Pareto Securities Oil & Offshore Conference Chris Beckett, CEO September 12, 2012
Disclaimer Certain statements and information in this presentation may constitute forward looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward looking statements include words or phrases such as believe, expect, anticipate, plan, intend, foresee, should, would, could or other similar words, which are generally not historical in nature. These forward looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Important factors that could cause actual results to differ materially from those in the forwardlooking statements include, but are not limited to governmental regulatory, legislative and permitting requirements affecting drilling operations; changes in worldwide rig supply and demand, competition and technology; future levels of offshore drilling activity; downtime and other risks associated with offshore rig operations, relocations, severe weather or hurricanes; possible cancellation or suspension of drilling contracts as a result of mechanical difficulties, performance or other reasons; risks inherent to shipyard rig construction, repair, maintenance or enhancement; actual contract commencement dates; environmental or other liabilities, risks or losses; our ability to attract and retain skilled personnel on commercially reasonable terms; governmental action, civil unrest and political and economic uncertainties; terrorism, piracy and military action; and the outcome of litigation, legal proceedings, investigations or other claims or contract disputes. For additional information regarding known material factors that could cause our actual results to differ from our projected results, please see our filings with the SEC, including our Annual Report on Form 20 F and Current Reports on Form 6 K. 1 Existing and prospective investors are cautioned not to place undue reliance on forward looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forwardlooking statements after the date they are made, whether as a result of new information, future events or otherwise. 2
Who is Pacific Drilling? Focus on the Growing Ultra Deepwater Market Financial Strength Commitment to Shareholder Value Pure Play Ultra Deepwater Drillship Asset Base Dedication to Operational Excellence 3
A Global Growth Market Areas WithActive Ultra deepwater Rig Programs In 2012 HQ Operations Support Core areas Emerging areas Pacific Drilling present in all core ultra deepwater areas 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 Increasing activity in Ghana, Liberia, Namibia, Cote d Ivoire Mexico Similar geology to US GOM Under explored Regions Mediterranean, Malaysia, Brunei, Indonesia, India, S. China Sea, Black Sea, Atlantic Canada / Greenland, Suriname and Guyana 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 Greater drilling efficiency to reduce total well costs 3 48% 40% 4 Advances in well construction 5 More demanding downhole environments, e.g. high pressure & temperature drilling Increasingly demanding regulatory climate 6 10% 2% Rig Age in Years (1) Over 20 10 to 20 5 to 10 Under 5 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 165 169 145 150 20 127 22 16 180 111 128 149 Supply Demand Supply Demand Supply Demand 2012 2013 2014 Newbuild Rigs Existing UDW Fleet 6
Recent Pricing Data Indicates Cyclical ca Upswing Contract Dayrates for 5 th Gen and Later Ultra Deepwater Floaters (3) Day rate, $K/d 700 650 600 Saudi Arabia Ghana Angola USGOM USGOM Angola Angola 550 USGOM USGOM 4 Pacific Sharav (USGOM) 500 Angola 450 USGOM Mexico 400 5/1/11 7/1/11 9/1/11 11/1/11 1/1/12 3/1/12 5/1/12 7/1/12 9/1/12 Contract Length 1 3 Years >3 Years 2 nd Degree Polynomial Regression 7
Newer Rigs Enjoy Higher Utilization Rates Throughout Cycle (5) Current Floater Fleet by Delivery Year Floater Utilization since 2008 by Build Cycle 40 35 100 2007 Current 1998 2006 95 30 25 20 90 85 1979 1997 15 80 10 5 75 1971 1978 0 1971 1975 1980 1985 1990 1995 2000 2005 2010 70 Jan Apr Jul Oct Jan Apr Jul Oct Jan Apr Jul Oct Jan Apr Jul Oct Jan Apr Jul 2008 2009 2010 2011 2012 8
Pacific Drilling: Most Modern, Pure Play UDW Fleet More Modern 2020 Average Floater Fleet Depth and Age (7) 2015 e Year Built Averag 2010 2005 2000 1995 1990 Songa Transocean Ensco Atwood Noble North Atlantic Drilling Seadrill Ocean Rig 1985 1980 Fred Olsen Energy Diamond Offshore Area of bubble bbl represents total enterprise value (6) 1975 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 11,000 12,000 Average Water Depth (Ft.) Deeper Wt Water 9
Fleet Capabilities Designed to Satisfy Customer Demands Consistent, Proven Design & Drilling Package Fleet wide Water Depth Capability10 12,000 ft. Dual Derricks with 1000 1250 ST Hook Loads 2x Single plus Offline & 4x 5x Dual Load Path Rigs 200 POB Accommodation, accommodation, 22,000 ST Displacement Up to 40,000 ft Drilling Depth with 6 Ram BOPs Delivers Fleet wide Operating Synergies Provides for Deepest Operating Requirements in the Market Exceeds Most Demanding Well construction Requirements Optimizes Drilling Efficiencies, Reduces Critical Path Activities Accommodates Needs of Remote and Complex Projects Meets Needs for Redundant Safety Systems and Latest Regulations 10
Dual Gradient Drilling Game Changing Technology A Proven Well Construction Advance Removes the effect of mud weight in the riser column and provides better pressure control Especially important in deeper water and wellbores (e.g. Gulf of Mexico or pre salt Brazil) Well is fully controlled in the event of riser disconnect; Safer and more efficient Should allow operators to access wells which were previously problematic or inaccessible Value to Operators Offshore Magazine (May 1 st, 2010) "It's easier, safer, better for the environment, less expensive, the risks decrease, and the outcomes are more predictable. I think it will be the way we drill deepwater wells in the future. Chevron North America BOEMRE Report t(may 2011) (8) 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 Source: May 2011 BOEMRE Report Risk Profile of Dual Gradient Drilling Sole drillingcontractor with knowledgeand equipment to provide mud lift based Dual Gradient Drilling in ultra deepwater Anticipate a long term competitive advantage Cost to upgrade existing rigs uneconomic 11
Delivering on Promises Becoming The Preferred UDW Drilling Contractor 1 drilling contract signed NYSE listing Closed $200 MM TI letter of credit facilities Operations & Growth Fully fledged UDW contractor Bora and Scirocco began drilling operations 3 rigs delivered 2 drilling contracts signed Ordered one additional drillship Closed $300 MM bond financing Four Rigs in operation by end Q2 Development Building the platform Initiated construction of 4 drillships Implemented management systems First rig delivered $1.8 Bn financing secured 2 drilling contracts signed Ordered 2 additional drillships Closed $600 MM private placement Built operations support team, over 950 staff to date Startup Initial investment Formed by the Quantum Pacific Group (QP) Established management team 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 id (LTIs) (nearly 750,000 000 manhours) Exceptional post delivery safety performance 033LTIF 0.33 (9) (total 3.03 303million manhours) No LTIs in over 4.5 rigs years, no LTI on any operating rig First three rigs have achieved over 1 year without an LTI 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 Achieved ~90% average revenue efficiency (10) during second quarter 2012, excluding BOP repairs 13
$3.1 Billion Backlog With Blue Chip Operators Contract Backlog Total, (11) (12) $ MM Blue Chip Partners (13) Percent of total deepwater developments by operator (2008 12E) Term Firm years Optional years 410 258 462 900 1,076 Bora Scirocco Mistral Santa Ana Sharav 3 2 3 5 5 2 3 0 0 0 Average Remaining i Contract Backlog Revenue Per Day, $ K Chevron (Bora, Santa Ana, Sharav) Others 11% Total (Scirocco) 40% 10% 10% BP 8% 6% 7% 8% Statoilt Shell Petrobras (Mistral) ExxonMobil Pacific Drilling Customer Other Strong backlog, with additional potential from options 581 590 554 35 106 511 525 79 53 44 Contracts t with well capitalized li international ti oil companies 555 475 475 458 481 Demonstrated ability to secure premium rates (14) Bora Scirocco Mistral Santa Ana Sharav Contract day rate Deferred revenue Proven market acceptance 14
Balanced Mix of Dayrate Exposure and Contracted Backlog (15) 2012 2013 2014 Pacific Bora Chevron Nigeria, $475k/d (16) 3 year contract Options for up to 2 years of additional term Pacific Scirocco Pacific Mistral Pacific Santa Ana Total lnigeria, i $475k/d (16) 2 year contract Petrobras Brazil, $458k/d (16) 3 year contract Chevron USGOM, $481k/d (16) 5 year contract Options for up to 3 years of additional term Pacific Khamsin Delivery: Second Quarter 2013 Pacific Chevron USGOM, $555k/d Delivery: Fourth Quarter 2013 (16) Sharav 5 year contract Pacific Meltem Delivery: Second Quarter 2014 15
Strong Initial Funding for Rigs Capital Expenditure vs. Funding Sources, $B 17 1.7 Project Facilities Agreement 3.2 1.5 Equity contribution Remaining debt to be from sponsor closed in 4Q2012 (17) 0.9 1.2 0.3 Private Placement and IPO proceeds 0.6 0.45 0.15 Remaining debt to be closed by 1Q2014 (17) February 2012 Scandinavian bond Initial 4 Rigs Khamsin & Sharav Meltem Capital Expenditure Funding Sources 16
Solid Capitalization Balance Sheet as of June 30, 2012, (19) $ B Other Restricted Cash Cash 4.52 4.52 0.40 0.36 0.25 0.27 1.87 Other Long Term Debt Property & 3.60 Equipment, net Shareholders h Equity 2.29 Assets Liabilities Net book debt to capital ratio = 37% Fully funded net debt to enterprise value (18) ratio = 58% 17
Fleet Growth has the Potential to PropelEBITDA Growth Newbuilds and Future Roll offs (20) Contracted at the Following Dayrates: Result in these Levels of Future Projected EBITDA, $ MM $500 K/d 395 610 760 2013 2014 2015 $550 K/d 400 640 830 2013 2014 2015 $600 K/d 405 665 895 2013 2014 2015 18
Newbuild Considerations Considerations: Informed By: Project Returns Long term market view Newbuild cost Project Risk Maximum 2 rig exposure Financing requirements Operational Constraints Rig staffing Management bandwidth 19
Committed to Shareholder Value Creation 1 Target continued growth Benefit from strengthening UDW market conditions Build on leading edge edge technology, eg e.g. dual algradient drilling Seek value creating growth opportunities: organic and inorganic 2 Corporate and operational excellence Capitalize on high quality assets Differentiate through people and processes Deliver best in class corporate governance Expand EBITDA / CF Optimize capital structure Minimize the cost of capital 3 Disciplined financial management Enhance liquidity; Listed on the NYSE Focus on appropriate use of excess cash Monitor market conditions to assure appropriate capital structure 20
Pareto Securities Oil & Offshore Conference Chris Beckett, CEO September 12, 2012
Footnotes 1) Floater age data from ODS Petrodata as of August 15, 2012. Analysis by Pacific Drilling. Includes rigs under construction. 2) Supply data from ODS Petrodata as of August 16, 2012, for rigs with water depth capability of 7,500 ft or greater. Demand analysis by Pacific Drilling. 3) Data from ODS Petrodata as of August 15, 2012. Analysis by Pacific Drilling. Dayrate excludes mobilization and other compensation. Priced option exercises not included. Does not include contracts for under1 year in duration. 4) 3 Rig deal (19 years, $4 Bn.) between Seadrill and BP; have assumed the average term and rate across the three rigs with a $20 MM mobilization for each of the two newbuild rigs. 5) Data from ODS Petrodata as of August 16, 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. 6) Enterprise value includes committed capital expenditures. Data from public company disclosures and Pareto Securities as of August 13, 2012. 7) Average water depth and average year built for deepwater fleet include assets under construction and on order as of May 24, 2012. 8) United States Bureau of Ocean Energy Management, Regulation and Enforcement. Risk Profile of Dual Gradient Drilling by Stress Engineering Services Inc. May 2011. 9) LTIF is defined as Lost Time Incidents (LTI) per million manhours. Data is through March 31, 2012. 10) 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. 11) As of August 15, 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. 12) Includes revenues from contract dayrate, mobilization, and client contract upgrade. Mobilization and client contract upgrade revenue are not dependent on efficiency. 13) Deepwater developments by operator from Wall Street Research. 14) 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 $581,000 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. 15) Fleet status reflected as of August 15, 2012. 16) Daily contract backlog revenue does not include mobilization, contract preparation and client contract upgrade revenues. 17) Facilities or debt could exceed amounts shown as they may also fund working capital requirements. 18) Market capitalization calculated using closing share price of $9.46 on September 4, 2012. Fully funded book debt assumed to include an additional $1.5B in financing. 19) Financial statements as per Pacific Drilling s Form 6 K, filed on August 22, 2012. 20) 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. 21) Includes assumption of allocation of capital expenditures which are not included in the Samsung construction contracts. 22
Appendix Future Capex Needs Projected to be $1.6 Billion Quarterly Capex Projection ($MM) (21) Prior 1Q2012 2Q2012 3Q2012 4Q2012 1Q2013 2Q2013 3Q2013 4Q2013 1Q2014 2Q2014 Total Pacific Khamsin 82.7 7.6 63.7 62.8 37.9 16.6 337.1 608.4 Pacific Sharav 50.1 34.7 19.6 57.3 74.0 40.6 53.5 333.0 662.8 Pacific Meltem 2.0 23.4 25.4 33.9 6.4 6.6 118.8 12.3 53.7 345.3 627.8 Total 134.8 31.0 98.4 107.8 129.1 97.0 384.3 172.3 345.3 53.7 345.3 1,899.0 23
PACIFIC DRILLING S.A. AND SUBSIDIARIES Condensed Consolidated Balance Sheets (in thousands, except par value and share amounts) Appendix Balance Sheet (19) June 30, December 31, 2012 2011 Assets: (unaudited) Cash and cash equivalents... $ 267,087 $ 107,278 Restricted cash... 42,120 168,681 Accounts receivable... 153,471 62,578 Materials and supplies... 49,343 42,986 Deferred financing costs... 16,348 15,124 Current portion of deferred mobilization costs... 54,992 54,523 Prepaid expenses and other current assets... 20,678 10,376 Total current assets... 604,039 461,546 Property and equipment, net... 3,602,945 3,436,010 Restricted cash... 208,287 208,287 Deferred financing costs... 29,367 32,386 Other assets... 70,782 46,060 Total assets... $ 4,515,420 $ 4,184,289 Liabilities and shareholders' equity: Accounts payable... $ 22,884 $ 26,845 Accrued expenses... 43,953 39,095 Current portion of long-term debt... 218,750 218,750 Accrued interest payable... 23,929 12,099 Derivative liabilities, current... 20,984 20,466 Current portion of deferred revenue... 82,078 28,829 Total current liabilities... 412,578 346,084 Long-term debt, net of current maturities... 1,646,875 1,456,250 Deferred revenue... 121,490 73,110 Other long-term liabilities... 46,760 34,772 Total long-term liabilities... i 1,815,125 125 1,564,132 132 Commitments and contingencies Shareholders' 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 June 30, 2012 and December 31, 2011, respectively... 2,169 2,169 Additional paid-in capital... 2,346,652 2,344,226 Accumulated other comprehensive loss... Retained earnings (accumulated deficit)... Total shareholders' equity... Total liabilities and shareholders' equity... (68,566) (60,284) 7,462 (12,038) 2,287,717 2,274,073 $ 4,515,420 $ 4,184,289 24
Appendix Statement of Operations (19) PACIFIC DRILLING S.A. AND SUBSIDIARIES Condensed Consolidated Statements of Operations (in thousands, except share and per share information) (unaudited) Revenues Contract drilling... Costs and expenses Contract drilling... General and administrative expenses... Depreciation expense... Loss of hire insurance recovery... Three Months Ended June 30, Six Months Ended June 30, 2012 2011 2012 2011 (a) $ 156,780 $ $ 274,174 $ (83,463) (148,374) (10,804) (13,299) (23,244) (23,812) (32,464) (176) (55,106) (316) (126,731) (13,475) (226,724) (24,128) 23,671 Operating income (loss)... 30,049049 (13,475) 71,121121 (24,128) Other income (expense) Equity in earnings of Joint Venture... 18,955 Interest income from Joint Venture... 495 Interest expense... (25,666) (44,946) (305) Other income... 814 932 3,824 1,162 Income (loss) before income taxes... 5,197 (12,543) 29,999 (3,821) Income tax (expense) benefit... (4,042) 36 (10,499) 408 Net income (loss)... $ 1,155 $ (12,507) $ 19,500 $ (3,413) Earnings (loss) per common share, basic... $ 0.01 $ (0.06) $ 0.09 $ (0.02) Weighted average number of common shares, basic... Earnings (loss) per common share, diluted... Weighted average number of common shares, diluted... 216,900,000 207,362,638 216,900,000 178,839,779 $ 0.01 $ (0.06) $ 0.09 $ (0.02) 216,901,766 207,362,638 216,902,148 178,839,779 For the second quarter of 2012: Deferred mobilization and contract prep revenue included in contract drilling revenue = $23.9 MM Deferred mobilization costs included in contract drilling expenses = $18.6 MM Average daily direct rig operating expenses = $178 k/day Shore based and support costs included in contract drilling costs = $5.9 MM 25