Deutsche Bank Leveraged Finance Conference Scottsdale, Arizona September 28-30, 2015

Transcription

1 Deutsche Bank Leveraged Finance Conference Scottsdale, Arizona September 28-30, 2015

2 Forward Looking Statements Certain statements and information contained in this presentation constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of Where any forward-looking statement includes a statement about the assumptions of bases underlying such 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. Any forward-looking statement where our management expresses an expectation as to future results is expressed in good faith and is believed to have a reasonable basis; however, we cannot assure you that the statement of expectation will result or be achieved. These statements relate to analyses and other information that are based on forecasts of future market conditions and results and estimates of amounts not yet determinable. These statements also relate to our future prospects, market developments and business strategies. Forward-looking statements typically include words or phrases such as believe, estimate, expect, forecast, our ability to, plan, potential, projected, target, 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: market conditions; future operational performance and cashflow; client contract opportunities; contract dayrate amounts; cost savings initiatives; contract backlog; revenue efficiency levels; construction, timing and delivery of newbuild drillships; capital expenditures; cost adjustments; estimated rig availability; 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. There can be no assurance that future developments affecting us will be those that we anticipate. 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 or dispositions. 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: levels of offshore drilling activity, reduced capital expenditures by our clients and general market conditions; changes in worldwide oil and gas supply and demand, rig availability, competition and technology; our ability to secure and maintain drilling contracts, including possible cancellation, renegotiation or suspension of drilling contracts as a result of market changes, mechanical difficulties, performance, regulatory or other approvals, or other reasons; outcome of negotiations with the shipyard regarding construction and delivery delays; our ability to favorably revise our current debt covenants; unplanned downtime and other risks associated with offshore rig operations, including unscheduled repairs or extended maintenance; governmental action, strikes, public health threats, civil unrest and political and economic uncertainties; relocations, severe weather or hurricanes; 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 or through the SEC s Electronic Data and Analysis Retrieval System at 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.

3 Topics 1. Macro Oil & Deepwater Picture Oil Supply & Demand Deepwater Cost Curve Improvements Deepwater Rig Supply & Demand 2. Pacific Drilling Performance and Initiatives Operational Excellence Cost Management Financial Strength 3

4 Over 20 Million Barrels a Day of New Supply Needed by 2020 OIL SUPPLY & DEMAND Oil Supply Demand Balance Forecast through Million Barrels per Day Supply Supply Inventory Supply Growth Required Demand New Demand Forecast 4

5 Demand Forecasts Have Increased to Above 2014 Estimates OIL SUPPLY & DEMAND Change in World Oil Demand Forecast from Previous 2 Year-Over-Year Change in World Oil Demand Forecast 2 mb/d Change vs. t-6 Mo. mb/d Change vs. t-12 Mo Q1 Q2 Q3 Q Current world demand forecast outpaces February s forecast substantially, and is generally higher than August 14 estimates OECD demand increases driving changes in forecasts Year-over-year change in world demand varies but averages ~1 Mmb/d in recent years 5

6 OPEC Spare Capacity is at Historic Lows OIL SUPPLY & DEMAND OPEC Spare Capacity 3 (mmb/d) Oil markets at 58mb/d Oil markets at 93mb/d OPEC Spare Capacity 3 (% of Global Supply) 20% 18% 16% 14% 12% 10% 8% 6% 4% 2% 0% Oil markets at 58mb/d Oil markets at 93mb/d

7 Production Forecasts Have a History of Disappointing, Primarily Due to Above-Ground Factors OIL SUPPLY & DEMAND Companies reported production (bars) vs previous guidance 4 (lines) (mb/d) Countries reported production vs target 4 (mb/d) Oil Major #1 Oil Major #2 Country Target (mmb/d) Set in For year Delivered In year Iraq ~ Brazil ~ Angola ~ Oil Major #3 Oil Major #4 Venezuela Nigeria ~ < Kazakhstan (Kashagan field) ~ UAE Delayed to

8 Sharp Rebound in Shale Drilling Activity Needed to Resume Annual Increases in Production OIL SUPPLY & DEMAND Resuming 1 mb/d shale production growth requires a stabilized decline rate, continued efficiency gains and a rapidly inflecting rig count US Tight Oil Production 4 (mboe/d) Production forecasts have long history of disappointing, for companies and countries alike No country has ever delivered such sharp growth over such an extended period of time Financing is a key obstacle with continued negative cash flow A rapid rebound in drilling activity is likely to re-accelerate cost inflation 8

9 Deepwater Resources Will Have to Fill the Supply- Demand Gap OIL SUPPLY & DEMAND Long lead time for DW projects require investment years before production Growth in LNG market should intensify need for DW drilling 25 Projected Call on Deepwater beyond Sanctioned Projects 5 20 >7 Million Barrels per Day ~1 ~ Additional Demand Opec Ex Iran Iran Shale Non-Opec ex DW Storage DW Sanctioned 9

10 Offshore Project Rework is Lowering Breakevens DW COST IMPROVEMENTS Offshore Projects Seeing Notable Reduction in Breakeven by 15-20% After Cost Savings 6 $/bbl $/bbl Likely viable based on futures curve Cost Deflation Decline in rig dayrates and well service cost Cost cuts in many other services are yet to be realized Design Improvements Development Plans Efficiency Gains Standardization Shell Appomattox Design improvements BP Hopkins Fast Track plan to clone previous production unit Chevron Jack St. Malo Hub development concept Increased drilling efficiency Downtime reduction Supplier Consolidation o Schlumberger / Cameron o Forsys Subsea (FMC & Technip) o Aker / Baker Hughes production alliance Drilling equipment Subsea Topsides / FPSO 10

11 Key Deepwater Demand Drivers by 2020 RIG SUPPLY & DEMAND Emerging Future Demand: Mexico Focus Returns to Reserve Replacement 350 IOCs are expected to ramp up activity in Mexico over the next few years following current energy reform efforts Revitalize Major Resources: Brazil Brazil is proven to have a strong deepwater resource base. Reform efforts should allow IOCs to increasingly capitalize on this in the coming years Avg Est Exploration and appraisal wells Build on Current Activity: US GoM/W. Africa With a healthy mix of exploration and development work, operators will look to grow exploration into production in coming years. Both regions are proven to have strong resource bases. 11

12 The Industry Needs to Remove Excess Capacity RIG SUPPLY & DEMAND 8 Contracted vs Available Rigs by Water Depth 8 12

13 Floater Rig Demand Could Overtake UDW Rig Supply by 2017 with Appropriate Attrition RIG SUPPLY & DEMAND 8 Contracted vs Available Rigs by Water Depth 8 Recovery Timeframe 13

14 High-Spec UDW Drillships Are Best Positioned for Majority of Work RIG SUPPLY & DEMAND 72% of the market is temperate and globally competitive for international drilling contractors; 94% of high-spec floaters operate in less than 7,500 feet water depth 100% 90% 80% 70% 60% Current Rig Status by Asset Class Current Floater Market Areas 9 19% 9% 72% Harsh Environment Niche Market Global Temperate 50% 40% 30% 20% High-Spec Floater Operating Depth 9 (ft) 6% 27% 10% 0% UDW DW MW Drilling Warm Stacked Cold Stacked Other 67% Less than 4,500 4,500-7,499 7,500 or greater 14 NOTES: Harsh environment includes Netherlands, Russia, Norway, Canada, Falkland Islands, and the UK Niche markets include Romania, Iran, Australia, China, and Azerbaijan

15 PACD s 100% High-spec Fleet Well Positioned for Future Market Opportunities RIG SUPPLY & DEMAND Percentage of fleet composition by rig capability and type 9 8% 8% 20% 17% 44% 38% 47% 33% 63% 100% 85% 12% 15% 8% 20% 16% 54% 88% 44% 38% 28% 19% 19% 14% 14% 13% 14% 13% 11% Pacific Drilling Ocean Rig Seadrill Atwood Transocean Noble Diamond Offshore Rowan Ensco High Spec Standard Spec Low Spec Jackup Rig Classification Index (Specification Scale Exclusively Floaters) 15 NOTES: Graph includes newbuilds not yet delivered

16 Succeeding in a Tough Market, Positioned to Take Advantage of a Future Recovery Pacific Drilling distinguished by operational excellence and cost management Operational excellence more important than ever: expect market to be very tough for at least 18 months Clients want the rigs that deliver PACD management focused on minimizing downtime & maximizing rig efficiency PACD has highest average rig capability and industry-leading UDW operating performance Cost management is key, while maintaining longer-term optionality & marketability Rig opex per day reduced every quarter since beginning 2014 Recent initiatives expected to generate > $150 million in annual run rate savings G & A has been reduced by > 20% YTD Maintaining ability to restart idle rigs within 90 days of contract award while significantly reducing costs 16

17 Revenue Efficiency Illustrates High Quality Client Service Delivery Clients want rigs that deliver OPERATIONAL EXCELLENCE (%) 100 Mean 95.7% Q Q4 Post-shakedown fleet revenue efficiency Q Q Q Q Q Q2 Already 9 wells in 2015 delivered ahead of client plan and budget across fleet Last 15 rig-years at >95% average uptime No significant well control events in company s operating history Highest efficiency rigs in the industry Mistral drilled 3 of 5 fastest wells in Lula field Santa Ana drilled 3 discoveries and is highest performer in Chevron US GoM fleet Scirocco delivering strongest operating performance in Total global fleet 17

18 $100m of Run-rate Savings Delivered to-date, with a Target of > $150m of Annualized Savings COST MANAGEMENT Sources of savings Labor and personnel costs Maintenance expenses Operations expenses Miscellaneous expenses Travel Variable compensation elements Overhead headcount Benefits Training Engineering & major projects Deferral of noncritical normal and project maintenance Materials & supplies Catering Customs Rentals Vessel inspections Agent fees Communications Insurance Other drillingrelated costs Supported by 3 rd party price reductions Targeting on contract average rig opex reduction from $178k/day (in 2014) to < $150k/day; Opex currently < $160k/day in Q

19 Smart Stacking Results in Idle Rig Costs of <$40k/day Without Incremental Investment COST MANAGEMENT Direct rig-related opex per day ($k) Miscellaneous 140 Operations Maintenance 103 Smart stacking efficiencies Personnel * Historical operating Conventional stacking savings Historical stacked Personnel savings Non-critical maintenance savings Rigs ready to work in <90 days; Idle rig cost < $15m/yr NOTES: * Stacking cost p/d potentially lower with further synergies Misc savings Smart stacking

20 Continuing to Deliver Industry-Leading EBITDA Margin with Only 5 Rigs on Contract FINANCIAL STRENGTH Range of adjusted EBITDA/revenue for offshore drillers 11,12 65% 60% 55% 50% 45% 40% 35% 30% 25% 3Q Q Q Q Q Q Q Q 2015 PACD Peer Offshore Driller Average 20 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 (adjusted to remove impacts from impairment for DO, RIG, ESV, NE)

21 Projected Positive EBITDA Through 2017 Even with No Additional Contracts Contract status as of September 27, 2015 FINANCIAL STRENGTH Pacific Bora Pacific Scirocco Chevron Nigeria, $586k/d 2 year extension Total Nigeria, $499k/d 2 year extension 2017 Existing contract provisions provide that any contract terminations are at least EBITDA neutral Pacific Mistral Available Pacific Santa Ana Pacific Khamsin Pacific Sharav Chevron USGoM, $490k/d 5 year contract CVX Nigeria, $660k/d 2 year contract Chevron USGoM, $558k/d 5 year contract Pacific Meltem Available Pacific Zonda Delivery under discussion with SHI 21 Firm Contract

22 Ongoing Initiatives to Further Strengthen Financial Position FINANCIAL STRENGTH Status of Pacific Zonda delivery currently under discussion with Samsung Finalizing negotiations with agent banks for post-2015 debt covenant revisions and 2014 RCF availability extension Current available liquidity is $615m of debt capacity and >$100m of cash Further cost reductions to include: - Rationalization of non-critical maintenance expense and capital expense - Further optimization of rig stacking - Additional adjustments to personnel costs - Additional improvement of vendor terms 22

23 Pacific Drilling Well Positioned to Meet the World s Deepwater Oil Needs Oil demand forecast to exceed supply plus excess storage by 2018 Other sources of oil beyond deepwater cannot fill the entire gap Deepwater project costs becoming more competitive Floater rig demand expected to exceed UDW rig supply by time frame Pacific Drilling is the only driller with a 100% highspec drillship fleet Pacific Drilling s Industry-leading operational performance and cost management delivering financial strength through the downturn 23

24 Investor Contact Pacific Drilling John Boots VP Finance & Treasurer 8-10 Avenue de la Gare L-1610 Luxembourg Luxembourg Phone:

25 25 Appendix

26 Footnotes 1. Through 2016: EIA International Petroleum and Other Liquids Production, Consumption, and Inventories, dated Sept Post 2016: assume 5% decline rate on supply and +1mbbls of demand per year post IEA February 2015, July 2015, August 2015, June 2014, June 2013 Monthly Oil Market Reports 3. EIA, IEA, IMF, Morgan Stanley 4. Morgan Stanley 5. Data is based on EIA supply/demand estimates through 2016, Simmons (Global Oil Macro Outlook: US Production and Global Balances Aug 21, 15) estimates for non-opec ex DW & DW sanctioned projects (PACD split by DW / ex DW), PACD analysis for gap and call on DW 6. Morgan Stanley Global Oil Services Drilling and Equipment July 9, Quest Offshore March 2015 for E&A well counts 8. IHS-Petrodata, PACD Supply Forecast, Morgan Stanley Demand (Ranged) 9. IHS-Petrodata 10.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. Post-shakedown revenue efficiency represents levels of average revenue efficiency which are typical for ongoing operations. Revenue efficiency is typically lower during shakedown, when a newbuild rig is undergoing the initial break-in of equipment. 11.EBITDA is a non-gaap measure. EBITDA is defined as earnings before interest, taxes, depreciation and amortization. The most comparable GAAP financial measure to EBITDA is net income, which includes interest, taxes, depreciation and amortization. EBITDA is included herein because it is used by management to measure the company's operations. Management believes that EBITDA presents useful information to investors regarding the company's operating performance 12.EBITDA margin is defined as 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. 26

27 US Shale Sweet Spots Are Clearly Demarcated; Outside Those, Productivity Deteriorates OIL SUPPLY & DEMAND In the low rig count environment, operators have focused on the core sweet spots in their portfolios, reaching high efficiency gains due in part to the nature of these assets However, as the rig count and the production required rises, lower productivity acreage will need to be drilled Financing is currently constrained as operators continue to outspend cash flow 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% Well Count (%) Peak Production (%) 100% 30% 90% of 80% wells 0% % 60% 50% 40% 30% 20% 10% Account for more than 80% of peak production 27 Source: Morgan Stanley

28 More Potential to Reduce Deepwater Project Cost DW COST IMPROVEMENTS Deflation in ~65% of total project cost not yet realized due to complexity, long lead times and long term contracts Deepwater Total Project Costs (1) Deepwater Project Costs (2) 7% 3% 5% 25% 40% 12% 65% 75% 10% 10% 15% 13% Offshore Drilling Subsea Equipment Offshore Engineering OCTG Marine Transport Well Service Subsea Installation FPSO ROV 28 SOURCES: Goldman Sachs 420 Projects to Change the World May 15, 2015 (assumed rig dayrate of $575k/d) Morgan Stanley