiency to reduce total well costs 48%•4 Advances in well construction 10%•5 More demanding downhole environments, e.g. high 2% pressure & temperature drilling Rig Age in Years(1) Over 20 10 to 20 5 to 10 Under 5•6 Increasingly demanding regulatory climate…Supports ”bifurcation” in the market due to increased willingness to pay for newer, higher spec rigs 5

UDW Demand Expected to Exceed Supply Through 2014(2) Supply and Demand Forecast 185 170 168 150 149 19 128 21 17 149 128 111Supply Demand Supply Demand Supply Demand 2012 2013 2014 Newbuild Rigs Existing UDW Fleet 6

Recent Pricing and Utilization Data Indicate Cyclical Upswing Contract Dayrates and Utilization for 5th Gen and Later Ultra-Deepwater Floaters(3)Day rate, $K/d %700 100650 95600 90550 85500 80450 75400 70 5/11 6/11 7/11 8/11 9/11 10/11 11/11 12/11 1/12 2/12 3/12 4/12 5/12 6/12 7/12 Contract Length (LHS) 1-3 Years >3 Years Contract Trend (LHS) Utilization (RHS) 7

Newer Rigs Enjoy Higher Utilization Rates Throughout Cycle Current Floater Fleet by Delivery Year(4) Floater Utilization since 2008 by Build Cycle(4)40 100 2007-Current 1998-200635 9530 9025 1979-199720 8515 8010 75 1971-197850 70 Apr Apr Apr Apr Apr Oct Oct Oct Oct Jan Jan Jan Jan Jan Jul Jul Jul Jul 1985 1971 1975 1980 1990 1995 2000 2005 2010 2008 2009 2010 2011 2012 8

Pacific Drilling: Most Modern, Pure Play UDW Fleet Average Floater Fleet Depth and Age (6)More Modern 2020 2015 2010 Seadrill Ocean RigAverage Year Built 2005 Ensco Songa North Atlantic Drilling 2000 1995 Atwood Noble 1990 Transocean 1985 Area of bubble represents Fred Olsen Energy total enterprise value (5) 1980 Diamond Offshore 1975 Deeper Water 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 11,000 12,000 9 Average Water Depth (Ft.)

Fleet Capabilities Designed to Satisfy Customer Demands Consistent, Proven Design & Drilling Delivers Fleet-wide Operating Synergies Package Fleet-wide Water Depth Capability 10- Provides for Deepest Operating 12,000 ft. Requirements in the Market Dual Derricks with 1000-1250 ST Hook Exceeds Most Demanding Well- Loads construction Requirements2x Single plus Offline & 4x Dual Load Path 5x Optimizes Drilling Efficiencies, Reduces Rigs Critical Path Activities 200 POB Accommodation, 22,000 ST accommodation, Accommodates Needs of Remote and Displacement Complex ProjectsUp to 40,000 ft Drilling Depth with 6 Ram Meets Needs for Redundant Safety BOPs Systems and Latest Regulations 10

Dual Gradient Drilling – Game-Changing Technology A Proven Well Construction Advance Value to Operators• Removes the effect of mud weight in the riser Offshore Magazine (May 1st, 2010) column and provides better pressure control "Its easier, safer, better for the environment, less• Especially important in deeper water and expensive, the risks decrease, and the outcomes are wellbores (e.g. Gulf of Mexico or pre-salt Brazil) more predictable. I think it will be the way we drill• Well is fully controlled in the event of riser deepwater wells in the future.“ disconnect; Safer as well as more efficient -Chevron North America• Should allow operators to access wells which (7) BOEMRE Report (May 2011) were previously problematic or inaccessible “The most impressive aspect of Dual Gradient Drilling is that it is as safe or safer than current conventional drilling techniques…” Value to Pacific Drilling • Sole drilling contractor with knowledge and equipment to provide mud-lift based Dual Gradient Drilling in ultra-deepwater • Anticipate a long-term competitive advantageSource: May 2011 BOEMRE Report “Risk Profile of Dual Gradient Drilling” • Cost to upgrade existing rigs uneconomic 11

Delivering on Promises 1 drilling contract Becoming The Preferred UDW Drilling Contractor signed Closed $200 MM TI letter of credit facilities NYSE listing Ordered one Bora and Scirocco additional drillshipOperations & began drilling Growth operations Closed $300 MMFully-fledged bond financing UDW 3 rigs delivered contractor Four Rigs in 2 drilling contracts operation by signed end Q2 First rig delivered Ordered 2 additional $1.8 Bn financing drillships secured Closed $600 MM Implemented private placement management 2 drilling contractsDevelopment systems signed Building the platform Initiated construction of Built operations support team, over 950 staff to date 4 drillships Startup Formed by the Initial Quantum Pacific Established management team investment Group (QP) 2006 2007 2008 2009 2010 2011 2012 12

Delivering Operational Excellence• Excellent construction and commissioning of 7 drillships at Samsung  Initial 4 rigs delivered on time and on budget  No lost time incidents (LTIs) (nearly 720,000 manhours)• Exceptional post-delivery safety performance  0.41 LTIF(8) (total 2.45 million manhours) First three rigs have achieved over 1 year without an LTI  No LTIs in over 4 rigs years, no LTI on any operating rig• World-class Pacific Bora, Pacific Scirocco, and Pacific Mistral operations  Pacific Bora first rig to enter Nigeria under new local content regulations  Pacific Mistral delivering strong performance against Petrobras KPIs (9)  Achieved 88.9% average revenue efficiency during first quarter 2012 13

$3.2 Billion Backlog With Blue Chip Operators Contract Backlog Total, (10) (11) $ MM Blue Chip Partners (12) Percent of total deepwater developments by operator (2008-12E) Chevron (Bora, Santa Ana, Sharav) 11% Total (Scirocco) Others 10% 1,076 40% 900 10% BP 440 490 289 8% Statoil Bora Scirocco Mistral Santa Ana Sharav 6% 7% 8%Term Shell Petrobras (Mistral)Firm years 3 2 3 5 5 ExxonMobilOptional years 2 3 0 0 0 Pacific Drilling Customer OtherAverage Remaining Contract Backlog Revenue Per Day, $ K • Strong backlog, with additional potential from options 581 590 553 35 106 511 509 78 • Contracts with well-capitalized international oil 53 41 companies 555 475 475 458 468 • Demonstrated ability to secure premium rates (13) Bora Scirocco Mistral Santa Ana Sharav • Proven market acceptance Deferred revenue Contract day rate 14

Balanced Mix of Dayrate Exposure and Contracted Backlog(14) 2012 2013 2014 Options for up toPacific Bora Chevron Nigeria, $475k/d (15) 2 years of 3 year contract additional term Pacific Total Nigeria, $475k/d (15) Options for up to 3 years of Scirocco 2 year contract additional term Pacific Petrobras Brazil, $458k/d (15) Mistral 3 year contract Pacific Chevron USGOM, $468k/d (15)Santa Ana 5 year contract Pacific Delivery: Second Quarter 2013 Khamsin Pacific Chevron USGOM, $555k/d (15) Delivery: Fourth Quarter 2013 5 year contract Sharav Pacific Delivery: Second Quarter 2014 Meltem 15

Strong Initial Funding for Rigs Capital Expenditure vs. Funding Sources, $B 1.7 Project Facilities Agreement3.2 Equity contribution Remaining debt to be from sponsor closed by 1Q2013 0.9 1.5 1.2 Remaining debt to be 0.45 closed by 1Q2014 0.6 Private Placement and 0.3 IPO proceeds February 2012 0.15 Scandinavian bondInitial 4 Rigs Khamsin & Sharav Meltem Capital Expenditure Funding Sources 16

Fleet Growth has the Potential to Propel EBITDA GrowthNewbuilds and FutureRoll-offs (16) Contracted at Result in these Levels of Future Projectedthe Following Dayrates: EBITDA, $ MM 615 760 $500 K/d 410 2013 2014 2015 $550 K/d 645 825 415 2013 2014 2015 $600 K/d 675 895 420 2013 2014 2015 17

Newbuild ConsiderationsConsiderations: Informed By: • Long term market viewProject Returns • Newbuild cost • Maximum 2 rig exposure Project Risk • Financing requirements Operational • Rig staffing Constraints • Management bandwidth 18

Committed to Shareholder Value Creation1• Target continued growth – Benefit from strengthening UDW market conditions – Build on leading-edge technology, e.g. dual gradient drilling – Seek value-creating growth opportunities: organic and inorganic • Expand EBITDA / CF2• Corporate and operational excellence – Capitalize on high quality assets • Optimize capital structure – Differentiate through people and processes • Minimize the cost of capital – Deliver best-in-class corporate governance3• Disciplined financial management – Enhance liquidity; Listed on the NYSE – Focus on appropriate use of excess cash – Monitor market conditions to assure appropriate capital structure 19

Footnotes1) Floater age data from ODS-Petrodata as of May 24, 2012. Analysis by Pacific Drilling. Includes rigs under construction.2) Supply data from ODS-Petrodata as of May 24, 2012, for rigs with water depth capability of 7,500 ft or greater. Supply and demand analysis by Pacific Drilling.3) Data from ODS-Petrodata as of May 24, 2012. Analysis by Pacific Drilling. Dayrate excludes mobilization and other compensation. Priced option exercises not included. Does not include contracts for under 1 year in duration.4) Data from ODS-Petrodata as of May 24, 2012. Analysis by Pacific Drilling. “2007-Current” adjusted to remove impact of Ocean Courage and Petrobras 10,000 in 2009, which were subject to construction finance issues and unable to work.5) Enterprise value includes committed capital expenditures. Data from public company disclosures and Pareto Securities as of May 18, 2012.6) Average water depth and average year built for deepwater fleet include assets under construction and on order as of May 24, 2012.7) United States Bureau of Ocean Energy Management, Regulation and Enforcement. Risk Profile of Dual Gradient Drilling by Stress Engineering Services Inc. May 2011.8) LTIF is defined as Lost Time Incidents (LTI) per million manhours. Data is through March 31, 2012.9) Revenue efficiency is defined as actual contractual dayrate revenue (excludes mobilization fees, upgrade reimbursements and other revenue sources) divided by the maximum amount of contractual dayrate revenue that could have been earned during such period.10) As of June 22, 2012; does not include contract options. On March 21, 2012, the Pacific Santa Ana was accepted and commenced its five-year contract with Chevron while mobilizing to the U.S. Gulf of Mexico. On May 4, 2012, the Pacific Santa Ana completed all necessary activities for commencement of revenue recognition and placing the rig into service in the U.S. Gulf of Mexico.11) Includes revenues from contract dayrate, mobilization, and client contract upgrade. Mobilization and client contract upgrade revenue are not dependent on efficiency.12) Deepwater developments by operator from Wall Street Research.13) Revenues earned and incremental costs incurred directly related to contract preparation and mobilization along with reimbursements received for capital expenditures for the Pacific Scirocco are deferred and recognized over the primary term of the drilling contract. As a result, deferred revenue and deferred mobilization costs of the Pacific Scirocco will be recognized over the initial one year primary term of the contract. Consequently, average contract backlog revenue per day is approximately $586,000 through December 31, 2012. On January 1, 2013 through the end of the two year contract period, the average contract backlog revenue per day is $474,750.14) Fleet status reflected as of June 22, 2012.15) Daily contract backlog revenue does not include mobilization, contract preparation and client contract upgrade revenues.16) Pacific Scirocco assumed to have its options exercised rather than gain exposure to these dayrates. Re-rate exposure schedule through 2015 assumed to be: Pacific Khamsin – 2013, Pacific Bora – 2014, Pacific Meltem – 2014 and Pacific Mistral – 2015.17) Includes assumption of allocation of capital expenditures which are not included in the Samsung construction contracts.18) Financial statements as per Pacific Drilling’s Form 6-K, filed on May 31, 2012. 20

Appendix – Future Capex of $1.6 Billion Required to Complete Newbuilds Quarterly Capex Projection ($MM)(17) Prior 1Q2012 2Q2012 3Q2012 4Q2012 1Q2013 2Q2013 3Q2013 4Q2013 1Q2014 2Q2014 TotalPacific Khamsin 83 8 68 65 43 20 328 - - - - 615Pacific Sharav 50 - 38 9 57 71 37 353 - - - 615Pacific Meltem 2 23 - 25 34 5 6 118 11 53 338 615Total 135 31 106 99 134 96 371 471 11 53 338 1,845 21

Appendix – Balance Sheet(18) PACIFIC DRILLING S.A. AND SUBSIDIARIES Condensed Consolidated Balance Sheets (in thousands, except par value and share amounts) March 31, December 31, 2012 2011 (unaudited)Assets: Cash and cash equivalents................................................................................. $ 269,344 $ 107,278 Restricted cash..................................................................................................... 149,195 168,681 Accounts receivable............................................................................................ 241,975 62,578 Materials and supplies........................................................................................ 44,543 42,986 Deferred financing costs..................................................................................... 16,605 15,124 Current portion of deferred mobilization costs................................................ 63,801 54,523 Prepaid expenses and other current assets...................................................... 14,930 10,376 Total current assets........................................................................ 800,393 461,546 Property and equipment, net.............................................................................. 3,509,933 3,436,010 Restricted cash..................................................................................................... 208,287 208,287 Deferred financing costs..................................................................................... 32,922 32,386 Other assets.......................................................................................................... 72,501 46,060 Total assets..................................................................................... $ 4,624,036 $ 4,184,289Liabilities and shareholders equity: Accounts payable................................................................................................ $ 26,044 $ 26,845 Accrued expenses................................................................................................ 35,738 39,095 Current portion of long-term debt..................................................................... 218,750 218,750 Accrued interest payable.................................................................................... 18,754 12,099 Derivative liabilities, current............................................................................... 21,549 20,466 Current portion of deferred revenue................................................................. 86,866 28,829 Total current liabilities................................................................... 407,701 346,084 Long-term debt, net of current maturities......................................................... 1,756,250 1,456,250 Deferred revenue.................................................................................................. 126,918 73,110 Other long-term liabilities.................................................................................... 42,923 34,772 Total long-term liabilities............................................................... 1,926,091 1,564,132Commitments and contingenciesShareholders equity: Common shares, $0.01 par value, 5,000,000,000 shares authorized, 224,100,000 shares issued and 216,900,000 shares outstanding as of March 31, 2012 and December 31, 2011, respectively..................... 2,169 2,169 Additional paid-in capital................................................................................... 2,345,149 2,344,226 Accumulated other comprehensive loss.......................................................... (63,381) (60,284) Retained earnings (accumulated deficit).......................................................... 6,307 (12,038) Total shareholders equity............................................................. 2,290,244 2,274,073 Total liabilities and shareholders equity.................................... $ 4,624,036 $ 4,184,289 22See accompanying notes to unaudited condensed consolidated financial statements.

Appendix – Statement of Operations(18) PACIFIC DRILLING S.A. AND SUBSIDIARIES Condensed Consolidated Statements of Operations (in thousands, except share and per share information) (unaudited) Three Months Ended March 31, 2012 2011 Revenues Contract drilling.................................................................................................... $ 117,394 $ — Costs and expenses Contract drilling.................................................................................................... (64,911) — General and administrative expenses................................................................. (12,440) (10,513) Depreciation expense........................................................................................... (22,642) (140) (99,993) (10,653) Loss of hire insurance recovery......................................................................... 23,671 — Operating income (loss)........................................................................................... 41,072 (10,653) Other income (expense) Equity in earnings of Joint Venture.................................................................. — 18,955 Interest income from Joint Venture.................................................................... — 495 Interest expense.................................................................................................... (19,280) (305) Other income......................................................................................................... 3,010 230 Income before income taxes..................................................................................... 24,802 8,722 Income tax (expense) benefit............................................................................... (6,457) 372 Net income.................................................................................................................. $ 18,345 $ 9,094 Earnings per common share, basic........................................................................ $ 0.08 $ 0.06 Weighted average number of common shares, basic.......................................... 216,900,000 150,000,000 Earnings per common share, diluted..................................................................... $ 0.08 $ 0.06 Weighted average number of common shares, diluted....................................... 216,902,496 150,000,000For the first quarter of 2012:• Deferred mobilization and contract prep revenue included in contract drilling revenue = $19.3 MM• Deferred mobilization costs included in contract drilling expenses = $14.7 MM• Average daily direct rig operating expenses = $190 k/day 23• Shore-based and support costs included in contract drilling costs = $5.2 MM

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GHS100 Energy Conference June 25, 2012

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GHS100 Energy Conference June 25, 2012 Presentation Transcript