Investor Presentation November 2014 STRATEGY EXCELLENCE GROWTH
Certain statements and information contained in this presentation (and oral statements made regarding the subjects of this presentation) constitute “forward- looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements typically include words or phrases such as “anticipate,” “believe,” “could,” “estimate,” “expect,” “forecast,” “foresee,” “intend,” “our ability to,” “plan,” “potential,” “project,” “should,” “tends to,” “target,” “will,” “would,” or other similar words, or negatives of such words, which are generally not historical in nature. Such forward-looking statements specifically include statements involving future distributions to shareholders; contract dayrate amounts; future operational performance and cashflow; backlog; revenue efficiency levels; client contract opportunities; estimated duration of client contracts; future contract commencement dates and locations; construction, timing and delivery of newbuild drillships; capital expenditures; market conditions; cost adjustments; estimated rig availability; new rig commitments; the expected time and number of rigs in a shipyard for repairs, maintenance, enhancement or construction; expected direct rig operating costs; shore based support costs; selling, general and administrative expenses; income tax expense; expected amortization of deferred revenue and deferred mobilization expenses; and expected depreciation and interest expense for our existing credit facilities and senior bonds. 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. In particular, our forward looking statements regarding future distributions to shareholders and share repurchases are subject to the discretion of our Board of Directors, additional laws of Luxemburg, and the funding of any such distribution or repurchase is heavily dependent on our ability to achieve projected cashflows, which could be materially impacted by numerous factors, including those listed below. There can be no assurance that we will make distributions or share repurchases within the period or in the amount forecasted or at all. All comments concerning our expectations for future revenue 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 (many of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations, plans or projections. Important factors that could cause actual results to differ materially from projected cashflows and other projections in our forward-looking statements include, but are not limited to: our ability to secure and maintain drilling contracts, including possible cancellation or suspension of drilling contracts as a result of mechanical difficulties, performance, market changes, regulatory or other approvals, or other reasons; changes in worldwide rig supply and demand, competition and technology; risks inherent to shipyard rig construction, repair, maintenance or enhancement, including delays; levels of offshore drilling activity and general market conditions; unplanned downtime and other risks associated with offshore rig operations, including unscheduled repairs or maintenance; governmental action, strikes, public health threats, civil unrest and political and economic uncertainties; relocations, severe weather or hurricanes; actual contract commencement dates; environmental or other liabilities, risks or losses; governmental regulatory, legislative and permitting requirements affecting drilling operations; our ability to attract and retain skilled personnel on commercially reasonable terms; impact of potential licensing or patent litigation; 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 risk factors that could cause our actual results to differ from our projected results, please see our filings with the Securities and Exchange Commission (SEC), including our Annual Report on Form 20-F and Current Reports on Form 6-K. These documents are available through our website at www.pacificdrilling.com or through the SEC’s Electronic Data and Analysis Retrieval System at www.sec.gov. 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 forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise. Forward Looking Statements
3 Committed to Being the Preferred Ultra-Deepwater Driller • Only 100% high-specification, ultra-deepwater fleet • NYSE: PACD • Market cap: $1.5 billion(1) • Substantial growth and more to come 1Q2011 3Q2014 Number of rigs 4 8 Number of operating rigs 0 6 Number of drilling contracts 2 6 Contract backlog (billion) $1.5 $2.7(2) Number of employees ~500 ~1,600
40 70 100 130 160 190 220 250 Financial Performance Highlights 4 For third-quarter 2014: • Total revenue of $279.6 million • EBITDA(3) of $145.5 million • EBITDA margin(4) of 52.0% • Revenue efficiency(5) of 94.4% • Net income of $48.1 million • Earnings per share of $0.22 ($m) Dayrate Revenue Direct Rig-related Operating Expenses EBITDA & Adjusted EBITDA NOTES: • Dayrate revenue does not include amortization of deferred revenue. • Direct rig-related operating expenses do not include reimbursable costs. • Adjusted EBITDA removes from EBITDA certain costs from debt refinancing in 2Q2013 and loss-of-hire insurance recovery.
Positioned for Long-Term Success 5 STRATEGY EXCELLENCE GROWTH
60 65 70 75 80 85 90 95 100 New Rigs Should Receive Higher Asset Values and Multiples Floater Utilization Since 2008 by Build Cycle (6) 6 U ti liz at ion % O ct Ja n A p r Ju l O ct Ja n A p r Ju l O ct Ja n Ja n Ja n A p r Ju l A p r O ct Ju l 2008 2009 2010 2011 2012 A p r Ju l O ct Ja n 2013 A p r Ju l O ct 2007-Current 1998-2006 1979-1997 1971-1978 Newer Rigs Enjoy Higher Market Utilization Rates Throughout Cycle Greater Cash Flow Potential (m) $994 $974 7.9x $898 $634 5.1x $648 $446 3.6x Adjusted for Market Utilization (m) Implied EBITDA Multiple NOTES: • Analysis assumes 30 year useful life of asset (1971-1978 rigs not included in analysis). • Cash flow calculation uses the following assumed standard industry rate: $500k/day revenue minus $200k/day opex minus $11k/day tax which equals $289k/day cash contribution per day from rig or $105m cash flow from operations per rig per year. • Market utilization defined as days contracted divided by days in period; utilization adjustment assumes utilization at end of Q3 2014; for off-hire periods, no revenues and full operating costs. • NPV of future stream of EBITDAs is calculated using a Weighted Average Cost of Capital of 10%. • Enterprise value is calculated as market cap plus debt minus total cash and cash equivalents. 2015 EBITDA as per ThomsonReuters consensus on 29 Oct 2014. Strategy Ja n 2014 A p r Current PACD EV / 2015 EBITDA = 5.9x Ju l
100% 84% 41% 33% 22% 17% 12% 11% 11% 8% 11% 7% 18% 17% 11% 13% 8% 27% 44% 23% 64% 17% 48% 33% 16% 43% 88% 14% 59% Pacific Drilling Ocean Rig Seadrill Atwood Transocean Noble Rowan Diamond Offshore Ensco High Spec Standard Spec Low Spec Jackup The Only 100% High-Specification, Ultra-Deepwater Fleet NOTES: Graph includes committed newbuilds only. 7 Percentage of Fleet Composition by Rig Capability and Type(7) ific Drilli g Strategy Rig Classification Index (Specification Scale Exclusively Floaters)
8 What is a High-Specification UDW Rig(7)? Strategy Specification Standard High-Specification Hook load (short tons) < 1,000 1,000 + Riser tensioner capacity (kips) < 3,200 3,200 + Mud pump capacity (total HP) < 8,800 8,800 + Mud capacity (bbl) < 15,000 15,000 + Drilling system sophistication Limited automation Fully automated Dual load path/offline handling Single load path / offline handling Dual load path / offline handling Variable deck load / Available deck space Limited Expanded Persons on board < 200 200+ D ril ling Cap abil it y Dri lli n g Effi cienc y Ope ra ti o n s Su p p o rt
Newest Drillships in Demand For All Water Depths Industry Trends 90% of High-Spec Floaters Operate in Less Than 7,500 ft Water Depth 9 1. Challenges of remote drilling sites 2. Drilling deeper and with longer offsets 3. Greater drilling efficiency to reduce total well costs 4. Advances in well construction techniques, e.g. intelligent completions 5. More demanding downhole environments, e.g. high-pressure & high-temperature drilling 6. Increasingly demanding regulatory climate 7. Increased client focus on safety High-Spec Rigs Deliver Value to Clients in All Water Depths through Significantly Enhanced Drilling Efficiency 30% 60% 10% By Operating Water Depth (ft)(8) Less than 4,500 4,500-7,499 7,500 or greater Strategy
Dayrate Bifurcation Between High-Spec and Low-Spec Rigs Continues All-in Dayrate Trend for Floating Rigs By Rig Specification Index(9) NOTES: • Analysis includes rigs with water depth capability greater than 5000 ft and contract dayrate revenue from mutual contracts greater than one year. 10 Rig Specification Index Strategy PACD Contract 300 350 400 450 500 550 600 650 700 750 800 Jan-12 Mar-12 Jun-12 Sep-12 Dec-12 Mar-13 Jun-13 Sep-13 Dec-13 Mar-14 Jun-14 Sep-14 D ay ra te ( $K ) Fixture Date High Spec Standard and Low Spec Poly. (High Spec) Poly. (Standard and Low Spec)
Supply for High-Spec Rigs is Still Expected to Keep Pace with Demand through the End of 2016 11 Supply and Demand Forecast(10) 165 (170) 173 71 8 3 65 11 Supply Demand 109 193 72 15 3 61 16 Supply Demand 2015 2016 NOTES: • Projections include rigs with water depth capability of 7,500 ft. or greater and announced newbuild orders only. • Both supply and demand are weighted by portion of the year the rig or project is available. Current Projections Previous Projections (July 2014) 184 (192) 91 89 101 High Spec Standard Spec Low Spec Unable to predict project requirements Strategy Current uncertainty of timing
0.4 9 0.4 9 0.0 0 0.7 3 2.4 4 1.8 8 1.9 5 1 .7 9 1.3 0 0.8 7 0.8 4 0.0 0.5 1.0 1.5 2.0 2.5 3.0 2008 2009 2010 2011 2012 2013 TTM PACD LTIF IADC LTIF Exceptional Safety Performance NOTES: • LTIF is defined as Lost Time Incidents (LTI) per million man-hours. • TTM (trailing 12 months) is for the period October 2013 – September 2014. • IADC data is for water regions only and is for the period July 2013 – June 2014. 12 • Pacific Bora achieved 3.75 years without an LTI and 1.75 years without a recordable incident • Pacific Scirocco achieved 3.5 years without an LTI and 1.5 years without a recordable incident • Pacific Khamsin achieved 1 year without an LTI and nearing 1 year without a recordable incident • PSV has had zero LTIs since commencing contract • “A” rating on the Chevron Contractor HES Management (CHESM) program in both deepwater and Nigeria Business Units LTIF Excellence
1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 35% 40% 45% 50% 55% 80% 85% 90% 95% 100% A d ju st e d E B IT D A M ar gi n Revenue Efficiency Strong Revenue Efficiency 13 Excellence 1. Shortened shakedown to 1 quarter 2. Focused employee recruiting and training programs 3. Fully implemented preventive maintenance programs 4. Enhanced planning of maintenance to coincide with between well activities 5. Strong operating cost management Keys to Success: 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 Revenue Efficiency(5) 88.9% 85.4% 83.1% 94.6% 90.3% 90.2% 96.9% 95.6% 82.7% 97.1% 94.4% Adjusted EBITDA Margin(4) 36.7% 40.4% 38.0% 48.3% 45.6% 48.3% 50.0% 48.0% 44.7% 52.7% 52.0% Net Opex Per Rig ($k/d) 185.6 174.0 187.8 168.0 178.6 164.0 163.4 176.2 183.8 178.2 175.5 NOTES: Red denotes quarters affected by shakedown of newbuild rigs.
1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 35% 40% 45% 50% 55% 80% 85% 90% 95% 100% A d ju st e d E B IT D A M ar gi n Operating Efficiency Not All Efficiency Metrics are the Same 14 Excellence 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 Operating Efficiency 94.5% 95.5% 86.4% 97.0% 95.3% 95.1% 99.7% 100.0% 91.8% 99.3% 97.4% Adjusted EBITDA Margin(4) 36.7% 40.4% 38.0% 48.3% 45.6% 48.3% 50.0% 48.0% 44.7% 52.7% 52.0% Net Opex Per Rig ($k/d) 185.6 174.0 187.8 168.0 178.6 164.0 163.4 176.2 183.8 178.2 175.5 NOTES: Red denotes quarters affected by shakedown of newbuild rigs. • Operating efficiency defined as revenue-earning days divided by available drilling days • Results in average 6% increase over revenue efficiency Different calculation:
15 Industry-Beating Adjusted EBITDA Margins Excellence Range of Adjusted EBITDA/Revenue for Offshore Drillers 25% 30% 35% 40% 45% 50% 55% 60% 65% Q4 2012 Q1 2013 Q2 2013 Q3 2013 Q4 2013 Q1 2014 Q2 2014 PACD Peer Offshore Driller Average NOTES: • Peer Offshore Driller Average includes PACD and publicly available information for ATW, DO, ESV, NE, ORIG, RDC, RIG, and SDRL • EBITDA is as reported by Bloomberg (ESV adjusted for $992 million impairment in 2Q 2014). • Adjusted EBITDA for PACD removes from EBITDA certain costs from debt refinancing in 2Q2013.
$0 $20 $40 $60 $80 $100 $120 $140 $160 $6 $7 $8 $9 $10 $11 $12 $13 Ad ju st ed EBIT D A ( $ m ) St ock Pr ice ($ ) EBITDA Last Price 16 NOTES: Closing stock price from Nov. 11, 2011 to Nov. 4, 2014. Excellence Stock Performance Disconnected from Financial Performance Over the Past Year 1 # Number of operating rigs 6 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14
Approximately 2 Rig Years Available Through 2015 17 Contract Status as of November 4, 2014 Excellence Chevron Nigeria, $475k/d 3 year contract Total Nigeria, $495k/d 1 year extension Petrobras Brazil, $458k/d 3 year contract Chevron USGoM, $490k/d 5 year contract Chevron Nigeria, $660k/d 2 year contract Delivered: Chevron USGoM, $558k/d 5 year contract Expected Delivery: November 2014 Construction Mobilization Firm Contract 2014 2015 2016 Pacific Bora Pacific Scirocco Total Nigeria, $499k/d 2 year extension Chevron Nigeria, $586k/d 2 year extension Pacific Zonda Expected Delivery: Second Quarter 2015 Pacific Mistral Pacific Santa Ana Pacific Khamsin Pacific Sharav Pacific Meltem May 2014
18 NOTES: • Includes available fleet (excludes cold stacked units). • Pacific Drilling newbuild delivery as per November Fleet Status Report. All other newbuild deliveries as per data from IHS-Petrodata. Availability assumed to be 4 months from delivery. 100% 100% 93% 90% 89% 87% 85% 84% 77% 87% 73% 58% 76% 74% 64% 74% 58% 57% Ocean Rig Rowan Noble Seadrill Ensco Atwood Transocean Diamond Offshore 2014 2015 Pacific Drilling Days Contracted As Percentage of Days Available for 2014 and 2015(11) Excellence Contract Coverage Provides Visibility
50 100 150 200 250 300 350 400 4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q Actual $400k/d $450k/d $500k/d Projected Revenues Continue to Increase Revenue ($m) Assumed rollover dayrates NOTES: • Assumed rig availability month for extension/rollover to new rates: Mistral (2/15), Meltem (4/15), Zonda (10/15), Khamsin (12/15), Bora (8/16), Scirocco (1/17), Santa Ana (4/17), Sharav (8/19). • Assumed 85% revenue efficiency for initial 6 months shakedown period, blended revenue efficiency average of approximately 95% for 8 rig fleet post-shakedown, excluding surveys. 2012 2013 2014 2015 2016 19 Growth Average Dayrate at End of 2016 $506k $475k $443k
Big 3 OFS Avg PACD ORIG ATW RDC VTG 75 100 125 150 175 200 225 2013 2014 2015 PACD Offers Superior Growth Potential: Consensus Forecasts NOTES: • EBITDA from Thomson Reuters consensus mean as of October 29, 2014. Analysis of percentage change from 2013 EBITDA baseline by Pacific Drilling. • Big 3 Oilfield Services Company average includes BHI, HAL, SLB, weighted by total EBITDA. 20 Consensus Projected EBITDA CAGR 2013-2015 = 45% Projected EBITDA Growth Growth
Growth in Profitability and Cashflow From 8 Rig Fleet Allows for Distributions NOTES: • Projected cashflow from operations assumes operating fleet size of 6 rigs at end of 2014, 8 rigs at end of 2015, includes expected cash reimbursements for equipment upgrades, and includes above dayrates, as noted, on contracts for new drillships and extensions on existing drillships, as applicable. • Assumed rig availability month for extension/rollover to new rates: Assumed rig availability month for extension/rollover to new rates: Mistral (2/15), Meltem (4/15), Zonda (10/15), Khamsin (12/15), Bora (8/16), Scirocco (1/17), Santa Ana (4/17), Sharav (8/19). 21 Cashflow from Operations Forecast ($m) 230 405 450 375 100 200 300 400 500 600 700 2013 Actual 2014 2015 2016 $400 k/day $450 k/day $500 k/day Growth 470 490 440 510 Assumed new dayrate scenarios
Secured Funding and Projected Cash Flow in Excess of Debt and Capex Commitments 22 1,050 135 250 860 535 300 132 4Q14 1Q15 2Q15 3Q15 4Q15 Column1 Debt Amortization Capex Maturity Column2 Growth NOTES: • Capex as per Investor Toolkit dated Sep. 30, 2014. • Commitments shown as net of gross interest since interest has been deducted when calculating cash flow from operations. • Cash flow from operations projected using $400k/day for contract rollovers/extensions. See slide 21. Existing Facilities Provide up to $1.3 Billion of Undrawn Capacity Total commitments Sources through end of 2015 Excess liquidity available for discretionary distributions & deleveraging $1,295 $1,967 Existing cash Projected cash flow from operations Conditional debt(12) Currently available debt capacity
Return of Cash to Shareholders Aligns with Our Capital Allocation Strategy 23 Fund Existing Growth Profile Invest in Additional Growth Distribution Deleveraging • Shareholders approved return of capital to shareholders of up to $152 million in the aggregate in 2015 • Board will recommend to shareholders at November EGM a share repurchase program; Board intends to accelerate distributions through a repurchase of up to $30 million of outstanding shares • Target net debt range to 3.0 – 3.5x EBITDA and 40-50% net debt to capital within 5 years • Distribution payout ratio based on cash flow from operations • Continue to grow fleet with portion of cash flow from operations NOTES: • Shareholders approved a proposal at the 2014 AGM that the Company make cash distributions of up to $152 million in the aggregate to shareholders in 2015, commencing with an initial payment in the first quarter of 2015. The timing, amount and form of the distributions will be subject to the discretion of the Board. • The Board will submit a proposal at a Nov. 24, 2014 EGM to approve a share repurchase program. The timing and amount of the repurchases will be subject to the discretion of the Board and to the parameters of the approved share repurchase program. Growth
24 • Drilling contracts • Pacific Mistral extension • Pacific Meltem contract • Pacific Zonda contract • Continued excellence in operations • Initiation of return of cash to shareholders, including share repurchases and cash distributions Our Current Priorities and Potential Catalysts
Investor Contact Pacific Drilling Amy Roddy VP Investor Relations 11700 Katy Freeway Suite 175 Houston, Texas 77079 USA Phone: +1 832-255-0502 Email: Investor@pacificdrilling.com www.pacificdrilling.com 25
Footnotes 26 1. Closing stock price of $6.72 as of Nov. 3, 2014 and 217.4m shares outstanding. 2. As of November 1, 2014. 3. EBITDA and adjusted EBITDA are non-GAAP measures. EBITDA is defined as earnings before interest, taxes, depreciation and amortization. Adjusted EBITDA is defined as earnings before interest, costs from debt refinancing, loss of hire insurance, taxes, depreciation and amortization. Please refer to the reconciliation attached to this presentation of net income to EBITDA along with a definition and statement indicating why management believes the non-GAAP measure provides useful information for investors. 4. EBITDA margin is defined as EBITDA divided by contract drilling revenue. Adjusted EBITDA margin is defined as adjusted EBITDA divided by contract drilling revenue. Management uses this operational metric to track company results and believes that this measure provides additional information that consolidates the impact of our operating efficiency as well as the operating and support costs incurred in achieving the revenue performance. 5. Revenue efficiency is defined as actual contractual dayrate revenue (excluding mobilization fees, upgrade reimbursements and other revenue sources) divided by the maximum amount of contractual dayrate revenue that could have been earned during a certain period. 6. Utilization data from IHS-Petrodata through Sep 30, 2014. “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. 7. Rig data from IHS-Petrodata as of November 3, 2014. Rig specification analysis & classification index by Pacific Drilling. Rig specification analysis includes weighted average of characteristics which are important to industry clients, including DP class, derrick capacity, top drive capacity, size of main rotary table, number and size of mud pumps, liquid mud capacity, oil capacity, brine capacity, total liquids volume, automation capabilities, riser tensioner capacity, size of quarters, variable deck load, number of cranes and BOP capacity. 8. Rig data from IHS-Petrodata as of November 3, 2014. Analysis by Pacific Drilling using most recent well depth data available for each rig. 9. Rig data from IHS-Petrodata as of October 31, 2014. Analysis by Pacific Drilling. Priced option exercises, sublets and contracts for less than 1 year in duration not included. 10. Supply data from IHS-Petrodata as of Sep. 30, 2014. Demand analysis by Pacific Drilling as of July 2014. Both are weighted by the portion of the year during which either the supply is available or the demand exists. Demand projections should be regarded as our general estimate of forecasted market conditions. Our projections are derived from internal analysis and include uncertainty. Our internal analysis incorporates factors including, but not limited to, known tenders existing in the marketplace, potential future tenders as projected by IHS-Petrodata, perceptions of operator intent derived through marketing discussions, news articles regarding political conditions and potential regulatory developments in deepwater-active countries, and presentations by peers, deepwater operators, and analysts. The numbers presented on this slide correspond to the range between our ‘downside case’ and ‘base case’. 11. Data from IHS-Petrodata as of October 31, 2014. Analysis by Pacific Drilling. 12. We will have access to $100.0 million available under our SSCF and $150.0 million available under our new 2014 Revolving Credit Facility, provided that satisfactory drilling contracts are signed for Pacific Meltem and Pacific Zonda in accordance with terms under the SSCF and 2014 Revolving Credit Facility, respectively.
Income Statement 27 Appendix September 30, 2014 June 30, 2014 September 30, 2013 September 30, 2014 September 30, 2013 $ 279,637 $ 260,829 $ 193,240 $ 766,057 $ 545,028 (116,850) (107,964) (82,719) (335,780) (246,641) (16,467) (13,773) (13,080) (42,773) (35,658) (50,187) (46,449) (36,646) (142,790) (109,752) (183,504) (168,186) (132,445) (521,343) (392,051) 96,133 92,643 60,795 244,714 152,977 Other expense — — — — (38,184) (35,626) (28,599) (23,797) (90,256) (68,257) (35,626) (28,599) (23,797) (90,256) (106,441) — — — — (28,428) (870) (1,231) (842) (3,270) (946) 59,637 62,813 36,156 151,188 17,162 (11,536) (12,931) (5,829) (30,975) (17,350) $ 48,101 $ 49,882 $ 30,327 $ 120,213 $ (188) $ 0.22 $ 0.23 $ 0.14 $ 0.55 $ — 217,344 217,293 216,969 217,254 216,944 $ 0.22 $ 0.23 $ 0.14 $ 0.55 $ — 217,547 219,523 217,157 217,455 216,944 Weighted average number of common shares, diluted... Costs on interest rate swap termination............................ Interest expense............................................................. Total interest expense............................................. Costs on extinguishment of debt...................................... Other expense................................................................ Income before income taxes............................................ Income tax expense........................................................ Net income (loss).............................................................. Earnings (loss) per common share, basic......................... Weighted average number of common shares, basic...... Earnings (loss) per common share, diluted...................... Operating income............................................................ PACIFIC DRILLING S.A. AND SUBSIDIARIES Condensed Consolidated Statements of Operations (in thousands, except per share amounts) (unaudited) Three Months Ended Nine Months Ended Revenues Contract drilling.............................................................. Costs and expenses Contract drilling.............................................................. General and administrative expenses................................ Depreciation expense......................................................
Balance Sheet 28 Appendix September 30, June 30, December 31, 2014 2014 2013 Assets: $ 132,359 $ 149,617 $ 204,123 184,291 157,863 206,078 92,096 82,472 65,709 13,872 14,356 14,857 31,688 36,594 48,202 25,060 26,528 13,889 479,366 467,430 552,858 5,105,911 5,048,463 4,512,154 43,638 46,913 53,300 48,605 39,213 45,728 $ 5,677,520 $ 5,602,019 $ 5,164,040 Liabilities and shareholders' equity: $ 41,331 $ 46,887 $ 54,235 50,399 68,672 66,026 349,167 349,167 7,500 37,732 22,029 21,984 9,043 9,473 4,984 90,122 86,499 96,658 577,794 582,727 251,387 2,436,969 2,438,532 2,423,337 128,351 113,359 88,465 14,197 4,196 927 2,579,517 2,556,087 2,512,729 Shareholders' equity: 2,174 2,173 2,170 2,366,560 2,363,758 2,358,858 (16,191) (22,291) (8,557) 167,666 119,565 47,453 2,520,209 2,463,205 2,399,924 $ 5,677,520 $ 5,602,019 $ 5,164,040 Accumulated other comprehensive loss...................................... Retained earnings..................................................................... Total shareholders' equity.......................................... Total liabilities and shareholders' equity...................... Total long-term liabilities............................................ Common shares, $0.01 par value per share, 5,000,000 shares authorized, 232,770 and 224,100 shares issued and 217,391 and 217,035 shares outstanding as of September 30, 2014 and December 31, 2013, respectively............................ Additional paid-in capital........................................................... Other long-term liabilities........................................................... Other assets............................................................................ Total assets............................................................. Accounts payable..................................................................... Accrued expenses.................................................................... Long-term debt, current............................................................. Accrued interest....................................................................... Derivative liabilities, current........................................................ Deferred revenue, current........................................................... Total current liabilities............................................... Long-term debt, net of current maturities..................................... Deferred revenue....................................................................... Deferred financing costs............................................................ PACIFIC DRILLING S.A. AND SUBSIDIARIES Condensed Consolidated Balance Sheets (in thousands, except par value) (unaudited) Cash and cash equivalents........................................................ Accounts receivable.................................................................. Materials and supplies.............................................................. Deferred financing costs, current................................................ Deferred costs, current.............................................................. Prepaid expenses and other current assets................................ Total current assets.................................................. Property and equipment, net......................................................
Cash Flow Statement 29 Appendix September 30, 2014 June 30, 2014 September 30, 2013 September 30, 2014 September 30, 2013 Cash flow from operating activities: $ 48,101 $ 49,882 $ 30,327 $ 120,213 $ (188) 50,187 46,449 36,646 142,790 109,752 (27,278) (28,038) (18,163) (83,324) (52,336) 12,885 13,547 9,840 39,642 29,147 2,544 2,343 1,658 7,465 8,319 227 182 193 582 252 — — — — 27,644 — — — — 38,184 (48) 3,440 (1,126) 3,380 (2,505) 2,876 2,690 2,471 7,532 6,964 Changes in operating assets and liabilities: (26,428) 18,530 9,084 21,787 21,047 (9,624) (8,427) (7,707) (26,387) (9,755) (20,952) (4,818) (4,500) (40,370) (11,892) 30,049 (3,538) 16,149 21,829 1,664 37,953 8,307 12,391 108,734 27,287 100,492 100,549 87,263 323,873 193,584 Cash flow from investing activities: (115,802) (545,058) (554,716) (749,686) (772,249) — — — — 172,184 (115,802) (545,058) (554,716) (749,686) (600,065) Cash flow from financing activities: (73) (503) — 174 — — 360,000 — 360,000 1,497,250 (1,875) (1,875) (1,875) (5,625) (1,458,125) — — — — (41,993) — — — (500) (62,684) (1,948) 357,622 (1,875) 354,049 (65,552) (17,258) (86,887) (469,328) (71,764) (472,033) 149,617 236,504 603,216 204,123 605,921 $ 132,359 $ 149,617 $ 133,888 $ 132,359 $ 133,888 Amortization of deferred costs................................................... Amortization of deferred financing costs..................................... Amortization of debt discount.................................................... Write-off of unamortized deferred financing costs........................ PACIFIC DRILLING S.A. AND SUBSIDIARIES Condensed Consolidated Statements of Cash Flows (in thousands) (unaudited) Three Months Ended Nine Months Ended Decrease in restricted cash.............................................................. Net cash used in investing activities.................................. Costs on interest rate swap termination..................................... Net income (loss)............................................................................ Adjustments to reconcile net income to net cash provided by operating activities:..................................................... Depreciation expense............................................................... Amortization of deferred revenue................................................ Proceeds from shares issued under share-based compensation plan.... Deferred income taxes............................................................. Share-based compensation expense......................................... Accounts receivable............................................................. Materials and supplies......................................................... Prepaid expenses and other assets....................................... Accounts payable and accrued expenses.............................. Deferred revenue.................................................................. Net cash provided by operating activities............................ Capital expenditures........................................................................ Cash and cash equivalents, beginning of period...................................... Cash and cash equivalents, end of period............................................... Proceeds from long-term debt........................................................... Payments on long-term debt............................................................. Payment for costs on interest rate swap termination........................... Payments for financing costs............................................................ Net cash provided by (used in) financing activities............... Decrease in cash and cash equivalents.................................................
EBITDA Reconciliation 30 Appendix EBITDA is defined as earnings before interest, taxes, depreciation and amortization. EBITDA does not represent and should not be considered an alternative to net income, operating income, cash flow from operations or any other measure of financial performance presented in accordance with generally accepted accounting principles in the United States of America (“GAAP”) and our calculation of EBITDA may not be comparable to that reported by other companies. EBITDA is included herein because it is used by the company to measure its operations and is intended to exclude charges or credits of a non-routine nature that would detract from an understanding of our operations. Management believes that EBITDA presents useful information to investors regarding the company's operating performance during the third quarter of 2014. September 30, 2014 June 30, 2014 September 30, 2013 $ 48,101 $ 49,882 $ 30,327 35,626 28,599 23,797 50,187 46,449 36,646 11,536 12,931 5,829 145,450 137,861 96,599 Net income..... ................................................................. PACIFIC DRILLING S.A. AND SUBSIDIARIES Supplementary Data - Reconciliation of Net Income to Non-GAAP EBITDA (in thousands) (unaudited) Three Months Ended Add (subtract): Interest expense............................................................. Depreciation expense...................................................... Income tax expense........................................................ EBITDA.............................................................................
$28 $112 $132 $132 $132 $83 $21 $300 $500 $713 $604 $750 $300 $292 2014 2015 2016 2017 2018 2019 2020 Mandatory Amortization Scheduled Maturities RCF Staggered Debt Maturities Debt Commitments Raised Outstanding Amortization Maturity Margin/Rate 8.25% Sr. Unsecured Notes $300m $300m Balloon Feb 2015 8.25% fixed 7.25% Sr. Secured Notes $500m $500m Balloon Dec 2017 7.25% fixed Sr. Secured Credit Facility $1,000m $500m 12 years May 2019 LIBOR + 3.375% 5.375% Sr. Secured Notes $750m $750m Balloon Jun 2020 5.375% fixed Term Loan B $750m $741m 1% per year Jun 2018 LIBOR + 3.50% 2013 Revolving Credit Facility $500m Footnote Balloon Jun 2018 LIBOR + (2.50% to 3.25%) 2014 Revolving Credit Facility $500m $0m 12 years Jun 2020 LIBOR + (1.75% to 2.50%) Total $4,300m $2,791m NOTES: • 2013 Revolving Credit Facility: $300m maximum cash sublimit (currently undrawn) and $300m maximum sublimit for letters of credit, with a total limit of $500m • 2014 Revolving Credit Facility: Matures 5 years after the delivery date of the Pacific Zonda • Amounts include projected $500M drawdowns on Sr. Secured Credit Facility & 2014 RCF which are not currently outstanding 31 Appendix
