Credit Suisse 20th Annual Energy Summit Vail, CO February 23‐25, 2015
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. Where any forward‐looking statement includes a statement about the assumptions of bases underlying the forward‐looking statement, we caution that, while we believe these assumptions or bases to be reasonable and made in good faith, assumed facts or bases almost always vary from actual results, and the differences between assumed facts or bases and actual results can be material, depending on the circumstances. Where, in any forward‐looking statement, our management expresses an expectation or belief as to future results, such expectation or belief is expressed in good faith and is believed to have a reasonable basis. We cannot assure you, however, that the statement of expectation or belief will result or be achieved or accomplished. These statements relate to analyses and other information that are based on forecasts of future results and estimates of amounts not yet determinable. These statements also relate to our future prospects, developments and business strategies. 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 high‐specification floating‐rig drilling contractor • Only 100% high‐specification floater fleet • NYSE: PACD • Market cap: $840 million(1) • Substantial growth and more to come 1Q2011 1Q2015 Number of rigs 4 8 Number of operating rigs 0 5 Contract backlog (billion) $1.5 $2.3(2) Number of employees ~500 ~1,600
Financial performance highlights 4 For full‐year 2014: • Total revenue of $1.09 billion • EBITDA(3) of $563.3 million • EBITDA margin(4) of 51.9% • Revenue efficiency(5) of 93.1% • Net income of $188.3 million • Earnings per share of $0.87 ($m) 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 in 1Q2012. 0 40 80 120 160 200 240 280 320 0 40 80 120 160 200 240 280 320 4Q143Q142Q141Q144Q133Q132Q131Q134Q123Q122Q121Q12 Dayrate Revenue Adjusted EBITDA(3) Direct Rig‐related operating expenses
Strategically positioned for long‐term success MARKET DYNAMICS • Increasingly challenging offshore drilling activities in all water depths • High‐specification drillships meet client demands OPERATIONAL EXCELLENCE • Strong operational performance • Relationships with high‐quality clients • Industry‐leading EBITDA margins FINANCIAL STRENGTH • Contracted backlog provides baseline liquidity • Financing in place for all commitments beyond 2016
100% 84% 41% 38% 25% 17% 12% 12% 11% 8% 11% 8% 20% 17% 12% 13% 8% 16% 37% 23% 61% 16% 48% 38% 18% 43% 88% 15% 60% Pacific Drilling Ocean Rig Seadrill Atwood Transocean Noble Rowan Diamond Offshore Ensco High Spec Standard Spec Low Spec Jackup The only 100% high‐specification floater fleet NOTES: Graph includes committed newbuilds only. 6 Percentage of fleet composition by rig capability and type(6) ic Drilling MARKET DYNAMICS Rig Classification Index (Specification Scale Exclusively Floaters)
7 What is a high‐specification floating rig(6)? MARKET DYNAMICS 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+ Drillin g c a p a b i l i t y Drillin g e fficienc y O p e r a t i o n s s u p p o r t
Newest drillships in demand for all water depths Industry trends 91% of high‐spec floaters operate in less than 7,500 feet water depth 8 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 35% 56% 9% By operating water depth (ft)(7) Less than 4,500 4,500‐7,499 7,500 or greater MARKET DYNAMICS
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 Dec‐14 D a y r a t e ( $ K ) Fixture Date Standard and Low Spec High Spec Poly. (Standard and Low Spec) Poly. (High Spec) All‐in dayrate trend for floating rigs by rig classification index(8) NOTES: Analysis includes rigs with water depth capability greater than 5000 ft and contract dayrate revenue from mutual contracts greater than one year.9 Rig Classification Index PACD Contract Dayrate bifurcation between high‐spec and standard‐spec rigs continues MARKET DYNAMICS
Rig capabilities drive fleet utilization 10 40 50 60 70 80 90 100 <1978 1979 ‐ 1997 1998 ‐ 2006 >2007 U t i l i z a t i o n % MARKET DYNAMICS Year delivered Floater utilization since 1985 by build cycle(9)
Pacific Drilling high‐spec fleet leading fleet renewal Only 10 high‐spec floaters available to work in 2015(10) 11 Rig Classification Index MARKET DYNAMICS 5.6 6.0 5.8 5.5 Pacific Mistral 5.7 Pacific Meltem 6.5 6.3 6.3 5.6 6.0 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 200 225 250 275 300 325 2014 2015 2016 2017 Projected year‐end global floater fleet size(11) NOTES: Chart assumes newbuild rig availability for work 4 months post‐delivery.
OPERATIONAL EXCELLENCE 0 . 5 8 0 . 5 1 0 . 0 0 1 . 0 3 2 . 4 4 1 . 8 8 1 . 9 5 1 . 7 9 1 . 3 1 0 . 9 2 0 . 8 9 0.0 0.5 1.0 1.5 2.0 2.5 3.0 2008 2009 2010 2011 2012 2013 2014 PACD LTIF IADC LTIF Exceptional safety performance NOTES: • LTIF is defined as Lost Time Incidents (LTI) per million man‐hours. • IADC data includes all land and water regions up to and including 2012. • IADC data only includes water regions where PACD was working for 2013/2014 (US, Africa, S. America). • IADC data for 2014 is up to Q3 YTD only. Full 2014 data not yet available. 12 Achievements in 2014: • Pacific Bora achieved 4 years without an LTI and 2 years without a recordable incident • Pacific Scirocco achieved 3 years without an LTI and 1 year without a recordable incident • Pacific Khamsin achieved 1 year without an LTI and 1 year without a recordable incident • “A” rating on the Chevron Contractor HES Management (CHESM) program in both deepwater and Nigeria Business Units • First drilling contractor to certify safety & environmental management systems with Center for Offshore Safety LTIF
1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 4Q14 35% 40% 45% 50% 55% 60% 80% 85% 90% 95% 100% A d j u s t e d E B I T D A m a r g i n Revenue efficiency Strong revenue efficiency drives financial results 13 OPERATIONAL 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 4Q14 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% 96.7% 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% 56.0% Net opex per rig ($k/d) 185.6 174.0 187.8 168.0 178.6 164.0 163.4 176.2 183.8 178.2 175.5 174.2 NOTES: Red denotes quarters affected by shakedown of newbuild rigs.
14 Industry‐leading adjusted EBITDA margins OPERATIONAL EXCELLENCE Range of adjusted EBITDA/revenue for offshore drillers 25% 30% 35% 40% 45% 50% 55% 60% 65% 4Q 2012 1Q 2013 2Q 2013 3Q 2013 4Q 2013 1Q 2014 2Q 2014 3Q 2014 4Q 2014 PACD Peer Offshore Driller AverageNOTES: • Peer Offshore Driller Average includes PACD and publicly available information for ATW, DO, ESV, NE, ORIG, RDC, RIG, and SDRL as of Feb. 23, 2015. • EBITDA is as reported by Bloomberg (ESV adjusted for $992 million impairment in 2Q 2014, NE for $745 million in 4Q 2014, ATW for $61 million in 4Q 2014). • Adjusted EBITDA for PACD removes from EBITDA certain costs from debt refinancing in 2Q2013.
$0 $20 $40 $60 $80 $100 $120 $140 $160 $180 $200 $3 $4 $5 $6 $7 $8 $9 $10 $11 $12 $13 A d j u s t e d E B I T D A ( $ m ) S t o c k P r i c e ( $ ) Adjusted EBITDA Last Price 15 NOTES: Closing stock price from Nov. 11, 2011 to Feb. 13, 2015. OPERATIONAL 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 4Q14
16 Fleet currently valued below replacement cost OPERATIONAL EXCELLENCE 2,982 411 840 4,233 Enterprise value ($m) Market cap Remaining capex Net debt 4,233 Implied rig values ($m) Implied average value of rigs: $529m Below replacement cost NOTES: Remaining Capex from Investor Toolkit dated Dec. 31, 2014. Net Debt as of Dec. 31, 2014. 8 rigs Book value of equity: $2.6b
17 NOTES: Pacific Drilling newbuild delivery as per February Fleet Status Report. All other newbuild deliveries as per data from IHS‐ Petrodata. Availability assumed to be 4 months from delivery. Full fleet days contracted as percentage of days available for 2015 and 2016(10) FINANCIAL STRENGTHContract coverage provides stability 94% 86% 84% 78% 75% 74% 66% 65% 64% 55% 69% 43% 56% 46% 47% 25% 33% 40% 39% 30% Ocean Rig Atwood Seadrill Noble Vantage Drilling Transocean Ensco Rowan Diamond Offshore 2015 2016 Pacific Drilling
Percent Contracted High‐Spec Floater % Available 97% 85% 100% 69% 83% 53% 68% 100% 59% 39% 44% 32% Ocean Rig Atwood Seadrill Noble Vantage Drilling Transocean Ensco Rowan Diamond Offshore 2015 2016 Pacific Drilling 94% 86% 84% 78% 75% 74% 66% 65% 64% 55% 69% 43% 56% 46% 47% 25% 33% 40% 39% 30% 2015 2016 18 NOTES: Pacific Drilling newbuild delivery as per February Fleet Status Report. All other newbuild deliveries as per data from IHS‐ Petrodata. Availability assumed to be 4 months from delivery. Full fleet days contracted as percentage of days available for 2015 and 2016(10) FINANCIAL STRENGTH Pacific drilling only company with exclusively high‐spec floater availability
$2.3 billion contract backlog 19 Contract status as of Feb. 24, 2015 FINANCIAL STRENGTH Total NGA, $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 Chevron USGoM, $555k/d 5 year contract Delivered: November 2014 Expected Delivery: Third Quarter 2015 Construction Mobilization Firm Contract Pacific Zonda Pacific Mistral Pacific Santa Ana Pacific Khamsin Pacific Sharav Pacific Meltem 2015 2016 Pacific Bora Pacific Scirocco Total Nigeria, $499k/d 2 year extension Chevron Nigeria, $586k/d 2 year extension 2014
Cash requirements through end of 2016 covered 20 650 222 250 479 168 289 470 998 450 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 Total Commitments Sources through end of 2016 Debt Amortization Capex Maturity FINANCIAL STRENGTH NOTES: • Capex as per Investor Toolkit dated Dec. 31, 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. Projected cashflow from operations assumes operating fleet size of 7 rigs at end of 2015 and 8 rigs at end of 2016. Costs as per guidance in news release dated Feb. 23, 2015. Includes assumptions for idle time prior to or between contracts for rigs which are currently uncontracted. Existing facilities provide up to $900 million of undrawn capacity Excess liquidity available for discretionary distributions & deleveraging $990 $1,988 Existing cash Projected cash flow from operations Conditional debt(12) Currently available debt capacity 2015 2016
21 Projected positive cash flow through 2016 with no additional contracts FINANCIAL STRENGTH 1086 1070 690 2014 2015 2016 518 560 570 2014 2015 2016 563 510 120 2014 2015 2016 EBITDA ($m) 396 370 0 2014 2015 2016 CFFO ($m) Costs ($m)Revenue ($m) Actuals Current Rig Contracts Only NOTES: Revenue efficiency and cost as per guidance in news release dated Feb. 23, 2015. Assumes year over year cost inflation. Interest expense as per Investor Toolkit dated Dec. 31, 2014.
Capital allocation strategy provides flexibility 22 Fund Existing Growth Profile Invest in Additional Growth Distribution Deleveraging • Target net debt range to 3.0 – 3.5x EBITDA and 40‐50% net debt to capital within 5 years • In December 2014, commenced repurchase of up to 8 million outstanding shares • Further shareholder‐approved return of capital deferred until market visibility improves • Long‐term distribution payout ratio based on cash flow from operations • Long‐term, 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. The timing, amount and form of the distributions will be subject to the discretion of the Board. • At the Nov. 24, 2014 EGM, shareholders approved a share repurchase program of up to 8 million shares. 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. FINANCIAL STRENGTH
23 Questions
Investor contact Pacific Drilling Amy Roddy VP Investor Relations & Communications 11700 Katy Freeway Suite 175 Houston, Texas 77079 USA Phone: +1 832‐255‐0502 Email: Investor@pacificdrilling.com www.pacificdrilling.com 24
Footnotes 25 1. Closing stock price of $3.92 as of Feb. 18, 2015 and 215m shares outstanding. 2. As of Feb. 24, 2015. 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. Rig data from IHS‐Petrodata as of Feb. 5, 2015. 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. 7. Rig data from IHS‐Petrodata as of Feb. 5, 2015. Analysis by Pacific Drilling using most recent well depth data available for each rig. 8. Data from IHS‐Petrodata as of Feb. 17, 2015. Analysis by Pacific Drilling. Includes 3 rig deal and renegotiation between ORIG and Eni, bringing ORIG Poseidon dayrate from $690 to $450‐550 k/d with an additional year on the contract and combined 8 months of contract for ORIG Skryros and Olympia at $370 k/d. 9. Data from IHS‐Petrodata through Jan. 31, 2015. 10. Data from IHS‐Petrodata as of Feb. 17, 2015. Pacific Drilling rig status as per February Fleet Status Report. Rig specification analysis & classification index by Pacific Drilling. Chart includes all floating rigs of classification index >5.5. Newbuild availability assumed to be 4 months from delivery. 11. Projection analysis by Pacific Drilling. Includes all floating rigs in the global fleet and assumptions of attrition based on expected cold stacking or scrapping due to upcoming surveys or as indicated by the rig owner. 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 26 Appendix PACIFIC DRILLING S.A. AND SUBSIDIARIES Condensed Consolidated Statements of Income (in thousands, except per share amounts) (unaudited) Three Months Ended Years Ended December 31, December 31, 2014 September 30, 2014 December 31, 2013 2014 2013 2012 Revenues Contract drilling $ 319,737 $ 279,637 $ 200,546 $ 1,085,794 $ 745,574 $ 638,050 Costs and expenses Contract drilling (123,836) (116,850) (90,636) (459,617) (337,277) (331,495) General and administrative expenses (14,889) (16,467) (12,956) (57,662) (48,614) (45,386) Depreciation expense (56,547) (50,187) (39,713) (199,337) (149,465) (127,698) (195,272) (183,504) (143,305) (716,616) (535,356) (504,579) Loss of hire insurance recovery — — — — — 23,671 Operating income 124,465 96,133 57,241 369,178 210,218 157,142 Other income (expense) Costs on interest rate swap termination — — — — (38,184) — Interest expense (39,874) (35,626) (25,770) (130,130) (94,027) (104,685) Total interest expense (39,874) (35,626) (25,770) (130,130) (132,211) (104,685) Costs on extinguishment of debt — — — — (28,428) — Other income (expense) (1,902) (870) (608) (5,171) (1,554) 3,245 Income before income taxes 82,689 59,637 30,863 233,877 48,025 55,702 Income tax expense (14,645) (11,536) (5,173) (45,620) (22,523) (21,713) Net income $ 68,044 $ 48,101 $ 25,690 $ 188,257 $ 25,502 $ 33,989 Earnings per common share, basic $ 0.32 $ 0.22 $ 0.12 $ 0.87 $ 0.12 $ 0.16 Weighted average number of common shares, basic 217,132 217,344 217,022 217,223 216,964 216,901 Earnings per common share, diluted $ 0.32 $ 0.22 $ 0.12 $ 0.87 $ 0.12 $ 0.16 Weighted average number of common shares, diluted 217,197 217,547 217,429 217,376 217,421 216,903
Balance sheet 27 Appendix PACIFIC DRILLING S.A. AND SUBSIDIARIES Condensed Consolidated Balance Sheets (in thousands, except par value) (unaudited) December 31, 2014 2013 Assets: Cash and cash equivalents $ 167,794 $ 204,123 Accounts receivable 231,027 206,078 Materials and supplies 95,660 65,709 Deferred financing costs, current 14,665 14,857 Deferred costs, current 25,199 48,202 Prepaid expenses and other current assets 17,056 13,889 Total current assets 551,401 552,858 Property and equipment, net 5,431,823 4,512,154 Deferred financing costs 45,978 53,300 Other assets 48,099 45,728 Total assets $ 6,077,301 $ 5,164,040 Liabilities and shareholders' equity: Accounts payable $ 40,577 $ 54,235 Accrued expenses 45,963 66,026 Long-term debt, current 369,000 7,500 Accrued interest 24,534 21,984 Derivative liabilities, current 8,648 4,984 Deferred revenue, current 84,104 96,658 Total current liabilities 572,826 251,387 Long-term debt, net of current maturities 2,781,242 2,423,337 Deferred revenue 108,812 88,465 Other long-term liabilities 35,549 927 Total long-term liabilities 2,925,603 2,512,729 Commitments and contingencies Shareholders' equity: Common shares, $0.01 par value per share, 5,000,000 shares authorized, 232,770 and 224,100 shares issued and 215,784 and 217,035 shares outstanding as of December 31, 2014 and December 31, 2013, respectively 2,175 2,170 Additional paid-in capital 2,369,432 2,358,858 Treasury shares, at cost (8,240) — Accumulated other comprehensive loss (20,205) (8,557) Retained earnings 235,710 47,453 Total shareholders' equity 2,578,872 2,399,924 Total liabilities and shareholders' equity $ 6,077,301 $ 5,164,040
Cash flow statement 28 Appendix PACIFIC DRILLING S. A. AND SUBSIDIARIES Condensed Consolidated Statements of Cash Flows (in thousands) (unaudited) Three Months Ended Years Ended December 31, December 31, 2014 September 30, 2014 December 31, 2013 2014 2013 2012 Cash flow from operating activities: Net income $ 68,044 $ 48,101 $ 25,690 $ 188,257 $ 25,502 $ 33,989 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation expense 56,547 50,187 39,713 199,337 149,465 127,698 Amortization of deferred revenue (25,884) (27,278) (20,179) (109,208) (72,515) (95,750) Amortization of deferred costs 11,531 12,885 10,332 51,173 39,479 70,660 Amortization of deferred financing costs 2,951 2,544 1,787 10,416 10,106 13,926 Amortization of debt discount 235 227 193 817 445 — Write-off of unamortized deferred financing costs — — — — 27,644 — Costs on interest rate swap termination — — — — 38,184 — Deferred income taxes 15,281 (48) (614) 18,661 (3,119) (3,766) Share-based compensation expense 2,952 2,876 2,351 10,484 9,315 5,318 Changes in operating assets and liabilities: Accounts receivable (46,736) (26,428) (74,826) (24,949) (53,779) (89,721) Materials and supplies (3,564) (9,624) (6,328) (29,951) (16,083) (6,640) Prepaid expenses and other assets (16,123) (20,952) (18,948) (56,493) (30,840) (61,548) Accounts payable and accrued expenses (964) 30,049 10,637 20,865 12,301 33,865 Deferred revenue 8,267 37,953 67,195 117,001 94,482 156,967 Net cash provided by operating activities 72,537 100,492 37,003 396,410 230,587 184,998 Cash flow from investing activities: Capital expenditures (386,519) (115,802) (103,893) (1,136,205) (876,142) (449,951) Decrease in restricted cash — — — — 172,184 204,784 Net cash used in investing activities (386,519) (115,802) (103,893) (1,136,205) (703,958) (245,167) Cash flow from financing activities: Proceeds from shares issued under share-based compensation plan (79) (73) — 95 — — Proceeds from long-term debt 400,000 — 159,000 760,000 1,656,250 797,415 Payments on long-term debt (36,208) (1,875) (21,875) (41,833) (1,480,000) (218,750) Payments for costs on interest rate swap termination — — — — (41,993) — Payments for financing costs (7,069) — — (7,569) (62,684) (19,853) Purchases of treasury shares (7,227) — — (7,227) — — Net cash provided by financing activities 349,417 (1,948) 137,125 703,466 71,573 558,812 Increase (decrease) in cash and cash equivalents 35,435 (17,258) 70,235 (36,329) (401,798) 498,643 Cash and cash equivalents, beginning of period 132,359 149,617 133,888 204,123 605,921 107,278 Cash and cash equivalents, end of period $ 167,794 $ 132,359 $ 204,123 $ 167,794 $ 204,123 $ 605,921
EBITDA reconciliation 29 Appendix 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. EBITDA and adjusted EBITDA do not represent and should not be considered alternatives 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 and adjusted EBITDA may not be comparable to that reported by other companies. EBITDA and adjusted EBITDA are included herein because they are used by management to measure the company's operations and are intended to exclude charges or credits of a non‐routine nature that would detract from an understanding of our operations. Management believes that EBITDA and adjusted EBITDA present useful information to investors regarding the company's operating performance during fourth‐quarter and full‐year 2014. PACIFIC DRILLING S.A. AND SUBSIDIARIES Supplementary Data—Reconciliation of Net Income to Non-GAAP EBITDA and Adjusted EBITDA (in thousands) (unaudited) Three Months Ended Years Ended December 31, December 31, 2014 September 30, 2014 December 31, 2013 2014 2013 2012 Net income $ 68,044 $ 48,101 $ 25,690 $ 188,257 $ 25,502 $ 33,989 Add: Costs on interest rate swap termination — — — — 38,184 — Interest expense 39,874 35,626 25,770 130,130 94,027 104,685 Interest expense 39,874 35,626 25,770 130,130 132,211 104,685 Depreciation expense 56,547 50,187 39,713 199,337 149,465 127,698 Income taxes 14,645 11,536 5,173 45,620 22,523 21,713 EBITDA $ 179,110 $ 145,450 $ 96,346 $ 563,344 $ 329,701 $ 288,085 Add (subtract): Costs on extinguishment of debt — — — — 28,428 — Loss of hire insurance recovery — — — — — (23,671) Adjusted EBITDA $ 179,110 $ 145,450 $ 96,346 $ 563,344 $ 358,129 $ 264,414
Net income excluding charges reconciliation 30 Appendix During the second quarter of 2013, the company closed a refinancing transaction that resulted in material non‐recurring costs primarily related to swap termination fees and the write‐off of unamortized debt issue costs. Management believes that net income excluding charges related to our refinancing and loss of hire insurance recovery provides useful and comparable information to investors regarding the company’s operating performance. Specifically, the excluded charges are of a non‐routine nature and management believes they detract from an understanding of our operating performance and comparisons with other periods. Net income excluding charges does not represent and should not be considered an alternative to or substitute for net income, operating income, cash flow from operations or any other measure of financial performance presented in accordance with GAAP, and our calculation of net income excluding charges may not be comparable to that reported by other companies. PACIFIC DRILLING S.A. AND SUBSIDIARIES Supplementary Data—Reconciliation of Net Income and Earnings per Share to Non-GAAP Net Income Excluding Charges and Earnings per Share Excluding Charges (in thousands, except per share information) (unaudited) Three Months Ended December 31, Years Ended December 31, 2014 2013 2014 2013 2012 Net income $ 68,044 $ 25,690 $ 188,257 $ 25,502 $ 33,989 Add (subtract): Loss of hire insurance recovery — — — — (23,671) Costs on interest rate swap termination — — — 38,184 — Costs on extinguishment of debt — — — 28,428 — Net income excluding charges $ 68,044 $ 25,690 $ 188,257 $ 92,114 $ 10,318 Earnings per common share, basic and diluted $ 0.32 $ 0.12 $ 0.87 $ 0.12 $ 0.16 Add (subtract): Loss of hire insurance recovery — — — — (0.11) Costs on interest rate swap termination — — — 0.18 — Costs on extinguishment of debt — — — 0.13 — Earnings excluding charges per common share, basic and diluted $ 0.32 $ 0.12 $ 0.87 $ 0.43 $ 0.05
Financial covenants in our credit facilities post‐pending amendment 31 2013 $500M RCF 2014 $500M RCF $1B SSCF Liquidity $100M (including 2013 RCF undrawn capacity – reduced to $50M post SSCF) $100M (including 2013 RCF undrawn capacity – reduced to $50M post SSCF) $50M (cash in group account) Other Financial Covenants Notes: • Leverage ratio is Adjusted Net Debt to Adjusted EBITDA • Adjusted Net Debt excludes 100% of SSCF debt prior to 09/30/15 and Meltem debt prior to 06/30/16 • Adjusted EBITDA adds back amortization on Deferred Assets Notes: • Leverage ratio is Adjusted Net Debt to Adjusted EBITDA • Adjusted Net Debt excludes 100% of SSCF debt prior to 09/30/15 and Meltem debt prior to 06/30/16 • Adjusted EBITDA adds back amortization on Deferred Assets Notes / Additional Financial Covenants: • Leverage ratio is Adjusted Net Debt to Adjusted EBITDA • Adjusted Net Debt excludes 100% of SSCF debt prior to 09/30/15 and Meltem debt prior to 06/30/16 • Adjusted EBITDA adds back amortization on Deferred Assets • Projected DSCR calculated as: Adjusted EBITDA to sum of Paid Interest + 1/10th of Total Debt • Consolidated Tangible Net Worth: Min. $1B • Debt to Total Cap: Max. 60% Period Leverage Max 12/31/13‐3/31/14 5.75:1 6/30/14‐12/31/14 5.25:1 3/31/15‐12/31/15 4.75:1 >3/31/16 4.25:1 Period Leverage Max 9/30/14‐12/31/14 5.25:1 3/31/15‐12/31/15 4.75:1 >3/31/16 4.25:1 Period Leverage Max Projected DSCR Min 12/31/13‐3/31/14 5.50:1 1.125:1 6/30/14‐12/31/14 5.00:1 1.25:1 3/31/15‐12/31/15 4.50:1 1.25:1 3/31/16‐3/31/16 4.00:1 1.25:1 >6/30/16 4.00:1 1.50:1 Appendix
Upstream and Downstream Guarantees Pacific Drilling S.A. (Luxembourg) Public Entity $1.0Bn Senior Secured Credit Facility (SSCF) Issuing Entities $500M PDV Sr. Secured US Bonds Issuing Entity Recourse Guarantors for 2013 Refinancing Tranches (2013 RCF, Bonds, TLB) • Pacific Sharav Sàrl • Pacific Drillship VII Ltd. (Meltem) • $500M First Out 2013 Secured RCF • $750M First Lien Secured Bonds • $750M First Lien Secured Term Loan B • $300M Norwegian unsecured bond • $500M 2014 Secured RCF • Pacific Drilling V. Ltd. (Khamsin) • Pacific Bora Ltd. • Pacific Scirocco Ltd. • Pacific Mistral Ltd. • Pacific Santa Ana Sàrl Recourse Guarantor for 2014 RCF financing • Pacific Drilling VIII Ltd. (Zonda) 2013 Refinancing Tranches 32 Unified corporate credit with different collateral packages Appendix
$112 $132 $132 $132 $83 $21 $500 $713 $604 $750 $300 $300 Remaining 2015 2016 2017 2018 2019 2020 Mandatory Amortization Scheduled Maturities RCF Debt Commitments Raised Outstanding Amortization Maturity Margin/Rate Collateral Vessels 7.25% Sr. Secured Notes $500m $500m Balloon Dec 2017 7.25% fixed Khamsin Sr. Secured Credit Facility(12) $1,000m $879m 12 years May 2019 LIBOR + 3.375% Sharav, Meltem 5.375% Sr. Secured Notes $750m $750m Balloon Jun 2020 5.375% fixed Bora, Mistral, Scirocco, Santa Ana Term Loan B $750m $736m 1% per year Jun 2018 LIBOR + 3.50% Bora, Mistral, Scirocco, Santa Ana 2013 Revolving Credit Facility $500m Footnote Balloon Jun 2018 LIBOR + (2.50% to 3.25%) Bora, Mistral, Scirocco, Santa Ana 2014 Revolving Credit Facility(12) $500m $180m 12 years Jun 2020 LIBOR + (1.75% to 2.50%) Zonda Total $4,300m $3,045m NOTES: • 2013 Revolving Credit Facility: $300m maximum cash sublimit (currently undrawn) and $300m maximum sublimit for letters of credit, not to exceed $500m in aggregate • 2014 Revolving Credit Facility: Matures 5 years after the delivery date of the Pacific Zonda • Amounts shown in bar chart include projected drawdowns on Sr. Secured Credit Facility & 2014 RCF, portions of which are not currently outstanding 33 No funding needs until December 2017, when 7.25% bonds mature Appendix
