Pareto Offshore Drilling Conference

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8 Νοε 2013 (πριν από 3 χρόνια και 9 μήνες)

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April 18, 2012
Pareto Offshore Drilling
Conference
Chris Beckett, CEO
Disclaimer

1

2
• This presentation contains statements that express opinions, expectations, beliefs,
plans, objectives, assumptions or projections of Pacific Drilling S.A. (the “Company”
or “Pacific”) regarding future events or future results, in contrast with statements
that reflect historical facts. Examples include discussion of our strategies, financing
plans and growth opportunities. In some cases, we have identified such forward-
looking statements with typical conditional words such as “anticipate,” “intend,”
“believe,” “estimate,” “plan,” “seek,” “project” or “expect,” “may,” “will,” “would,
“could” or “should,” the negative of these terms or other comparable terminology.
These forward-looking statements are not a guarantee of performance, and you
should not place undue reliance on such statements. We have based these forward-
looking statements largely on our current expectations and projections about future
events. Forward-looking statements are subject to many risks, uncertainties and
other variable circumstances that may cause the statements to be inaccurate and
readers are cautioned not to place undue reliance on such statements. Many of these
risks are outside of our control and could cause our actual results and experience to
differ materially from those we thought would occur. The forward-looking statements
included in this presentation are made only as of the date hereof. We do not
undertake, and specifically decline, any obligation to update any such statements or
to publicly announce the results of any revisions to any of such statements to reflect
future events or developments.
• This presentation does not constitute an offer to sell or a solicitation of an offer to
buy the Company’s common shares.
Who is Pacific Drilling?
3
Focus on the
Growing Ultra-
Deepwater Market
Dedication to
Operational
Excellence
Commitment
to
Shareholder
Value
Pure-Play
Ultra-
Deepwater
Drillship
Asset Base
Financial
Strength
Core areas
Emerging areas
Areas With Active Ultra-deepwater Rig Programs In 2012
Core Areas

US Gulf of Mexico

Attractive fiscal terms

Lower Tertiary ultra-deep wells
Brazil

Pre-salt success

Light oil & gas
West Africa

Long-lead time developments

Emerging Areas

East Africa

Major gas discoveries
Other West Africa

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
Pacific Drilling present in all core ultra-deepwater areas

A Global Growth Market
4
Operations
HQ
Support
41%
12%
2%
45%
Over 20
11 to 20
6 to 10
5 or Under
Advanced Drillships Deliver on
Industry Requirements

Challenges of remote drilling sites



Drilling deeper and with longer offsets



Greater drilling efficiency to reduce total well costs



Advances in well construction



More demanding downhole environments, e.g. high
pressure & temperature drilling


• Increasingly demanding regulatory climate
1
2
3
4
5
6
Over 40% Of Floaters Greater than 20 Years Old

Industry Trends

Rig Age in Years
(1)
…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)
6
111
Demand
111
Supply
Projected
current unmet
demand
150
18
129
Demand Supply
111
170
23
Demand Supply
152
129
185
13
Supply
165
152
Demand
Existing UDW Fleet Newbuild Rigs
Dec 31, 2011 2012 2013 2014
Supply and Demand Forecast

12/11 11/11 10/11 9/11
Day rate, $K/d
7/11 6/11 5/11
700
650
600
550
500
450
400
Date
4/12 3/12 2/12 1/12 8/11
> 3 Years
1-3 Years
Contract Length
Rising Day Rates for Fixtures
(3)

7
Newer Rigs Enjoy Higher Utilization
Rates Throughout Cycle
Current Floater Fleet by Delivery Year
(4)
Floater Utilization since 2008 by Build Cycle
(4)
Oct
Jan
Apr
Jul
Oct
Jan
Apr
Jul
Oct
Jan
70
80
90
100 2007-Current
1998-2006
Jan
Jan
95
75
85
1971-1978
1979-1997
Apr
Jul
Apr
Oct
Jul
2008 2009 2010 2011 2012
8
40
35
30
25
20
1980
1975
2010
2005
2000
1995
1990
1985
1971
0
10
5
15
1970
1975
1980
1985
1990
1995
2000
2005
2010
2015
2020
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
10,000
11,000
12,000
Pacific Drilling: Most Modern,
Pure Play UDW Fleet
More Modern

Deeper Water


Average Floater Fleet Depth and Age
(6)
Average Water Depth (Ft.)

Average Year Built

Songa
Fred Olsen Energy
Diamond Offshore
North Atlantic Drilling
Noble
Transocean
Seadrill
Ocean Rig
Ensco
Area of bubble represents
total enterprise value
(5)
Atwood
9
Fleet Capabilities Designed to
Satisfy Customer Demands
10
Consistent, Proven Design & Drilling
Package
Fleet-wide Water Depth Capability 10-
12,000 ft.
Dual Derricks with 1000-1250 ST Hook
Loads
2x Single plus Offline & 4x Dual Load Path
Rigs
200 POB 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
Consistent, Proven Design & Drilling
Package
Fleet-wide Water Depth Capability 10-
12,000 ft.
Dual Derricks with 1000-1250 ST Hook
Loads
2x Single plus Offline & 5x Dual Load Path
Rigs
200 POB Accommodation, 22,000 ST
Displacement
• Removes the effect of mud weight in the riser
column

Especially important in deeper water and
wellbores (e.g. Gulf of Mexico or pre-salt Brazil)


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
Value to Operators
A Proven Well Construction Advance
Value to Pacific Drilling
• Sole drilling contractor with knowledge and
equipment to provide mud-lift based Dual
Gradient Drilling in ultra-deepwater
• Anticipate a long-term competitive advantage
• Cost to upgrade existing rigs uneconomic
Dual Gradient Drilling –
Game-Changing Technology
Seawater hydrostatic pressure
Drilling and hydrostatic pressure
profiles for varying mud weights
Drilling mud hydrostatic pressure
Formation fracture pressure
Formation pore pressure
Footnote 7
11
Delivering on Promises
Development
Building the
platform
Operations &
Growth
Fully-fledged
UDW
contractor
Startup
Initial
investment
Formed by the
Quantum Pacific
Group (QP)
Becoming The Preferred UDW Drilling Contractor
Established management team
Initiated
construction of
4 drillships
Implemented
management
systems
2 drilling contracts
signed
2 drilling contracts
signed
Closed $600 MM
private placement
Ordered 2
additional
drillships
3 rigs delivered
Bora and Scirocco
began drilling
operations
$1.8 Bn financing
secured
First rig delivered
NYSE listing
Built operations support team, over 900 staff to date
Closed $300 MM
bond financing
Ordered one
additional drillship
2006 2007 2008 2009 2010 2011 2012
Mistral began
drilling operations
Santa Ana on
contract
12
• Construction and commissioning of 7 drillships at Samsung
 Initial 4 rigs delivered on time and on budget

No lost time incidents (nearly 700,000 manhours)

• Post-delivery phase for Pacific Bora, Pacific Scirocco and Pacific Mistral

0.59 LTIF
(8)
(total 1.69 million manhours)

• Pacific Bora, Pacific Scirocco, and Pacific Mistral contract commencement
 Pacific Bora first rig to enter Nigeria under new local content regulations
 No recordable incidents
 Pacific Bora achieved 93.2% average revenue efficiency
(9)
through December 31, 2011
Delivering

Operational Excellence
13
475 470
458 468
78
104
32 31
Bora Scirocco Mistral Santa Ana
Full contract revenue per day
Contract day rate
11%
10%
10%
8%
8%
7%
6%
40%
486
162
511
924
Bora Scirocco Mistral Santa Ana
$2.1 Billion Backlog

With Blue Chip Operators
Contract Backlog Total,
(10) (11)
$ MM
Average Remaining Contract Backlog Revenue Per Day, $ K

Blue Chip Partners
(12)

Percent of total deepwater developments by operator (2008-12E)
499
490
574
553

Strong backlog, with additional potential from options


Contracts with well-capitalized international oil
companies


Demonstrated ability to secure premium rates

• Proven market acceptance
Term
Firm years
Optional years
3
2
1
4
3
0
5
0
14
Chevron (Bora, Santa Ana)
Pacific Drilling Customer Other
Total (Scirocco)
BP
Statoil
Petrobras (Mistral)
ExxonMobil
Shell
Others
2012
2013
2014
Chevron Nigeria, $475k/d
(14)
3 year contract

Total Nigeria, $470k/d
(14)
1 year contract

Petrobras Brazil, $458k/d
(14)
3 year contract

Chevron USGOM, $467.5k/d
(14)
5 year contract

Delivery: April 2013

Delivery: September 2013

Delivery: May 2014

Pacific Bora
Options for up to 4 years of additional term

Pacific
Scirocco
Pacific
Mistral
Pacific
Santa Ana
Pacific
Khamsin
Pacific
Sharav
Pacific TBN
#7
Balanced Mix of Dayrate Exposure
and Contracted Backlog
(13)
Options for up to
2 years of
additional term
Strong Balance Sheet
(17)
$ 2.2 billion of net equity raised
• $1.6 B from main sponsor, $0.6 B from Private
Placement April 2011 and $57 MM from IPO November
2011
• Current market capitalization $2.21 B (@$10.19/share)

Strong balance sheet, pro-forma equity of ~44%

Fully funded net debt of $2.96 B for all seven units

Recent bond offering added to financial strength and
flexibility

To fund company growth via Drillship #7, working
capital and general corporate requirements

Implied valuation per rig of $757 MM
16
Liquidity reserve, working
capital and restricted cash
Capex – Khamsin, Sharav
and Drillship TBN #7
Capex – deliveries and
construction orders for
initial four drillships
Net Private Placement
and IPO proceeds
Equity contribution
from sponsor
Project Facilities
Agreement
(15)

1.6
0.6
1.3
0.3
1.7
5.5
Sources
(16)

February 2012
Scandinavian bond
Remaining debt funding
for Khamsin, Sharav &
TBN #7
Equity Debt
0.5
1.8
3.2
5.5
Uses
Fleet Growth has the Potential
to Propel EBITDA Growth
$500 K/d
$550 K/d
$600 K/d
Newbuilds and Future
Roll-offs
(18)
Contracted at
the Following Day Rates:
Result in these Levels of Future Projected
EBITDA, $ MM
17
390
600
730
2013 2014 2015
395
635
840
2013

2014

2015

400
675
945
2013

2014

2015

Newbuild Considerations
18
Considerations:

Informed By:

• Long term market view
• Newbuild cost
Project

Returns
• Maximum 2 rig exposure
• Financing requirements
Project

Risk
• Rig staffing
• Management bandwidth
Operational

Constraints
19
Committed to Shareholder
Value Creation
• Target continued growth
– Benefit from strengthening UDW market conditions
– Build on leading-edge technology, e.g. dual gradient
drilling

Seek value-creating growth opportunities: organic
and inorganic

• Corporate and operational excellence
– Capitalize on high quality assets
– Differentiate through people and processes

Deliver best-in-class corporate governance

• Disciplined financial management
– Enhance liquidity; Listed on the NYSE
– Focus on appropriate use of excess cash
– Monitor market conditions to assure appropriate
capital structure
• Expand EBITDA / CF
• Optimize capital structure
• Minimize the cost of capital
1
2
3
April 18, 2012
Pareto Offshore Drilling
Conference
Chris Beckett, CEO
1) Floater age data from ODS-Petrodata as of January 2012. Analysis by Pacific Drilling. Includes rigs under construction.
2) Supply data from ODS-Petrodata as of March 20, 2012, for rigs with water depth capability of 7,500 ft or greater. Supply and demand
analysis by Pacific Drilling.
3) Data from ODS-Petrodata as of April 9, 2012. Analysis by Pacific Drilling. Day rate excludes mobilization and other compensation. Priced
option exercises not included. Does not include contracts for under 1 year in duration.
4) Data from ODS-Petrodata as of March 2012. Analysis by Pacific Drilling. “2007-Current” adjusted to remove impact of Ocean Courage
and Petrobras 10,000 in 2009, which were subject to construction finance issues and unable to work
5) Enterprise value includes committed capital expenditures. Data from public company disclosures and Pareto Securities as of March 30,
2012.
6) Average water depth and average year built for deepwater fleet include assets under construction as of September 2011.
7) Graphic sourced from Scientific Drilling, July 6, 2008.
8) LTIF is defined as Lost Time Incidents (LTI) per million manhours. Data is through end of year 2011
9) Revenue efficiency is defined as actual contractual dayrate revenue (excludes mobilization fees, upgrade reimbursements and other
revenue sources) divided by the maximum amount of contractual dayrate revenue that could have been earned during such period.
10) As of March 31, 2012; does not include contract options. For Pacific Santa Ana, assumes backlog counted as of contract
commencement; however, we are currently evaluating the U.S. GAAP treatment of revenues for the period between contract
commencement and arrival in the USGoM.
11) Includes revenues from contract day rate, mobilization, and client contract upgrade. Mobilization and client contract upgrade revenue
are not dependent on efficiency.
12) Deepwater developments by operator from Wall Street Research.
13) Fleet status reflected as of March 31, 2012.
14) Daily contract backlog revenue does not include mobilization and client contract upgrade revenues.
15) Total drawdown on the $1.8 B facility was $1.725 B As of December 31, 2011, $50 MM of the total $1.725 B draw from the facility has
been repaid (from debt amortization on the Bora), leaving outstanding debt of $1.675 B.
16) Excluding cash flow generated from operations and principal repayments.
17) 216.9 MM shares at $10.19 per share as of closing price on April 11, 2012. Total drawdown on the $1.8 B facility was $1.725 B. As of
December 31, 2011, $50 MM of the total $1.725 B draw from the facility has been repaid (from debt amortization on the Bora), leaving
outstanding debt of $1.675 B. Excludes cash flow generated from operations and principal repayments.
18) Pacific Scirocco assumed to have its options exercised rather than gain exposure to these day rates. Re-rate exposure schedule through
2015 assumed to be: Pacific Khamsin – 2013, Pacific Sharav – 2013, Pacific Bora – 2014, Pacific TBN #7 – 2014 and Pacific Mistral – 2015.
19) Includes assumption of quarterly allocation of approximately $100 MM in capital expenditures per rig which are not included in the
Samsung construction contracts.
Footnotes
21
Appendix – Future Capex
Needs Projected to be $1.76B
Billion
Quarterly Capex Projection ($B)
(19)
First four units are fully funded
• $1.8 B senior secured facility in place
• $1.7 B drawn on the facility
0.05
0.01
0.33
2Q 2012 3Q 2012 1Q 2012
0.14
0.35
0.45
Total
1.76
0.10
0.11 0.11
4Q 2012 1Q 2013 2Q 2013 3Q 2013 4Q 2013 1Q 2014 2Q 2014
0.11
Pacific TBN #7
Pacific Santa Ana and other
Pacific Sharav
Pacific Khamsin
Equity portion of Pacific Khamsin and Pacific Sharav in
place
• $1.1 B in remaining capex
• Expected to be funded through senior secured debt of
$450 MM per unit
22