Timing the Return to Normalization for Offshore DrillingMarine Money Offshore Finance Forum

Michael Acuff, SVP Sales and Business Development, Pacific Drilling

April 7, 2016

Certain statements and information contained in this presentation constitute “forward-looking statements” within the meaning of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995, and are generally identifiable by the use of words such as “estimate,” “expect,” “forecast,” “plan,” “potential,” “projected,” “target,” or other similar words, which are generally not historical in nature. The forward-looking statements speak only as of the date hereof, and 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.

Our forward-looking statements express our current expectations or forecasts of possible future results or events, including: market outlook; forecasts of trends; future client contract opportunities; and our business strategies and plans and objectives of management.

Although we believe that the assumptions and expectations reflected in our forward-looking statements are reasonable and made in good faith, these statements are not guarantees and actual future results may differ materially due to a variety of factors. These statements are subject to a number of risks and uncertainties, many of which are beyond our control.

Important factors that could cause actual results to differ materially from our expectations include: the global oil and gas market and its impact on demand for our services; the offshore drilling market, including reduced capital expenditures by our clients; changes in worldwide oil and gas supply and demand; rig availability and supply and demand for high-specification drillships and other drilling rigs competing with our fleet; costs related to stacking of rigs; our ability to enter into and negotiate favorable terms for new drilling contracts or extensions; possible cancellation, renegotiation, termination or suspension of drilling contracts as a result of market changes or other reasons.

Forward Looking Statements

2

3

Summary

Two part solution to fixing the offshore rig market-Stacking/scrapping/delaying newbuild rigs-Demand recovery (stabilization/marginal growth)

-Floating rig market will be smaller than the 2015 peak floater fleet (~350 down to ~225 rigs)-But the fleet will be more technologically capable

-Recovery timeframe is likely to begin in late 2017 as rig contracting restarts-Dayrates will likely increase in 2018-19 as the market begins to tighten

4Source: IHS-Petrodata

Scale of Recent 6th/7th Gen Newbuild Cycle is Relatively in Line with 3rd/4th Gen Cycle

# of Rigs Delivered # of UDW Rigs in Fleet

0

20

40

60

80

100

120

140

160

180

200

0

5

10

15

20

25

30

35

40

1970 1975 1980 1985 1990 1995 2000 2005 2010 2015 2020

Floater Fleet by Delivery Year

Removed From Fleet UDW Floater Fleet (RHS)

Aging Floater Fleet Replaced By Newer, More Efficient Rigs

Source: IHS-Petrodata

Floater Fleet Composition

0

50

100

150

200

250

300

350

400

450

Under Construction Less than 10 years 10-20 years 20-30 years More than 30 years

5

No growth since 1985 with a fleet total of ~225

6Source: IHS-Petrodata, PACD estimates

~115 Rigs Have Left the Market Since 2014 and See Potential for Additional ~50 to Leave Through 2017

0

30

60

90

120

150

180

0

5

10

15

20

25

30

Q1 2014 Q2 2014 Q3 2014 Q4 2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015 Q1 2016 Overdue Q2 2016 Q3 2016 Q4 2016 Q1 2017 Q2 2017 Q3 2017 Q4 2017 Post 2017

Actual and Forecasted Rig Removal through Cold Stacking and Scrapping

6th gen+ 5th gen 4th gen 3rd gen-

6th gen+ 5th gen 4th gen 3rd gen-

Cumulative Out of Market (RHS) Estimated Out of Market (RHS)

Cold Stacked/Scrapped

Expected C. Stacked/Scrapped

7

Floater Fleet Profile vs Projected 2018 Floater Fleet Profile Shows a Net Fleet Decline of ~130 Rigs (-37%)

Projected Floater Fleet Changes

Source: IHS-Petrodata, Cold stacking is assumed after a rig is stacked for more than six months or after announced, PACD estimates

108

55

17

44

End of 2018

92

79

34

150

2015 Peak Fleet

-70

-60

-50

-40

-30

-20

-10

0

10

20

30Prior Scrapped Prior Cold Stacked 2016 2017 2018

Abs. Growth

% Change

6th Gen + 16 17%

5th Gen -24 -30%

4th Gen -17 -50%

3rd Gen - -106 -71%

Additions include 40 newbuilds (7 Sete) to be delivered through 2018, though we believe all are at risk for delays and some for cancellation

Addi

tions

Rem

oval

s

(355) (224)

122 114 123 137 143

8773 62

62 61

34

22 1617 17

150

86

5246 44

393

295

254 261 264

Peak Fleet End 2015 End 2016 End 2017 End 2018

Effective Floater Fleet(fleet x Gen drilling efficiency)

6th gen+ 5th gen 4th gen 3rd gen-

8

But More Capable Remaining Fleet Translates to Effective Fleet Decline of 33%

Est. Drilling Efficiency 1.33x 1.1x 1.0x 1.0x

Progression from 3rd through 5th gen was predominately focused on drilling deeper wells and carrying heavier loads

Move from 5th to 6th gen and especially to 7th is focused on increasing operational efficiencies

This increased efficiency is reflected in the greater weighting given to 6th Gen + rigs

Technology used to improve efficiency include:

Offline handling Dual mud systems Dual BOPs Increase tripping speeds Longer joints More deck load / storage Condition based maintenance

Source: IHS-Petrodata, Cold stacking is assumed after a rig is stacked for more than six months or after announced, PACD estimates

-33% Decline

12.0 13.4 12.29.6

7.0

11.6 9.46.7

5.0

3.1

3.1 2.5

1.3

0.9

0.7

12.59.8

5.9

3.2

1.8

39.1

35.0

26.1

18.7

12.6

0

50

100

150

200

250

300

$0

$10

$20

$30

$40

$50

$60

$70

2014 2015 2016 Committed 2017 Committed 2018 Committed

Historic and Contracted Floater Spend by Generation

6th gen+ 5th gen4th gen 3rd gen-Committed Rig Count (RHS) 2016 Capex Level Rig Count (RHS)*

-29%

Note: excludes owner-operated rigs, assumes all non-published dayrates are based on the average other contracted rigs dayrates: 3rd gen-$340k/d, 4th gen-400k/d, 5th gen-475k/d, 6th gen-520k/d*The rig count if 2016 capex levels are maintained and rigs are signed at $250k/d to reach this level 9

By 2017 Drilling Contracts Spend Reduces By 50%, Allowing Operators to Reset New Project Costs

-10%

-25%

-33%

Cape

x on

Flo

atin

g Ri

gs, $

B

Floa

ting

Rig

Coun

t

Analysts Predict Demand Recovery in 2018

0

50

100

150

200

250

300

350

400

2012 2013 2014 2015 2016 2017 2018 2019 2020

Analyst Projected Active Floating Rig Count

Historic Analyst 1 Analyst 2 Analyst 3 Base Analyst 3 Bull Analyst 4 Flat 2016 Spend

10Analysts include: Evercore ISI, Fearnley’s, Morgan Stanley, Wells Fargo, PACD

Recovery Dependent on Pace of Demand and Removal of Excess Capacity

8Contracted vs Available Rigs by Generation

Contracted 6th gen

Contracted 5th gen

Contracted Below 5th gen

Uncontracted 6th gen

Uncontracted 5th gen

Uncontracted Below 5th gen

Expected Cold Stacking/Scrapping

Demand, ranged (source: Analyst Range)

2016 2017 2018 2019 2020

Cold Stacked/Scrapped

2016 2017 2018 2019 2020High Demand Range -19% -5% 12% 13% 10%

Mid Demand -21% -8% 10% 10% 9%Low Demand Range -24% -12% 7% 7% 8% 11

Source: IHS-Petrodata, PACD estimates, stylized analyst range

Undelivered Newbuilds

8Contracted vs Available Rigs by Generation

Contracted 6th gen

Contracted 5th gen

Contracted Below 5th gen

Demand, ranged (source: Analyst Range)

2016 2017 2018 2019 2020

Pace of Fixtures Projected to Pick Up from Late 2017 to Mid 2019

12Source: IHS-Petrodata, PACD estimates, stylized analyst range

Uncontracted 6th gen

Uncontracted 5th gen

Uncontracted Below 5th gen

Expected Cold Stacking/Scrapping

Undelivered Newbuilds

Recovery Timeframe late 2017 – Mid 2019

Normal High Spec Utilization is Between 90%-100%, Current Utilization is Unprecedented

Source: IHS-Petrodata

Floater Fleet Utilization

40%

50%

60%

70%

80%

90%

100%

1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016

Utilization 0-10 years Utilization 10-20 years Utilization 20-30 years Utilization >30 years

13

0

50

100

150

200

250

300

350

400

450

500

70% 80% 90% 100%

Source: RS Platou, PACD estimates

Floater Utilization vs 4th Gen Dayrates

Utilization

$ k/

Day

Q1 94

Q1 03

Q3 07

Historic Data Shows, When Marketed Utilization is 88%+, Dayrates Begin Increasing

14

Q3 97

8Contracted vs Available Rigs by Generation

Contracted 6th gen

Contracted 5th gen

Contracted Below 5th gen

Demand, ranged (source: Analyst Range)2016 2017 2018 2019 2020

Positive Pricing Pressure Could Occur as Early as Late 2017 in a High Demand Scenario

Recovery Timeframe late 2017 – Mid 2019

15Source: IHS-Petrodata, PACD estimates, stylized analyst range; Marketed utilization of 88% excludes undelivered newbuilds

Uncontracted 6th gen

Uncontracted 5th gen

Uncontracted Below 5th gen

Undelivered Newbuilds

# 88% marketed utilization

1 32

Mid Demand Low DemandHigh Demand

Because We See a Recovery Within the Next 3 Years for 6th/7th

Gens, Smart Stacking is More Economic than Cold Stacking

Smart Stack

𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷 𝐷𝐷𝐷𝐷 𝑈𝑈𝑈𝑈𝐷𝐷𝐷𝐷𝑈𝑈𝐷𝐷𝑈𝑈 𝑎𝑎𝐷𝐷𝑎𝑎 𝑅𝑅𝐷𝐷𝑎𝑎𝐷𝐷𝑈𝑈𝐷𝐷𝑅𝑅𝑎𝑎𝑈𝑈𝐷𝐷𝑈𝑈𝐷𝐷 𝐶𝐶𝑈𝑈𝐶𝐶𝑈𝑈 𝑈𝑈𝐷𝐷 𝐷𝐷𝑎𝑎𝐷𝐷𝑒 𝑈𝑈𝑈𝑈𝑈𝑈𝐷𝐷𝑈𝑈𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷 𝐷𝐷𝐷𝐷 𝑅𝑅𝐷𝐷𝑈𝑈𝐷𝐷𝐷𝐷𝑅𝑅𝐷𝐷𝐷𝐷𝐷𝐷𝑅𝑅 𝑂𝑂𝑈𝑈𝐷𝐷𝐷𝐷𝑎𝑎𝑈𝑈𝐷𝐷𝐷𝐷𝑅𝑅 𝐷𝐷𝑎𝑎𝐷𝐷𝐷𝐷𝐷𝐷 𝐶𝐶𝑈𝑈𝐶𝐶𝑈𝑈 𝑈𝑈𝐷𝐷 𝐷𝐷𝑎𝑎𝐷𝐷𝑒 𝑈𝑈𝑈𝑈𝑈𝑈𝐷𝐷𝑈𝑈𝐷𝐷 = Number of Days off contract

prefer to smart stack

30k/d Opex (crew, fuel, insurance, fees, port dues…)

No upfront costs

Avoids significant reactivation costs and risks

Approx. 90 days to reactivate rig

More marketable rig makes it more likely to go back to work sooner than cold stacked rigs

Option to raft rigs could significantly decrease opex

Cold Stack

12k/d Opex (crew, fuel, insurance, fees, port dues…)

Significant upfront costs

Substantial unknown reactivation costs (market estimates range from $5m-$100m)

For each $1m in reactivation cost indifference point is pushed out 2 months

Approx. 150 days to reactivate rig

16Source: PACD estimates