2014-11-13_floater attrition forecast - d. gacicia

People. Ideas. Success.

Guggenheim Securities, LLC Oilfield Services, Offshore Contract Drillers & Capital Equipment

November 13, 2014

Floater Attrition Forecast: A Potential Inflection Point

Darren Gacicia

(212) 293-3054

[email protected]

GUGGENHEIM SECURITIES, LLC See pages 43 - 44 for analyst certification and important disclosures.

This report is intended for eric.w.loyet@

guggenheimpartners.com

at Guggenheim

. Unauthorized distribution of this report is prohibited.

Floater Attrition May Be a Potential Positive Catalyst for the Group Floater Market Forecast: Introduces Rig Attrition, Flat Demand, Market Utilization Bottoming in Low 90s %, & Scenarios for Upside. We are recalibrating our

floater market assumptions, forecasting that 58 total floaters leave the market by the end of 2016 (70 by 2018, pgs. 3-6), versus no retirements previously, and assume a

flat demand forecast amid limited visibility, versus demand growth previously. Limited slackening of the floater market to 90+% marketed utilization under a flat demand

outlook, although not a clear bullish signal, suggests a better outcome than the current market forecasts and more stable dayrates. In our view, announcements of rig

stacking and retirement will mark a bullish shift in the sentiment around floater market balances and likely a bottom in offshore driller shares. Under a flat forecast for

contracted rigs (currently 280, pg. 12) and our rig attrition forecast, utilization of marketed rigs falls from a current ~94% to ~92% at the end of 2016 (pg. 3), as attrition

largely offsets the arrival of newbuilds. Given plausible scenarios for low single digit (2.5%) demand growth and potential for delays or cancellations of Brazilian-built

newbuilds, the market may tighten and investor sentiment could shift quickly. We believe the stocks are likely near bottom and range-bound into year-end, as negative

investor sentiment reigns, but patient investors should build positions at current levels (see favored stocks below). If rig attrition trims supply, upstream budgets surprise

(better rig demand growth), and the oil outlook becomes more balanced (political/fundamental reasons), offshore driller shares may outperform in 2015.

Flat Floater Demand Forecast Conservative vs. Recent History. Firm contracted demand through 2015 for development work (pg. 21), a fall in exploration activity back

to historical averages (pg. 20), and limited near-term visibility around capital budgets supports a flat 2015 demand assumption. No growth beyond 2015 may prove

conservative versus historical trends. Historically, development drilling growth has been resilient through commodity volatility, as offshore basins remain important for new

source production. Our most recent demand forecast (pg. 14-16) must be revisited, as high growth, project-by-project data from consultant sources must better factor the

outcomes of a cautious capital budgeting cycle in addition to our probability weighting (“Second Derivative” Leads Drivers, Despite Near-Term Dayrate Headwinds,

6/2/14). Although 3Q14 industry comments temper offshore spending expectations and suggest project delays, favorable marginal cost economics for a large number of

projects (pg. 18) and the push for standardization indicate oil companies look to press forward with projects.

Two Plausible Bullish Scenarios May Turn the Market in 2H15/1H16 (pg. 3):

Growth Can Change Dynamics Quickly. A low single digit demand growth forecast (2.5%/year) remains plausible (pg. 3). Even small growth, in addition to rig attrition,

may tighten the market via an inflection in utilization, and turn market sentiment. For the last ten years, the number of contracted floaters grew at a 6-7% CAGR (pg.

19), largely driven by the search for larger scale reserve replacement and production growth. The advent of unconventional plays has not derailed the trend, but the

quest to lower breakeven costs has slowed activity and started the industry up the learning curve within the deepwater frontier, toward an establishment of best

practices and standardization. A flat growth forecast works contrary to historical trends and the need for oil companies to generate cash from offshore assets, if a

better ROIC, production growth, and dividend sustainability remain IOC goals.

Brazilian Floater Delays May Significantly Change Supply Dynamics. If the 28 newbuilds scheduled for construction in Brazil (9 by 4Q16) are delayed or do not come

to market, marketed utilization may improve dramatically (pg. 10). Only 13 of these rigs are under construction at shipyards with participation from established players

(Keppel FELS & Jurong). The remaining shipyards are under construction themselves. Probability favors Brazil rig delays/cancellations as a tailwind.

Drawing the Line in the Fleet: Multi-Factor Rating Methodology. We have constructed a proprietary multi-factor model to assess the floater fleet by capability, age, and

free date in order to create a ranking for each rig, retirement list and schedule (pg. 7). From the analysis we have derived a list of 71 rigs set to leave the market (pg. 9),

most in addition to those already idle/not contracted (47, pg. 12). We see 4Q14 as a significant attrition period, with 13 rigs leaving the market, of which 6 are currently

uncontracted. In our view, our retired rigs will leave the marketed fleet and drive marketed utilization higher, but may be counted in the fleet until scrapped, lowering the

optics of total fleet utilization despite no longer competing. Several offshore drillers have begun to announce rigs as stacked, retiring, or held for sale, while others have

suggested retirements are to follow. We see strategic reasons for offshore drillers to be coy in identifying rigs until they formally leave the market, but maintain the view

that rig retirements are on the horizon and will serve as positive catalysts for sentiment. We believe RIG (BUY, $27.08), DO (BUY, $35.84), and ESV (Neutral, $39.27) will

see the most retirements (pg. 8), but these are largely factored into our models and appear to be discounted in their share prices.

Favored Offshore Drillers. In our coverage, we believe SDRL (BUY, $21.27) and RIG (BUY, $27.08) have the most leverage to the more bullish offshore driller outlook,

especially if capital markets remain open to financing newbuild deliveries and fleet renewal, respectively. Post PGN spin and recent announcements, NE (BUY, $21.54)

continues to screen better with a solid cash flow story with catalysts around the MLP and share repurchase prospects. In the small/mid-cap names, we continue to like

PACD (BUY, $6.87) and ATW (BUY, $35.52) for quality of fleets, longer-term growth stories, and emerging payout strategies.

Guggenheim Securities, LLC | 212-293-3054 | guggenheimsecurities.com

Oilfield Services, Offshore Contract Drillers & Capital Equipment PAGE 2

https://guggenheimsecurities.bluematrix.com/docs/pdf/d71f2ec1-ec23-4ad9-93b7-4b80e48caecf.pdf



(13)

(7) (7)

(3)(4)

(7)

(3)(4) (4)

(2) (2) (1)(3)

-

(2) (2)

-

9

7

5 4

9

1

5

2

5

1

4

1 -

1 - - -

94% 94%

95%94%

93%

95%

94%

95%

94%

95%

94% 94%

95%95%

95%

96% 96%

91%

92%

93%

94%

95%

96%

97%

-16

-14

-12

-10

-8

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0

2

4

6

8

10

12

4Q

14

1Q

15

2Q

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3Q

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2Q

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3Q

16

4Q

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1Q

17

2Q

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3Q

17

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17

1Q

18

2Q

18

3Q

18

4Q

18

Mar

kete

d U

tiliz

atio

n %

Att

riti

on

/ N

ewb

uild

Cou

nt

Attrition Newbuilds, ex Brazil Marketed Utilization, ex Brazil

(13)

(7) (7)

(3)(4)

(7)

(3)(4) (4)

(2) (2) (1) (3)

-

(2) (2)

-

9 7 6

4

10

2

5

6 7

3

5

3 2 2 2 2

3

94% 94%94%

94%

92%

94%

93%

92%

92%91%

90%

90%

90%89%

89%

89%89%

85%

86%

87%

88%

89%

90%

91%

92%

93%

94%

95%

-16

-14

-12

-10

-8

-6

-4

-2

0

2

4

6

8

10

12

4Q1

4

1Q15

2Q1

5

3Q15

4Q1

5

1Q16

2Q1

6

3Q16

4Q1

6

1Q17

2Q1

7

3Q17

4Q1

7

1Q18

2Q1

8

3Q18

4Q1

8

Mar

kete

d U

tiliz

atio

n %

Att

riti

on

/ N

ewb

uild

Cou

nt

Attrition Newbuilds Marketed Utilization

78%79%80%81%82%83%84%85%86%87%88%89%90%91%92%93%94%95%96%97%98%99%

100%

1Q96

3Q96

1Q97

3Q97

1Q98

3Q98

1Q99

3Q99

1Q00

3Q00

1Q01

3Q01

1Q02

3Q02

1Q03

3Q03

1Q04

3Q04

1Q05

3Q05

1Q06

3Q06

1Q07

3Q07

1Q08

3Q08

1Q09

3Q09

1Q10

3Q10

1Q11

3Q11

1Q12

3Q12

1Q13

3Q13

1Q14

3Q14

1Q15

3Q15

1Q16

3Q16

1Q17

3Q17

1Q18

3Q18

Mar

kete

d U

tiliz

atio

n %

2.5% Growth 2.5% Decline Marketed Utilization - No Growth

Fleet Newbuilds (ex. Brazil)/ Attrition vs. Utilization

Attrition Forecast, Demand Growth & Brazil Rig Delays Tighten Market

78%79%80%81%82%83%84%85%86%87%88%89%90%91%92%93%94%95%96%97%98%99%

100%

1Q

96

3Q

96

1Q

97

3Q

97

1Q

98

3Q

98

1Q

99

3Q

99

1Q

00

3Q

00

1Q

01

3Q

01

1Q

02

3Q

02

1Q

03

3Q

03

1Q

04

3Q

04

1Q

05

3Q

05

1Q

06

3Q

06

1Q

07

3Q

07

1Q

08

3Q

08

1Q

09

3Q

09

1Q

10

3Q

10

1Q

11

3Q

11

1Q

12

3Q

12

1Q

13

3Q

13

1Q

14

3Q

14

1Q

15

3Q

15

1Q

16

3Q

16

1Q

17

3Q

17

1Q

18

3Q

18

Ma

rke

ted

Uti

liza

tio

n %

2.5% Growth 2.5% Decline Marketed Utilization - No Growth

Floater Marketed Utilization – Inc. Brazil Newbuilds Floater Marketed Utilization – Ex. Brazil NB

Fleet Newbuilds/Attrition vs. Utilization

Source: Guggenheim Securities, LLC, IHS-Petrodata; Note: All estimates are by Guggenheim Securities, LLC



Forecast of 60+ Incremental Rigs to Retire Through 2018

13

7

7

3

4

7

3

4 4

2 21

3

02 2

0

13

20

2730

34

4144

4852

5456 57

60 6062

64 64

0

10

20

30

40

50

60

70

0

2

4

6

8

10

12

14

4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18

Cu

mu

lati

ve F

loat

er A

ttri

tio

n

Qu

arte

rly

Flo

ater

Att

riti

on

Attrition Cumulative

Forecasted Floater Attrition

6 of the 13 rigs we see

exiting the market in 4Q14

are not contracted.

The majority of rigs will exit the market

in the near term, as market conditions

remain slack. In our view, retirements

will drive a change in the perceived

direction of market balances.

Source: Guggenheim Securities, LLC, IHS-Petrodata

Note: All estimates are by Guggenheim Securities, LLC

Note: We do not include rigs stacked or idle prior to 4Q14 in our incremental rig

retirement assumptions.



Drawing a Retirement Line on the Older, Lower Spec Fleet.

0.05 0.10 0.15 0.20 0.25 0.30 0.35 0.40 0.45 0.50 0.55 0.60 0.65 0.70 0.75 0.80 0.85 0.90 0.95 1.00

1970 1975 1980 1985 1990 1995 2000 2005 2010 2015

Per

cen

tile

Ran

k

Year in Service

3G

4G

5G

6G

Floater Fleet Percent Rank by Generation

We see the bottom quartile of

the floater fleet as ripe for

retirement as new rigs arrive,

the market remains

oversupplied, and higher spec.

5G/4G rigs compete for work.





Lower Deciles of the Fleet Screen Show Risk to 3G & 4G Rigs

43 40

29

11

3 - - - - -

-2

10

12

2

- - - - -

- -3

15

13

12

2 1 - -

-

4

26

29

40 41 42 43

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

1 2 3 4 5 6 7 8 9 10

% o

f R

igs

by

Ge

ne

rati

on

Decile

3G 4G 5G 6G

Floater Fleet Percent Rank by Deciles

Need to stretch retirements into

the bottom 3rd and 4th deciles to

begin retiring a meaningful

number of 4th and 5th

generation rigs.





Multi-Factor Rig Ranking Methodology

Our floater factor-weighting methodology ranks each rig against every rig in the floater universe. Each rig is percent

ranked against the universe on the below factors, with the overall ranking as an average of the category ranks.

Double counted

due to being

significantly

differentiating

factors that are

difficult/expensive

to change.

Rig Ranking Methodology

Source: Guggenheim Securities, LLC

Factor Description Weighting

Water Depth The rig's maximum operating water depth. A deeper depth ranks higher. Standard

Drilling Depth The rig's maximum drilling depth. A deeper depth ranks higher. Standard

VDL (Variable Deck Load) The variable deck load represents the carrying capacity of the rig. A greater capacity ranks higher.

Double

Derrick/Hook Load Maximum weight the derrick/mast and substructure can handle. A greater maximum load ranks higher.

Double

BOP Rams (Blowout Preventers) Total count of BOP rams onboard. BOP rams are designed to help prevent blowouts and are important for the safety of the crew, environment, and rig. More rams rank higher.

Double

DP (Dynamically Positioned) A dynamically positioned rig employs computerized thrusters to keep a rig positioned correctly at all times. Dynamically positioned is a binary measure with a DP system ranking positively.

Standard

Dual Activity A rig with two drilling packages to allow for greater efficiency. A binary measure with dual activity ranking positively.

Standard

Rebuild Credit is given to rigs that have been rebuilt. Standard

Generation Rig generation is based on the rig's initial delivery year. Newer generation rigs rank higher.

Standard

YIS (Year in Service) Year in service represents when a rig first began working. Newer rigs rank higher.

Standard



Rig Retirements by Offshore Driller



Manager Forecast Retirements

Transocean 20

Diamond Offshore 12

Ensco 6

Dolphin 4

Noble 3

Awilco Drilling 2

Paragon Offshore 2

PetroSaudi 2

Saipem 2

Songa Opus Offshore Drilling 2

Aban Offshore 1

Arktikmor 1

Atwood 1

Caspian Drilling 1

Crosco 1

Deepwater Drilling & Services 1

Frigstad Offshore 1

Gryphon Energy 1

Japan Drilling 1

Jet Drilling 1

Maersk Drilling 1

Odfjell Drilling 1

QGOG Constellation 1

Schahin 1

Songa Offshore 1

Stena 1

Total 71



List of Forecasted Retirement Rigs: Dominated by Large Players

We expect a large

number of

retirements will

come from large

established offshore

drillers, like RIG &

DO, in-line with

recent

industry/company

commentary.

Source: Guggenheim

Securities, LLC, IHS-

Petrodata

Note: All estimates are

by Guggenheim

Securities, LLC

Rig Name Manager Market Category Generation Rig Status Contract Status Last/Scheduled Yard Survey Due Free Date

1 Aban Ice Aban Offshore Drillship <=3000 3G Drilling Contracted -- Nov-18 Nov-16

2 Deep Venture Arktikmor Drillship 5001-7500 3G Yard Not Contracted Jun-14 Apr-18 Oct-14

3 Atwood Hunter Atwood Semi 3001-5000 3G Drilling Contracted Jan-14 Aug-17 Oct-14

4 WilHunter Awilco Drilling Semi Harsh Standard 3G Drilling Contracted Dec-15 -- Feb-16

5 WilPhoenix Awilco Drilling Semi Harsh Standard 3G Drilling Contracted May-16 -- Sep-17

6 Istiglal Caspian Drilling Semi <=3000 4G Drilling Contracted -- -- Jan-23

7 Zagreb 1 Crosco Semi <=3000 3G Warm stacked Not Contracted -- -- Sep-14

8 Paragon MDS1 Deepwater Drilling & Services Drillship <=3000 3G Drilling Contracted Dec-14 -- May-15

9 Ocean Vanguard Diamond Offshore Semi Harsh Standard 3G Warm stacked Not Contracted -- -- Jun-14

10 Ocean Concord Diamond Offshore Semi <=3000 3G Standby Not Contracted -- -- Nov-14

11 Ocean Yatzy Diamond Offshore Semi 3001-5000 4G Standby Not Contracted May-14 -- Nov-14

12 Ocean Star Diamond Offshore Semi 5001-7500 3G En route Not Contracted -- -- Nov-14

13 Ocean Princess Diamond Offshore Semi Harsh Standard 3G Drilling Contracted -- -- Dec-14

14 Ocean Worker Diamond Offshore Semi 3001-5000 3G Drilling Contracted -- -- Feb-15

15 Ocean Yorktown Diamond Offshore Semi <=3000 3G Drilling Contracted -- -- Mar-15

16 Ocean Winner Diamond Offshore Semi 3001-5000 3G Drilling Contracted -- -- Mar-15

17 Ocean Nomad Diamond Offshore Semi Harsh Standard 3G Drilling Contracted -- -- Aug-15

18 Ocean Ambassador Diamond Offshore Semi <=3000 3G Drilling Contracted -- Jul-18 Mar-16

19 Ocean Patriot Diamond Offshore Semi Harsh Standard 3G Moving to location Contracted Aug-14 -- Oct-17

20 Ocean Lexington Diamond Offshore Semi <=3000 3G Drilling Contracted Feb-15 -- Apr-18

21 Borgny Dolphin Dolphin Semi Harsh Standard 3G Warm stacked Not Contracted -- -- Dec-14

22 Byford Dolphin Dolphin Semi Harsh Standard 3G Drilling Contracted Jan-15 Jan-15 Apr-16

23 Bideford Dolphin Dolphin Semi Harsh High Spec 3G Drilling Contracted Apr-14 Jun-19 Jan-17

24 Borgland Dolphin Dolphin Semi Harsh High Spec 5G Yard Contracted Sep-14 Oct-19 Oct-17

25 ENSCO 5001 Ensco Semi 3001-5000 3G Yard Contracted Aug-14 Jun-14 Feb-15

26 ENSCO 6004 Ensco Semi 5001-7500 5G Drilling Contracted Sep-14 May-19 Oct-16

27 ENSCO 5004 Ensco Semi <=3000 3G Drilling Contracted Jan-14 Aug-16 Dec-16

28 ENSCO 6003 Ensco Semi 5001-7500 5G Drilling Contracted Jan-14 Sep-16 Jan-17

29 ENSCO 6001 Ensco Semi 5001-7500 5G Yard Contracted May-14 Dec-15 Jun-18

30 ENSCO 6002 Ensco Semi 5001-7500 5G Drilling Contracted Apr-14 Feb-16 Jul-18

31 Kan Tan IV Frigstad Offshore Semi <=3000 3G Drilling Contracted -- Apr-17 Dec-14

32 Peregrine I Gryphon Energy Drillship 5001-7500 3G Yard Not Contracted -- -- Dec-14

33 Hakuryu-5 Japan Drilling Semi <=3000 3G Hot stacked Not Contracted Apr-14 Sep-17 Sep-14

34 Energy Searcher Jet Drilling Drillship <=3000 3G Drilling Contracted Jan-14 May-16 Apr-15

35 Nanhai VI Maersk Drilling Semi <=3000 3G Drilling Contracted Jun-15 Dec-15 Oct-15

36 Noble Driller Noble Semi 3001-5000 3G Drilling Contracted -- May-19 Nov-14

37 Noble Jim Thompson Noble Semi 5001-7500 5G Drilling Contracted Dec-14 Sep-14 May-16

38 Noble Discoverer Noble Drillship <=3000 3G Standby Contracted Feb-14 Feb-19 Dec-16

39 Deepsea Bergen Odfjell Drilling Semi Harsh Standard 3G Drilling Contracted -- Aug-15 Jun-17

40 Paragon MSS1 Paragon Offshore Semi Harsh Standard 3G Drilling Contracted -- -- Jun-15

41 Paragon MSS2 Paragon Offshore Semi 3001-5000 3G Drilling Contracted Nov-14 -- Oct-15

42 PetroSaudi Discoverer PetroSaudi Drillship <=3000 3G Warm stacked Not Contracted Sep-14 -- Sep-14

43 PetroSaudi Saturn PetroSaudi Drillship 3001-5000 3G Drilling Contracted -- -- Nov-17

44 Atlantic Star QGOG Constellation Semi <=3000 3G Drilling Contracted -- Jan-16 Jul-18

45 Scarabeo 3 Saipem Semi <=3000 3G Drilling Contracted -- -- May-15

46 Scarabeo 4 Saipem Semi <=3000 3G Drilling Contracted -- -- Oct-15

47 SC Lancer Schahin Drillship 3001-5000 3G Drilling Contracted -- -- Aug-16

48 Songa Trym Songa Offshore Semi Harsh Standard 3G Moving to location Contracted -- -- Mar-16

49 Songa Venus Songa Opus Offshore Drilling Semi <=3000 3G Warm stacked Not Contracted Apr-15 -- Jul-14

50 Songa Mercur Songa Opus Offshore Drilling Semi <=3000 4G Standby Contracted Jun-15 -- Nov-14

51 Stena Clyde Stena Semi <=3000 3G Drilling Contracted Dec-14 -- Mar-15

52 M.G. Hulme, Jr. Transocean Semi 3001-5000 3G Hot stacked Contracted May-14 Aug-15 Aug-14

53 Sedco 707 Transocean Semi 5001-7500 3G Drilling Contracted -- -- Nov-14

54 GSF Rig 140 Transocean Semi <=3000 3G Drilling Contracted -- Oct-18 Dec-14

55 Transocean Legend Transocean Semi 3001-5000 3G Drilling Contracted Feb-14 -- Jan-15

56 GSF Arctic III Transocean Semi Harsh Standard 3G Moving to location Contracted Oct-14 Feb-15 Feb-15

57 Transocean Marianas Transocean Semi 5001-7500 5G Drilling Contracted -- -- Apr-15

58 GSF Rig 135 Transocean Semi <=3000 3G Drilling Contracted -- Jun-18 May-15

59 Transocean Prospect Transocean Semi Harsh Standard 3G Drilling Contracted -- -- May-15

60 GSF Grand Banks Transocean Semi Harsh Standard 3G WOW Contracted -- Mar-19 Sep-15

61 Actinia Transocean Semi <=3000 3G Drilling Contracted Jan-15 Oct-17 Sep-15

62 Transocean Amirante Transocean Semi 3001-5000 3G Yard Contracted Jun-14 -- Dec-15

63 Sedco 702 Transocean Semi 5001-7500 3G Drilling Contracted Mar-15 -- Jan-16

64 Sedco 711 Transocean Semi Harsh Standard 3G Drilling Contracted -- -- Jan-16

65 Sedco 704 Transocean Semi Harsh Standard 3G Drilling Contracted -- -- Jan-16

66 Sedco 714 Transocean Semi Harsh Standard 3G Drilling Contracted Jun-14 -- Feb-16

67 Transocean John Shaw Transocean Semi Harsh Standard 3G Drilling Contracted Jan-14 -- Apr-16

68 Transocean Winner Transocean Semi Harsh Standard 3G Drilling Contracted -- -- Jul-16

69 Transocean Driller Transocean Semi <=3000 4G Drilling Contracted Jul-15 -- Jul-16

70 Sedco 706 Transocean Semi 5001-7500 3G Drilling Contracted May-14 -- Sep-16

71 Polar Pioneer Transocean Semi <=3000 4G Yard Contracted Jul-14 -- Jun-17



PBR Sponsored & Brazil Built Newbuilds

Manager Rig Name Rig Type

Water

Depth

Drilling

Depth

North Sea

Capable Shipyard Country Build Cost

Drilling

Package BOP Cementing Order Date

Delivery

Date Operator

Contract

Duration

1 Etesco / OAS Cassino Drillship 10,000 35,000 N Ecovix-Engevix Brazil 778 SLB Mar-12 Jul-16 Petrobras 15.2

2 Etesco / OAS Curumim Drillship 10,000 35,000 N Ecovix-Engevix Brazil 778 SLB Mar-12 Mar-17 Petrobras 15.9

3 Etesco / OAS Salinas Drillship 10,000 35,000 N Ecovix-Engevix Brazil 778 SLB Mar-12 Nov-17 Petrobras 15.9

4 Etesco / OAS Itapema Drillship 10,000 35,000 N Estaleiro Enseada do Paraguacu Brazil 799 HAL Apr-12 May-19 Petrobras 15.8

5 Etesco / OAS Comandatuba Drillship 10,000 35,000 N Estaleiro Enseada do Paraguacu Brazil 799 HAL Apr-12 Jan-20 Petrobras 15.6

6 Not known Grumari Drillship 10,000 N Estaleiro Atlantico Sul Brazil 662 NOV BHI Jun-11 Jul-16 Petrobras 15.3

7 Not known Ipanema Drillship 10,000 N Estaleiro Atlantico Sul Brazil 662 NOV BHI Jun-11 Mar-17 Petrobras 15.3

8 Not known Leblon Drillship 10,000 N Estaleiro Atlantico Sul Brazil 662 NOV BHI Jun-11 Nov-17 Petrobras 15.3

9 Not known Leme Drillship 10,000 N Estaleiro Atlantico Sul Brazil 662 NOV BHI Jun-11 Jul-18 Petrobras 15.3

10 Not known Marambaia Drillship 10,000 N Estaleiro Atlantico Sul Brazil 662 NOV BHI Feb-11 Dec-18 Petrobras 15.6

11 Odebrecht Ondina Drillship 10,000 35,000 N Estaleiro Enseada do Paraguacu Japan 799 HAL Dec-12 Jul-16 Petrobras 15.1

12 Odebrecht Pituba Drillship 10,000 35,000 N Estaleiro Enseada do Paraguacu Brazil 799 HAL Apr-12 May-17 Petrobras 15.1

13 Odebrecht Boipeba Drillship 10,000 35,000 N Estaleiro Enseada do Paraguacu Brazil 799 NOV HAL Apr-12 Jan-18 Petrobras 15.6

14 Odebrecht Interlagos Drillship 10,000 35,000 N Estaleiro Enseada do Paraguacu Brazil 799 HAL Apr-12 Sep-18 Petrobras 15.7

15 Odebrecht Botinas Semisubmersible 10,000 32,808 N BRASFELS Brazil 832 HAL Mar-12 Aug-19 Petrobras 15.4

16 Odfjell Galvao Deepsea Guarapari Drillship 10,000 32,808 N Estaleiro Jurong Aracruz Singapore 792 CAM BHI Feb-12 Jul-16 Petrobras 15.0

17 Odfjell Galvao Deepsea Itaoca Drillship 10,000 40,000 N Estaleiro Jurong Aracruz Brazil 792 CAM BHI Mar-12 Aug-17 Petrobras 15.4

18 Odfjell Galvao Deepsea Siri Drillship 10,000 32,808 N Estaleiro Jurong Aracruz Brazil 792 CAM BHI Mar-12 Dec-18 Petrobras 16.1

19 Petrobras Arpoador Drillship 10,000 32,808 N Estaleiro Jurong Aracruz Singapore 792 NOV BHI Feb-11 Jun-15 Petrobras 15.6

20 Petrobras Copacabana Drillship 10,000 N Estaleiro Atlantico Sul Brazil 662 NOV BHI Jun-11 Feb-16 Petrobras 15.1

21 Petroserv Frade Semisubmersible 10,000 32,808 N BRASFELS Brazil 832 HAL Mar-12 Dec-16 Petrobras 15.4

22 Petroserv Portogalo Semisubmersible 10,000 32,808 N BRASFELS Brazil 832 HAL Mar-12 Apr-18 Petrobras 15.4

23 Queiroz Galvao Urca Semisubmersible 10,000 32,808 N BRASFELS Brazil HAL Dec-11 Dec-15 Petrobras 15.6

24 Queiroz Galvao Bracuhy Semisubmersible 10,000 32,808 N BRASFELS Brazil 832 HAL Mar-12 Aug-17 Petrobras 15.4

25 Queiroz Galvao Mangaratiba Semisubmersible 10,000 32,808 N BRASFELS Brazil 832 HAL Mar-12 Dec-18 Petrobras 15.4

26 Seadrill Camburi Drillship 10,000 32,808 N Estaleiro Jurong Aracruz Brazil 792 ASKO AKSO BHI Mar-12 Dec-16 Petrobras 15.4

27 Seadrill Itaunas Drillship 10,000 32,808 N Estaleiro Jurong Aracruz Brazil 792 ASKO AKSO BHI Mar-12 Apr-18 Petrobras 16.1

28 Seadrill Sahy Drillship 10,000 32,808 N Estaleiro Jurong Aracruz Brazil 792 ASKO AKSO BHI Mar-12 Aug-19 Petrobras 16.1

We assume that rigs built by

established offshore drillers do

come to market on time, which

may prove an aggressive

assumption if final construction

takes place at Brazilian yards.

The yards building rigs in Brazil are

largely still under construction. Aside

from Jurong and Keppel FELS, the

yards are also inexperienced in

building rigs.

Source: Guggenheim Securities, LLC, IHS-Petrodata; Note: All estimates are by Guggenheim Securities, LLC



Demand Calibration vs. Oil Prices



Current Fleet Complexion: Offshore Drillers


OPERATOR CONTRACTED FLEET NOT CONTRACTED FLEET NEWBUILDS

Drilli

ng

En r

oute

Sta

ndby

Movin

g T

o L

ocation

WO

W

Yard

Hot

sta

cked

Warm

sta

cked

TO

TA

L C

ON

TR

AC

TE

D

TO

TA

L U

TIL

IZA

TIO

N

MA

RK

ET

ED

UT

ILIZ

AT

ION

Hot

sta

cked

Warm

sta

cked

En r

oute

Sta

ndby

Movin

g T

o L

ocation

WO

W

Yard

Under

constr

uction

On o

rder

Accepta

nce t

esting

Out

of

serv

ice

Cold

sta

cked

TO

TA

L N

OT

CO

NT

RA

CT

ED

Mark

ete

d -

NC

Not

Mark

ete

d -

NC

Contr

acte

d

Not

Contr

acte

d

TO

TA

L N

EW

BU

ILD

S

On o

rder

TO

TA

L R

IGS

Transocean 46 1 1 1 - 4 1 - 55 75% 90% 2 - - - - - 3 - - - - 13 18 6 12 5 2 7 5 80

Diamond Offshore 19 - - - - 2 2 - 23 68% 88% - - 1 2 - - 2 - - - - 6 11 3 8 4 - 4 - 38

Ensco 19 - - - - 3 - - 22 85% 96% - 1 - - - - - - - - - 3 4 1 3 2 1 3 - 29

Seadrill 15 2 1 2 - 1 - - 21 95% 95% - 1 - - - - - - - - - - 1 1 - 4 6 10 3 32

Noble 13 - 1 - - 1 1 - 17 85% 85% 1 - - - - - 1 - - - - 1 3 3 - - - - - 20

Ocean Rig 8 - - - - 1 - - 9 100% 100% - - - - - - - - - - - - - - - 1 3 4 3 13

Saipem 8 - - - - - - 1 9 100% 100% - - - - - - - - - - - - - - - - - - - 9

Maersk Drilling 7 - - - - - - - 8 100% 100% - - - - - - - - - - - - - - - - 1 1 - 9

Atwood 6 1 - - - - - - 7 88% 100% - - - - - - - - - - - 1 1 - 1 - 2 2 - 10

Dolphin (Fred Olsen) 6 - - - - 1 - - 7 88% 100% - - - - - - - - - - - 1 1 - 1 1 - 1 - 9

Stena 5 - 1 - - 1 - - 7 100% 100% - - - - - - - - - - - - - - - - 2 2 - 9

Odfjell Drilling 6 1 - - - - - - 7 100% 100% - - - - - - - - - - - - - - - - 1 1 - 8

Pacific Drilling 6 - - - - - - - 6 100% 100% - - - - - - - - - - - - - - - - 2 2 - 8

Schahin 6 - - - - - - - 6 100% 100% - - - - - - - - - - - - - - - - - - - 6

Paragon Offshore 5 - - - - - - - 5 71% 100% - - - - - - - - - - - 2 2 - 2 - - - - 7

North Atlantic Drilling 3 - - 1 - - - - 4 100% 100% - - - - - - - - - - - - - - - 1 - 1 - 5

Songa Offshore 2 - - - - 1 - - 3 100% 100% - - - - - - - - - - - - - - - 4 - 4 - 7

Vantage Drilling 2 1 - - - - - - 3 100% 100% - - - - - - - - - - - - - - - - 3 3 - 6

Jet Drilling 2 - - - - - - - 2 100% 100% - - - - - - - - - - - - - - - - - - - 2

Awilco Drilling 2 - - - - - - - 2 100% 100% - - - - - - - - - - - - - - - - - - - 2

Rowan 1 1 - 1 - - - - 3 100% 100% - - - - - - - - - - - - - - - 1 - 1 - 4

Frigstad Offshore 1 - - - - - - - 1 100% 100% - - - - - - - - - - - - - - - - 2 2 - 3

Songa Opus Offshore Drilling - - - - - - - 1 1 50% 50% - 1 - - - - - - - - - - 1 1 - - - - - 2

Aban Offshore 1 - - - - - - - 1 100% 100% - - - - - - - - - - - - - - - - - - - 1

Deepwater Drilling & Services 1 - - - - - - - 1 100% 100% - - - - - - - - - - - - - - - - - - - 1

Essar Oilfields Services 1 - - - - - - - 1 100% 100% - - - - - - - - - - - - - - - - - - - 1

Other 1 - - - - - 1 - 2 150% 29% 1 3 - - - - 1 - - - - - 5 5 - 5 8 13 8 20

TOTAL COMPETITIVE 192 7 4 5 - 15 5 2 233 83% 92% 4 6 1 2 - - 7 - - - - 27 47 20 27 28 33 61 19 341

SPECULATORS --

Friede Goldman Offshore - - - - - - - - - -- -- - - - - - - - - - - - - - - - - 1 1 - 1

Keppel FELS - - - - - - - - - -- -- - - - - - - - - - - - - - - - - 1 1 - 1

PBR / BRAZIL --

Odebrecht 7 - - - - - - - 7 100% 100% - - - - - - - - - - - - - - - 5 - 5 4 12

QGOG Constellation 8 - - - - - - - 8 100% 100% - - - - - - - - - - - - - - - - - - - 8

Petrobras 4 - - - - - - - 4 100% 100% - - - - - - - - - - - - - - - 2 - 2 - 6

Odfjell Galvao - - - - - - - - - -- -- - - - - - - - - - - - - - - - 3 - 3 2 3

Etesco 1 - - - - 1 - - 2 100% 100% - - - - - - - - - - - - - - - - - - - 2

Etesco / OAS - - - - - - - - - -- -- - - - - - - - - - - - - - - - 5 - 5 5 5

Queiroz Galvao - - - - - - - - - -- -- - - - - - - - - - - - - - - - 4 - 4 1 4

NOC's --

COSL 8 - - - - - - 1 9 100% 100% - - - - - - - - - - - - - - - - 2 2 - 11

Petroserv 4 - - - - - - - 4 100% 100% - - - - - - - - - - - - - - - 2 - 2 1 6

IPC 3 - - - - - - - 3 100% 100% - - - - - - - - - - - - - - - - - - - 3

Caspian Drilling 2 - - - - - - - 2 100% 100% - - - - - - - - - - - - - - - - 1 1 - 3

Gazflot - - - - - - - 2 2 100% 100% - - - - - - - - - - - - - - - - - - - 2

ONGC 2 - - - - - - - 2 100% 100% - - - - - - - - - - - - - - - - - - - 2

KNOC - - - - - 1 - - 1 100% 100% - - - - - - - - - - - - - - - - 1 1 - 2

PetroSaudi 1 - - - - - - - 1 50% 50% - 1 - - - - - - - - - - 1 1 - - - - - 2

Sinopec 1 - - - - - - - 1 100% 100% - - - - - - - - - - - - - - - - - - - 1

KEPCO 1 - - - - - - - 1 100% 100% - - - - - - - - - - - - - - - - - - - 1

SOCAR - - - - - - - - - 0% -- - - - - - - - - - - 2 1 3 - 3 - - - - 3

North Sea Rigs - - - - - - - - - -- -- - - - - - - - - - - - - - - - - 2 2 - 2

Arktikmor - - - - - - - - - 0% 0% - - - - - - 1 - - - - - 1 1 - - - - - 1

TOTAL NOC 42 - - - - 2 - 3 47 90% 96% - 1 - - - - 1 - - - 2 1 5 2 3 21 8 29 13 81

TOTAL FLEET 234 7 4 5 - 17 5 5 280 84% 93% 4 7 1 2 - - 8 - - - 2 28 52 22 30 49 41 90 32 422

NO

C /

NO

C S

po

nso

red

/ S

pecu

lato

rsC

om

peti

tive O

ffsh

ore

Dri

llers



Current Fleet Complexion: Operator & Geography


OPERATOR Ind

ian

Ocean

SE

Asia

W A

fric

a

Far

East

US

GO

M

Au

s/N

Z

Med

/Bla

ck S

ea

NW

Eu

rop

e

Casp

ian

S A

meri

ca

Mexic

o

C A

meri

ca

Can

ad

a E

ast

Mid

dle

East

TO

TA

L M

AR

KE

T

Petrobras - - - - 1 - - - - 59 - - - - 60

Statoil 1 - 1 - 1 - - 14 - - - - 1 - 18

BP - - 3 - 8 - 1 2 3 - - - - - 17

Shell - 2 2 - 8 1 - 2 - 1 - - - - 16

Total - - 13 - - - - 2 - - - - - - 15

ONGC 9 - - - - - - - - - - - - - 9

Chevron - 1 2 - 4 2 - - - - - - - - 9

CNOOC - - 1 7 - - - - - - - - - - 8

Eni - 1 3 - 1 1 1 1 - - - - - - 8

Anadarko 1 - 1 - 5 - - - - - - - - - 7

ExxonMobil - - 3 - 1 1 1 1 - - - - - - 7

PEMEX - - - - - - - - - - 6 - - - 6

ConocoPhillips - 1 1 - - 1 - 1 - - - - - - 4

Apache - - - - 1 1 - 1 - - - - - - 3

Murphy - 1 - - 2 - - - - - - - - - 3

Rig Management Nor. - - - - - - - 3 - - - - - - 3

LLOG - - - - 3 - - - - - - - - - 3

Woodside - - - - - 2 - - - - - - - - 2

Hess - - - - 1 - - 1 - - - - - - 2

Marathon - - - - 1 - - 1 - - - - - - 2

BG - - - - - - - - - - - 1 - - 1

Nexen - - - - - - - 2 - - - - - - 2

PetroSA - - 2 - - - - - - - - - - - 2

Gazflot - - - 2 - - - - - - - - - - 2

Freeport-McMoRan Oil & Gas - - - - 2 - - - - - - - - - 2

Tullow Oil - - 2 - - - - - - - - - - - 2

Talisman Sinopec - - - - - - - 2 - - - - - - 2

Other 4 10 11 2 12 2 5 10 1 4 - - 3 1 65

TOTAL MARKET 15 16 45 11 51 11 8 43 4 64 6 1 4 1 280



Previous Forecast: Consultant Raw Forecast Growth Aggressive vs. Oil Outlook

Unadjusted development activity

data sets create unrealistic

expectations for the industry to

rapidly ramp project execution.

0

20

40

60

80

100

120

140

160

19

90

19

91

19

92

19

93

19

94

19

95

19

96

19

97

19

98

19

99

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

20

10

20

11

20

12

20

13

20

14

20

15

20

16

20

17

20

18

20

19

20

20

Nu

mb

er o

f P

roje

cts

Source: IHS-Petrodata., Infield Systems, Guggenheim Securities, LLC - Note: All estimates by Guggenheim Securities, LLC

Projects History & Forecast

Ultra/Deepwater Well Counts History & Forecast Midwater Well Counts History & Forecast

Even our probability-weighted

demand growth assumptions may

prove too high if commodity

concerns curb spending. Our midwater forecast implies a

number of projects that are not

sanctioned at lower water depths,

but may prove conservative.

Processing projects near this

rate of increase will require a

much higher level of project

management efficiency.

150

102 99 110 109

117

103

130

101

119

184

205

183

206

150

102 99 110 109

117

103

130

101 99

153 149

112 103

-

50

100

150

200

250

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

Nu

mb

er o

f W

ells

MW - Unadjusted Well Counts MW Forecast

129 146

164 153

121 127 138

165

199 201

236

278

350

439

129 146

164 153

121 127 138

165

199

171

215 232

265

301

-

50

100

150

200

250

300

350

400

450

500

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

Nu

mb

er o

f W

ells

UDW/DW - Unadjusted Well Counts UDW/DW Forecast



Previous Demand Analysis Needs Revisiting After Visibility Improves

Source: IHS Inc., Infield Systems, Guggenheim Securities, LLC - Note: All estimates are by Guggenheim Securities, LLC

Probability-weighted, field-by-field data

analyzed across regions, based on project

likelihood for FID and non-FID projects.

Exploration rig demand focuses on

probability-weighted tender activity in the

near term. See next page for greater detail.

Heavily “risked” demand in the near term

accrues into greater demand inventories

and challenges production forecasts. We

have done a better job of accounting for

“carried” demand from project delays. Later

forecast helped by slowed pace of fleet

construction.

A number of rigs rolling off contract through

2016 screen for retirement due to age,

capabilities, and investment required.

Coupled with Brazil rigs that may not arrive

or be delayed, floater market balances may

prove better than expected.

Development Floater Demand 2014E 2015E 2016E 2017E 2018E

Development Well Count - Ultra/Deepwater 171 215 232 265 301

Divided By: Well-to-Rig Ratio 2.0 2.0 2.1 2.1 2.2

Equals: Development Floater Demand - Ultra/Deepwater 85 108 113 126 140

Development Well Count - Midwater 99 153 149 112 103

Divided By: Well-to-Rig Ratio 3.0 3.0 3.1 3.2 3.2

Equals: Development Floater Demand - Midwater 33 51 48 35 32

Add: Development Floater Demand - Ultra/Deepwater 85 108 113 126 140

Add: Development Floater Demand - Midwater 33 51 48 35 32

TOTAL DEVELOPMENT FLOATER DEMAND 118 159 162 162 171

Exploration Floater Demand 2014E 2015E 2016E 2017E 2018E

Add: Exploration Rig Demand - Ultra/Deepwater 67 74 78 82 86

Add: Exploration Rig Demand - Midwater 29 32 33 35 36

Equals: TOTAL EXPLORATION FLOATER DEMAND 95 106 111 116 122

Total Floater Demand 2014E 2015E 2016E 2017E 2018E

Add: Ultra/Deepwater Floater Demand 152 182 191 208 226

Add: Midwater Floater Demand 62 83 82 71 69

Equals: TOTAL FLOATER DEMAND 214 265 273 279 295

Floater Market Balance 2014E 2015E 2016E 2017E 2018E

Add: Ultradeepwater Floater Supply (Util. Adjusted) 111 120 135 145 152

Add: Deepwater Floater Supply (Util. Adjusted) 68 68 68 69 70

Less: Ultra/Deepwater Floater Demand (152) (182) (191) (208) (226)

Equals: Current Ultra/Deepwater Suplus/(Deficit) 27 6 12 6 (4)

Less: Floater Demand Assumed "Pushed to Right" (Previous Year) - (15) (10) (22) (39)

Less: Carried Ultra/Deepwater Floater From Rig Deficit - - (9) (7) (23)

Equals: Current & Carried Ultra/Deepwater Suplus/(Deficit) 27 (9) (7) (23) (67)

Add: Midwater Floater Supply (Util. Adjusted) 85 92 97 100 100

Less: Midwater Floater Demand (62) (83) (82) (71) (69)

Equals: Current Midwater Suplus/(Deficit) 23 9 15 29 31

Less: Floater Demand Assumed "Pushed to Right" (Previous Year) - (7) (10) (18) (22)

Less: Carried Midwater Floater Demand - - - - -

Equals: Current & Carried Midwater Suplus/(Deficit) 23 2 5 11 9

Floaters Rolling Off Contract Screening for Retirement 33 27 25 6 2

Petrobras/Brazil Rigs Likely Delayed/Cancelled - 1 6 6 6

Ultra/deepwater demand remains strong,

but mid-water activity slows in the forecast.



Unsanctioned Development Rig Demand at Risk

2014E 2015E 2016E 2017E 2018E

IHS - Non-FID (0-80% Probability) - - - 1 4

Probable (30-75% Probability) - 2 3 2 2

Possible (25% Probability) - 1 2 3 6

Ultra-Deepwater Wells- Infield - 3 5 6 12

IHS - Non-FID (0-80% Probability) 0 18 44 74 97

Probable (30-75% Probability) 3 11 14 30 48

Possible (25% Probability) 1 3 8 16 26

Deepwater Wells- Infield 5 31 66 120 171

IHS - Non-FID (0-80% Probability) 0 7 10 13 16

Probable (30-75% Probability) 3 14 32 41 52

Possible (25% Probability) 3 8 15 18 27

Midwater Wells- Infield 5 29 56 72 95

Total Unsanctioned Wells at Risk 10 63 127 198 278

Ultra/Deepwater Well-to-Rig Ratio 2.0 2.0 2.0 2.0 2.0

Midwater Well-to-Rig Ratio 3.0 3.0 3.0 3.0 3.0

Ultra/Deepwater Unsanctioned Floater Demand at Risk 2 17 36 63 91

Total Ultra/Deepwater Floater Demand 152 182 191 208 226

% of Demand at Risk 1% 9% 19% 30% 40%

Midwater Unsanctioned Floater Demand at Risk 2 10 19 24 32

Total Midwater Floater Demand 62 83 82 71 69

% of Demand at Risk 3% 12% 23% 34% 46%

We assign very

low probabilities to

non-FID projects

in 2014 and 2015.

With a deeper

dive into the IHS

components of

demand, we were

able to further risk-

weight current

assumptions

across water

depths.

Our conclusions

see very little

demand at risk

from non-FID

projects in the near

term, thus less of a

chance that

negative revisions

will come from

projects pushed to

the right.


Source: IHS Inc., Infield Systems, Guggenheim Securities, LLC

Previous Demand Analysis Needs Revisiting, but Offers View on Sensitivities



Oil Strips: Brent & WTI

77.0

77.5

78.0

78.5

79.0

79.5

80.0

77

79

81

83

85

87

89

91D

ec-

14

Jan

-15

Feb

-15

Mar

-15

Ap

r-1

5M

ay-1

5Ju

n-1

5Ju

l-1

5A

ug-

15

Sep

-15

Oct

-15

No

v-1

5D

ec-

15

Jan

-16

Feb

-16

Mar

-16

Ap

r-1

6M

ay-1

6Ju

n-1

6Ju

l-1

6A

ug-

16

Sep

-16

Oct

-16

No

v-1

6D

ec-

16

WTI

Co

ntr

act

Pri

ce (

USD

)

Bre

nt

Co

ntr

act

Pri

ce (

USD

)

Brent Strip WTI Strip

Oil Strips

Source: Guggenheim Securities, LLC, Bloomberg



Most Oil Price Strips Still Leave Many Deepwater Projects Above Breakeven

Source: IHS-Petrodata



Growth in Contracted Floaters Resilient to Short-Term Oil Fluctuations

137

140

146

152

157

162

163

168

166

165

169

171

169

175

174

179

180

179

185

185

190

193

193

192

194

199

201

200

206

213

220

226

241 251

253

255

257

259

261

264

260

262

260

-

10

20

30

40

50

60

70

80

90

100

110

120

130

110

120

130

140

150

160

170

180

190

200

210

220

230

240

250

260

270

280

2Q

04

3Q

04

4Q

04

1Q

05

2Q

05

3Q

05

4Q

05

1Q

06

2Q

06

3Q

06

4Q

06

1Q

07

2Q

07

3Q

07

4Q

07

1Q

08

2Q

08

3Q

08

4Q

08

1Q

09

2Q

09

3Q

09

4Q

09

1Q

10

2Q

10

3Q

10

4Q

10

1Q

11

2Q

11

3Q

11

4Q

11

1Q

12

2Q

12

3Q

12

4Q

12

1Q

13

2Q

13

3Q

13

4Q

13

1Q

14

2Q

14

3Q

14

4Q

14

Bre

nt

Oil

Pri

ce (

Qu

art

er

Avg

.)

To

tal

Co

ntr

acte

d R

ig Q

uart

ers

Total Contracted Floaters Brent Prices (Avg Quarter)

Total Contracted Floaters vs. Brent Prices

Growth in the contracted

floater rig count has

trended higher

independent of oil prices

at about a 6-7% CAGR for

the last 10 years.

Capital budget vetting &

concerns about project

economics have slowed

the trajectory of contacted

rigs in recent quarters.

Source: Guggenheim Securities, LLC, IHS-Petrodata, Bloomberg



Exploration & Appraisal Drilling Already Returned to Historical Run Rates

32

63 68

80

82

81

74 8

0

79

79

80 84

83

77 8

3

84 9

1

82

76

79

76 81

79 83 86

81

73 7

9

80 87 9

3 104

106

108

105

108

98

91 95

89

89

90 94

83

52

41

38

32

-5

10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85 90 95

100 105 110 115

1Q

04

2Q

04

3Q

04

4Q

04

1Q

05

2Q

05

3Q

05

4Q

05

1Q

06

2Q

06

3Q

06

4Q

06

1Q

07

2Q

07

3Q

07

4Q

07

1Q

08

2Q

08

3Q

08

4Q

08

1Q

09

2Q

09

3Q

09

4Q

09

1Q

10

2Q

10

3Q

10

4Q

10

1Q

11

2Q

11

3Q

11

4Q

11

1Q

12

2Q

12

3Q

12

4Q

12

1Q

13

2Q

13

3Q

13

4Q

13

1Q

14

2Q

14

3Q

14

4Q

14

1Q

15

2Q

15

3Q

15

4Q

15

To

tal

Exp

lora

tio

n a

nd

Ap

pra

isal

Rig

Qu

art

ers

Future Contracted E&A

Contracted Rigs Earmarked for E&A Activity



Floaters rolling off contract

may be renewed, but

present a risk to our flat

demand assumption.



Development Drilling Maintains Consistent Growth Path

24

58

57

51 56 63 70

68 7

6

75

69 74

76

76

69

56

55 61

60

52 58

54

52 57 62

58

55

55 60

59

61

58 65 7

6

78

80

92 101

108

110

112

109

109

92

8

15

16

15

14 13 18

15 13

12

16

11

12 17

22

35

34 3

7 44

54

53

56

62

53

46 5

9

74

70

62

59

60

60

55

60

69

65

65 6

5

56 62

63

62

59 8

4

-

10

20

30

40

50

60

70

80

90

100

110

120

130

140

150

160

170

180

190

1Q

04

2Q

04

3Q

04

4Q

04

1Q

05

2Q

05

3Q

05

4Q

05

1Q

06

2Q

06

3Q

06

4Q

06

1Q

07

2Q

07

3Q

07

4Q

07

1Q

08

2Q

08

3Q

08

4Q

08

1Q

09

2Q

09

3Q

09

4Q

09

1Q

10

2Q

10

3Q

10

4Q

10

1Q

11

2Q

11

3Q

11

4Q

11

1Q

12

2Q

12

3Q

12

4Q

12

1Q

13

2Q

13

3Q

13

4Q

13

1Q

14

2Q

14

3Q

14

4Q

14

To

tal

Develo

pm

en

t R

ig Q

uart

ers

Development Under Contract: Not Defined

32

73

72

66

70 77 8

8

83 89

87

85

85

88 93

91

91

89 9

8

104

107

111

110

114

110

108 117 129

125

122

119

121

118

121 1

35 147

145 157 166

164

172

174

171

168

177 1

89

195

188

183

-

10

20

30

40

50

60

70

80

90

100

110

120

130

140

150

160

170

180

190

200

210

1Q

04

2Q

04

3Q

04

4Q

04

1Q

05

2Q

05

3Q

05

4Q

05

1Q

06

2Q

06

3Q

06

4Q

06

1Q

07

2Q

07

3Q

07

4Q

07

1Q

08

2Q

08

3Q

08

4Q

08

1Q

09

2Q

09

3Q

09

4Q

09

1Q

10

2Q

10

3Q

10

4Q

10

1Q

11

2Q

11

3Q

11

4Q

11

1Q

12

2Q

12

3Q

12

4Q

12

1Q

13

2Q

13

3Q

13

4Q

13

1Q

14

2Q

14

3Q

14

4Q

14

1Q

15

2Q

15

3Q

15

4Q

15

To

tal

Develo

pm

en

t R

ig Q

uart

ers

Future Contracted Development/Unidentified

Contracted Rigs: Development & Unidentified

Past & Future Contracted Rigs: Development & Unidentified



The number of development rigs

contracted remains high through

2015.

A number of rigs are not identified

as exploration or development,

we assume they are working on

development work.



Number of Uncontracted Marketed Rigs Moves With Oil Prices

-

10

20

30

40

50

60

70

80

90

100

110

120

130

140

150

0

5

10

15

20

25

30

35

40

451

Q9

03

Q9

01

Q9

13

Q9

11

Q9

23

Q9

21

Q9

33

Q9

31

Q9

43

Q9

41

Q9

53

Q9

51

Q9

63

Q9

61

Q9

73

Q9

71

Q9

83

Q9

81

Q9

93

Q9

91

Q0

03

Q0

01

Q0

13

Q0

11

Q0

23

Q0

21

Q0

33

Q0

31

Q0

43

Q0

41

Q0

53

Q0

51

Q0

63

Q0

61

Q0

73

Q0

71

Q0

83

Q0

81

Q0

93

Q0

91

Q1

03

Q1

01

Q1

13

Q1

11

Q1

23

Q1

21

Q1

33

Q1

31

Q1

43

Q1

4

Bre

nt

Oil

Pri

ce (

Qu

arte

r En

d)

# o

f U

nco

ntr

acte

d M

arke

ted

Rig

s

Uncontracted Marketed RigsBrent Price (QTR End)

Period of oversupply,

following 80s overbuild

and low oil prices

Tight market spurs build

of 5G rigs.

Asian Financial Crisis, oil

approaches $10/bbl

Oil market tightens and prices

surge past $140/bbl.

US/Europe financial crisis

and oil market recovery

from lows near $40/bbl.

Current CAPEX spending

pullback, creates overbuild

scenario, and need for

retirement of legacy rigs.

Uncontracted Marketed Rigs


Note: Current quarter end Brent price as of 11/10/2014



Utilization vs. Brent

-

10

20

30

40

50

60

70

80

90

100

110

120

130

140

150

75%76%77%78%79%80%81%82%83%84%85%86%87%88%89%90%91%92%93%94%95%96%97%98%99%

100%

1Q

90

3Q

90

1Q

91

3Q

91

1Q

92

3Q

92

1Q

93

3Q

93

1Q

94

3Q

94

1Q

95

3Q

95

1Q

96

3Q

96

1Q

97

3Q

97

1Q

98

3Q

98

1Q

99

3Q

99

1Q

00

3Q

00

1Q

01

3Q

01

1Q

02

3Q

02

1Q

03

3Q

03

1Q

04

3Q

04

1Q

05

3Q

05

1Q

06

3Q

06

1Q

07

3Q

07

1Q

08

3Q

08

1Q

09

3Q

09

1Q

10

3Q

10

1Q

11

3Q

11

1Q

12

3Q

12

1Q

13

3Q

13

1Q

14

3Q

14

Bre

nt

Oil

Pri

ce (

Qu

arte

r En

d)

Mar

kete

d U

tiliz

atio

n

Marketed Util % Brent Price (QTR End)

Marketed Utilization vs. Brent Prices


Note: Current quarter end Brent price as of 11/10/2014



75%

80%

85%

90%

95%

100%

-

100

200

300

400

500

Jan

-09

Ap

r-0

9Ju

l-0

9O

ct-0

9Ja

n-1

0A

pr-

10

Jul-

10

Oct

-10

Jan

-11

Ap

r-1

1Ju

l-1

1O

ct-1

1Ja

n-1

2A

pr-

12

Jul-

12

Oct

-12

Jan

-13

Ap

r-1

3Ju

l-1

3O

ct-1

3Ja

n-1

4A

pr-

14

Jul-

14

Utilizatio

n %

Fixt

ure

Day

rate

(kp

d)

Marketed Utilization Dayrate

75%

80%

85%

90%

95%

100%

-

100

200

300

400

500

600

Jan

-09

Ap

r-0

9Ju

l-0

9O

ct-0

9Ja

n-1

0A

pr-

10

Jul-

10

Oct

-10

Jan

-11

Ap

r-1

1Ju

l-1

1O

ct-1

1Ja

n-1

2A

pr-

12

Jul-

12

Oct

-12

Jan

-13

Ap

r-1

3Ju

l-1

3O

ct-1

3Ja

n-1

4A

pr-

14

Jul-

14

Utilizatio

n %

Fixt

ure

Day

rate

(kp

d)


75%

80%

85%

90%

95%

100%

-

100

200

300

400

500

600

700

Jan

-09

Ap

r-0

9Ju

l-0

9O

ct-0

9Ja

n-1

0A

pr-

10

Jul-

10

Oct

-10

Jan

-11

Ap

r-1

1Ju

l-1

1O

ct-1

1Ja

n-1

2A

pr-

12

Jul-

12

Oct

-12

Jan

-13

Ap

r-1

3Ju

l-1

3O

ct-1

3Ja

n-1

4A

pr-

14

Jul-

14

Utilizatio

n %

Fixt

ure

Day

rate

(kp

d)


Marketed Utilization vs. Average Fixed Dayrates

UDW Marketed Utilization vs. Fixtures DW Marketed Utilization vs. Fixtures

Midwater Semis Marketed Utilization vs. Fixtures


Note: Data through September 2014



Floater Fleet Additions and Attrition: Raw Consultant Data

-

5

10

15

20

25

30

35

19

58

19

59

19

60

19

61

19

62

19

63

19

64

19

65

19

66

19

67

19

68

19

69

19

70

19

71

19

72

19

73

19

74

19

75

19

76

19

77

19

78

19

79

19

80

19

81

19

82

19

83

19

84

19

85

19

86

19

87

19

88

19

89

19

90

19

91

19

92

19

93

19

94

19

95

19

96

19

97

19

98

19

99

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

20

10

20

11

20

12

20

13

20

14

20

15

20

16

20

17

20

18

20

19

20

20

# o

f R

igs

Drillship Semisubmersible

0

2

4

6

8

10

12

14

16

18

19

53

19

54

19

55

19

56

19

57

19

58

19

59

19

60

19

61

19

62

19

63

19

64

19

65

19

66

19

67

19

68

19

69

19

70

19

71

19

72

19

73

19

74

19

75

19

76

19

77

19

78

19

79

19

80

19

81

19

82

19

83

19

84

19

85

19

86

19

87

19

88

19

89

19

90

19

91

19

92

19

93

19

94

19

95

19

96

19

97

19

98

19

99

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

20

10

20

11

20

12

20

13

20

14

# o

f R

igs

Drillship Semisubmersible

Floater Additions by Year

Floater Attrition by Year

Total Drillship Additions Post 2000: 141

Total Semisubmersible Additions Post 2000: 100

Total Drillship Attritions Post 2000: 3

Total Semisubmersible Attritions Post 2000:13




Valuation & EPS Comp Sheets



Large Cap Services 7.5 x

Large Cap Equipment 8.6 x

Small/Mid Cap Svcs &

Equipment 8.8 x

Offshore Drilling 6.5 x

E & C 8.3 x

5.0 x

5.5 x

6.0 x

6.5 x

7.0 x

7.5 x

8.0 x

8.5 x

9.0 x

5.0 x 10.0 x 15.0 x 20.0 x 25.0 x

EV

/EB

ITD

A '14E

Price/Earnings '14E

NAVs & Relative Valuation Leave Offshore Driller Shares Screening Attractively

Source: Guggenheim Securities, LLC, Thomson Reuters

Note: Based on Consensus Estimates

Offshore Drillers Least Expensive Sub-Sector 2014 Y/Y EBITDA Growth vs. 2014 EV/EBITDA

PX NAV-B/U NAV-R P/NAV-B/U P/NAV-R

Company Rating 11/12 Target PX

Rtn to

Target

2014

PE

2015

PE

2016

PE

2014

PE

2015

PE

2016

PE

2014

EV/EBITDA

2015

EV/EBITDA

2016

EV/EBITDA 2014E 2014E 2014E 2014E

ATW Buy 35.52$ $55.0 55% 11.2x 8.3x 8.5x 7.3x 5.4x 5.5x 7.4x 5.6x 5.4x 55 65 65% 55%

DO Buy 35.84$ $50.0 40% 16.4x 15.4x 16.7x 11.8x 11.0x 11.9x 7.0x 6.4x 6.5x 50 52 72% 69%

ESV Neutral 39.27$ $44.0 12% 7.3x 7.2x 7.0x 6.5x 6.4x 6.2x 6.0x 5.9x 5.6x 44 44 89% 89%

HERO Neutral 1.61$ $1.5 -7% NA NA NA NA NA NA 5.7x 8.2x 29.8x 0.75 0.75 215% 215%

NE Buy 21.54$ $30.0 39% 10.2x 13.0x 12.8x 7.4x 9.4x 9.2x 5.1x 6.0x 5.9x 30 30 72% 72%

ORIG Neutral 12.87$ $15.0 17% 6.0x 5.6x 5.0x 5.1x 4.8x 4.3x 5.9x 5.5x 5.2x 15 17 86% 76%

PACD Buy 6.87$ $14.0 104% 17.3x 12.2x 13.5x 8.5x 6.0x 6.6x 7.2x 5.4x 5.4x 14 14 49% 49%

RDC Neutral 24.05$ $25.0 4% 11.9x 6.4x 7.7x 11.5x 6.2x 7.4x 8.0x 5.1x 5.3x 25 27 96% 88%

RIG Buy 27.08$ $45.0 66% 9.5x 14.8x 12.9x 5.7x 8.9x 7.7x 4.8x 5.8x 5.5x 45 45 60% 60%

SDRL Buy 21.27$ $50.0 135% 16.1x 14.3x - 6.9x 6.1x - 11.6x 9.6x - 28 33 76% 64%

Averages 7.8x 7.1x 7.4x 6.8x 6.4x 8.3x 88% 84%

Target Current

Large Cap Services 7.5 x

Large Cap Equipment 8.6 x

Small/Mid Cap Svcs &

Equipment 8.8 x

Offshore Drilling 6.5 x

E & C 8.3 x

5.0 x

5.5 x

6.0 x

6.5 x

7.0 x

7.5 x

8.0 x

8.5 x

9.0 x

0% 5% 10% 15% 20%

EV

/EB

ITD

A '14E

EBITDA Growth, '14E vs. '13E

Source: Guggenheim Securities, LLC, Thomson Reuters, Company Reports



Gross Fleet Value & EBITDA by Rig Generation

Source: Guggenheim Securities, LLC

Estimated Gross Fleet Value Breakdown Estimated EBITDA Breakdown 2014 - 2015

Ticker Jackups 2G 3G 4G 5G 6G Other

ATW 15% 0% 0% 9% 0% 75% 0%

DO 5% 3% 4% 17% 17% 54% 0%

ESV 35% 0% 1% 11% 18% 35% 1%

HERO 74% 0% 0% 0% 0% 0% 26%

NE 10% 0% 18% 16% 17% 38% 0%

ORIG 0% 0% 0% 0% 11% 89% 0%

PACD 0% 0% 0% 0% 0% 100% 0%

RDC 57% 0% 0% 0% 0% 43% 0%

RIG 11% 1% 6% 5% 23% 54% 0%

SDRL 25% 0% 0% 1% 3% 71% 1%

TOTAL 17% 0% 7% 8% 13% 53% 1%

Ticker Jackups 2G 3G 4G 5G 6G Other

ATW 19% -1% 0% 22% 0% 58% 0%

DO 7% 20% 18% 15% 19% 21% 0%

ESV 38% 0% 1% 10% 25% 24% 2%

HERO 84% 0% 0% 0% 0% 0% 16%

NE 28% 0% 7% 13% 14% 37% 0%

ORIG 0% 0% 0% 0% 21% 79% 0%

PACD 0% 0% 0% 0% 0% 100% 0%

RDC 68% 0% 0% 0% 0% 32% 0%

RIG 5% 2% 20% 16% 26% 31% 0%

SDRL 25% 0% 0% 3% 5% 67% 0%

TOTAL 23% 2% 7% 10% 15% 42% 1%



Jackup Contract Coverage Give Less Buffer Than for Floaters

Jackup Contract Coverage Floater Contract Coverage

Source: Guggenheim Securities, LLC, Company Reports

33%

57%

50%

55%

67%

71%

46%

100%

70%

61%

84%

66%

79%

84%

70%

71%

100%

96%

87%

90%

96%

96%

96%

100%

100%

100%

100%

0% 20% 40% 60% 80% 100%

RIG

NE

DO

ESV

SDRL

ATW

PACD

RDC

ORIG

2014E 2015E 2016E

17%

47%

37%

38%

17%

26%

45%

45%

16%

52%

76%

64%

78%

46%

84%

73%

50%

90%

90%

92%

93%

93%

94%

95%

0% 20% 40% 60% 80% 100%

HERO

RDC

RIG

ESV

ATW

DO

NE

SDRL

2014E 2015E 2016E



Clear Relationship Between Yield & Payout Ratios

Yield vs. DPS/CEPS

Source: Thomson Reuters, Company Reports, Guggenheim Securities, LLC

NADL 19.4%

DO, 9.8%

ESV, 7.6%NE, 7.1%

ORIG, 5.9%

RDC, 1.7%

RIG, 11.1%

SDRL, 18.8%

CRR, 2.6%

0.0%

1.0%

2.0%

3.0%

4.0%

5.0%

6.0%

7.0%

8.0%

9.0%

10.0%

11.0%

12.0%

13.0%

14.0%

15.0%

16.0%

17.0%

18.0%

19.0%

20.0%

21.0%

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 110% 120%

Div

iden

d Y

ield

(L

ate

st

Qu

art

er

An

nu

ali

zed

)

DPS/CEPS 3Q14E (annualized)

Full payouts should

migrate yields toward

each company’s cost of

equity, under the

assumption that higher

payouts signify lower

future distribution

growth.

Lower yields are contingent upon perceived

future distribution growth. Theoretically,

lower payout ratios produce lower yields, as

assumed reinvestment should produce

dividend growth in the future.



Yield-Based Values vs. P/NAV

Yield vs. P/NAV relationship


DO, 9.8%

ESV, 7.6%

NE, 7.1% ORIG, 5.9%

RDC, 1.7%

RIG, 11.1%

SDRL, 18.8%

NADL, 19.4%

SDLP, 11.3%

0.0%

1.0%

2.0%

3.0%

4.0%

5.0%

6.0%

7.0%

8.0%

9.0%

10.0%

11.0%

12.0%

13.0%

14.0%

15.0%

16.0%

17.0%

18.0%

19.0%

20.0%

21.0%

45% 55% 65% 75% 85% 95% 105% 115%

Div

iden

d Y

ield

(L

ate

st

Qu

art

er

An

nu

ali

zed

)

P/NAV - Break-up 2014E



OFS Earnings Metrics

Source: Thomson Reuters, Guggenheim Securities, LLC

Mkt Price Gugg EPS PE Consensus EPS EPS Variance

Company Ticker Rating Cap 11/12 Target Upside 4Q14E 14E 15E 16E 14E 15E 16E 4Q14E 14E 15E 16E 4Q14E 14E 15E 16E

S&P 500 SPX 2,038 17.4 16.0 14.9 117.3 127.2 137.0

Large Cap Services

Baker Hughes BHI Buy 22,054 50.98 72 41% 1.20 3.98 4.85 5.80 12.8 10.5 8.8 1.19 3.97 4.84 5.57 1% 0% 0% 4%

Halliburton HAL Buy 45,110 53.23 75 41% 1.21 4.04 5.05 5.80 13.2 10.5 9.2 1.21 4.04 4.82 5.53 0% 0% 5% 5%

Schlumberger SLB Buy 125,372 97.43 125 28% 1.51 5.57 6.40 7.35 17.5 15.2 13.3 1.55 5.62 6.34 7.19 -3% -1% 1% 2%

Weatherford WFT Neutral 11,948 15.44 25 62% 0.43 1.15 1.75 - 13.4 8.8 - 0.38 1.06 1.53 1.84 14% 8% 15% NA

Mean 14.2 11.3 10.4

Large Cap Equipment

Cameron CAM Buy 11,576 58.63 75 28% 1.21 4.10 4.75 4.90 14.3 12.3 12.0 1.22 4.12 4.87 5.49 -1% 0% -2% -11%

FMC Tech FTI Buy 13,046 55.79 70 25% 0.77 2.85 3.40 3.70 19.6 16.4 15.1 0.80 2.86 3.38 3.73 -4% 0% 1% -1%

Nat Oil Varco NOV Buy 31,432 73.00 90 23% 1.59 5.98 6.05 6.25 12.2 12.1 11.7 1.61 6.06 6.32 6.50 -1% -1% -4% -4%

Tenaris TS Buy 21,533 36.48 50 37% 0.59 2.56 3.35 4.35 14.2 10.9 8.4 0.65 2.66 2.87 3.19 -9% -4% 17% 37%

Mean 15.1 12.9 11.8

SMid Cap Services

C&J Energy Svcs CJES Neutral 1,035 18.71 32 71% 0.38 1.20 2.00 - 15.6 9.4 - 0.44 1.35 1.84 1.75 -13% -11% 9% NA

Core Laboratories CLB Buy 6,101 139.31 170 22% 1.55 5.80 6.70 7.50 24.0 20.8 18.6 1.54 5.81 6.34 6.85 1% 0% 6% 10%

Carbo Ceramics CRR Neutral 1,167 50.52 55 9% 0.62 3.25 3.25 4.55 15.5 15.5 11.1 0.69 3.27 3.12 3.79 -9% 0% 4% 20%

Frank's International FI Buy 3,123 20.24 27 33% 0.31 1.07 1.30 - 18.9 15.6 - 0.31 1.13 1.25 1.37 0% -5% 4% NA

Oil States Int'l OIS Neutral 3,056 57.48 60 4% 1.00 4.29 4.30 4.65 13.4 13.4 12.4 1.00 3.80 4.07 4.46 0% 13% 6% 4%

Superior Energy Svcs SPN Neutral 3,684 24.21 26 7% 0.50 1.81 2.25 2.35 13.4 10.8 10.3 0.52 1.82 2.21 2.45 -3% -1% 2% -4%

U.S. Silica Holdings SLCA Buy 2,305 42.75 70 64% 0.72 2.43 3.37 4.17 17.6 12.7 10.3 0.74 2.43 3.59 5.15 -2% 0% -6% -19%

TESCO TESO Buy 647 16.32 23 41% 0.31 1.08 1.40 1.60 15.1 11.7 10.2 0.34 1.14 1.41 1.59 -10% -6% -1% 1%-

Mean 16.7 13.7 12.1

*In $m except per share data



OFS Earnings Metrics


Mkt Price Gugg EPS PE Consensus EPS EPS Variance

Company Ticker Rating Cap 11/12 Target Upside 4Q14E 14E 15E 16E 14E 15E 16E 4Q14E 14E 15E 16E 4Q14E 14E 15E 16E

Smid Cap Equipment

Aker Solutions AKSO Buy kr 11,820 43.45 kr 75 73% kr 1.17 kr 4.15 kr 5.40 kr 6.70 10.5 8.0 6.5

Dresser-Rand DRC Neutral 6,256 81.62 83 2% 1.39 2.65 3.25 - 30.8 25.1 - 1.38 2.57 3.08 3.51 1% 3% 5% NA

Dril-Quip DRQ Neutral 3,425 86.78 100 15% 1.35 5.01 5.55 6.00 17.3 15.6 14.5 1.34 5.03 5.72 6.15 1% 0% -3% -2%

Forum Energy Tech FET Buy 2,560 27.19 40 47% 0.51 1.87 2.35 2.74 14.5 11.6 9.9 0.50 1.87 2.21 2.45 2% 0% 6% 12%

Oceaneering OII Neutral 7,372 70.20 80 14% 0.99 4.00 4.35 4.80 17.5 16.1 14.6 1.00 4.00 4.40 4.90 -1% 0% -1% -2%425%

Mean 18.1 15.3 11.4

Offshore Drilling

Atwood Oceanics* ATW Buy 2,285 35.52 55 55% 1.31 4.89 6.60 6.50 7.3 5.4 5.5 1.56 4.91 6.62 6.35 -16% 0% 0% 2%

Diamond DO Buy 4,915 35.84 50 40% 0.62 3.05 3.25 3.00 11.8 11.0 11.9 0.65 3.09 3.36 2.28 -5% -1% -3% 32%

Ensco plc ESV Neutral 9,199 39.27 44 12% 1.37 6.05 6.10 6.30 6.5 6.4 6.2 1.53 6.15 5.21 4.74 -10% -2% 17% 33%

Hercules Offshore HERO Neutral 259 1.61 1.50 -7% (0.51) (0.39) (0.45) (0.71) NA NA NA (0.29) (0.08) (0.12) (0.12) 78% 413% 285% 492%

Noble Corp NE Buy 5,434 21.54 30 39% 0.40 2.93 2.30 2.35 7.4 9.4 9.2 0.50 2.96 2.25 1.86 -19% -1% 2% 27%

Ocean Rig UDW ORIG Neutral 1,697 12.87 15 17% 0.80 2.52 2.70 3.00 5.1 4.8 4.3 0.56 2.00 2.16 1.71 42% 26% 25% 76%

Pacific Drilling PACD Buy 1,443 6.87 14 104% 0.26 0.81 1.15 1.04 8.5 6.0 6.6 0.27 0.82 1.05 0.73 -2% -1% 9% 42%

Rowan RDC Neutral 2,995 24.05 25 4% 0.87 2.10 3.90 3.25 11.5 6.2 7.4 0.91 2.18 3.57 3.68 -5% -4% 9% -12%

Transocean RIG Buy 9,810 27.08 45 66% 0.73 4.75 3.05 3.50 5.7 8.9 7.7 0.71 4.69 2.66 1.95 3% 1% 15% 80%

Seadrill SDRL Buy 10,488 21.27 50 135% 0.69 3.10 3.50 - 6.9 6.1 - 0.71 2.99 3.23 3.33 -3% 4% 8% NA- NA NA NA NA

Mean 7.8 7.1 7.4

Onshore Drilling

Helm & Payne* HP Neutral 9,260 85.56 110 29% - 6.21 7.25 - 13.8 11.8 - 1.76 6.29 7.41 7.76 NA -1% -2% NA

Nabors NBR Neutral 4,990 17.24 32 86% 0.44 1.20 2.30 - 14.4 7.5 - 0.42 1.18 1.95 2.11 5% 2% 18% NA

Patterson UTI PTEN Neutral 3,169 21.64 40 85% 0.50 1.55 2.35 - 14.0 9.2 - 0.52 1.59 2.22 2.34 -4% -3% 6% NA

Seventy Seven Energy SSE Buy 597 11.73 33 181% 0.35 0.75 2.00 3.00 15.6 5.9 3.9 0.30 0.69 1.68 2.28 15% 9% 19% 32%

Mean 14.4 8.6 3.9

*Quarterly EPS figures for ATW and HP reflect calendar year reporting basis. In $m except per share data.



OFS EBITDA & Cash Flow Valuation


Price Net Current Debt / EBITDA EV / EBITDA CFPS P / CFPS FCFPS FCF NAV

Company Ticker Rating 11/12 Debt EV EBITDA 14E 15E 16E 14E 15E 16E 14E 15E 16E 14E 15E 16E 15E Yield NAV P/NAV*

S&P 500 2,038 9.3 8.9 8.8

Large Cap Services

Baker Hughes BHI Buy 50.98 3,114 25,168 0.8 4,724 5,390 6,110 5.3 4.7 4.1 8.08 9.13 10.28 6.3 5.6 5.0 2.51 4.9% NA NA

Halliburton HAL Buy 53.23 5,787 50,897 1.1 7,269 8,744 - 7.0 5.8 NA 6.52 7.81 - 8.2 6.8 NA 2.75 5.2% NA NA

Schlumberger SLB Buy 97.43 6,318 131,690 0.8 13,820 15,061 16,659 9.5 8.7 7.9 8.64 9.65 10.64 11.3 10.1 9.2 4.09 4.2% NA NA

Weatherford WFT Neutral 15.44 8,761 20,709 2.2 3,138 3,710 - 6.6 5.6 NA 2.87 3.39 - 5.4 4.6 NA 1.38 8.9% NA NA

Mean 7.1 6.2 6.0 7.8 6.8 7.1 5.8%

Large Cap Equipment

Cameron CAM Buy 58.63 2,039 13,615 1.7 1,630 1,748 1,804 8.4 7.8 7.5 5.77 6.55 6.74 10.2 9.0 8.7 3.68 6.3% NA NA

FMC Tech FTI Buy 55.79 836 13,882 1.0 1,302 1,484 1,602 10.7 9.4 8.7 3.83 4.47 4.83 14.6 12.5 11.6 2.43 4.3% NA NA

Nat Oil Varco NOV Buy 73.00 (945) 30,487 0.7 4,545 4,674 4,791 6.7 6.5 6.4 7.79 7.89 8.09 9.4 9.3 9.0 3.43 4.7% NA NA

Tenaris TS Buy 36.48 (1,364) 20,169 0.1 2,608 3,209 3,985 7.7 6.3 5.1 3.51 4.29 5.31 10.4 8.5 6.9 0.76 2.1% NA NA

Mean 8.4 7.5 6.9 11.1 9.8 9.0 4.4%

SMid Cap Services

C&J Energy Svcs CJES Neutral 18.71 283 1,318 1.2 243 356 - 5.4 3.7 NA 3.12 4.33 - 6.0 4.3 NA 4.30 23.0% NA NA

Core Laboratories CLB Buy 139.31 346 6,447 1.0 378 421 457 17.1 15.3 14.1 6.40 7.37 8.25 21.8 18.9 16.9 6.21 4.5% NA NA

Carbo Ceramics CRR Neutral 50.52 (25) 1,142 0.0 161 173 228 7.1 6.6 5.0 5.47 5.92 7.69 9.2 8.5 6.6 (2.09) -4.1% NA NA

Frank's International FI Buy 20.24 (443) 2,680 0.0 421 476 - 6.4 5.6 NA 1.49 1.74 - 13.6 11.6 NA 0.37 1.8% NA NA

Oil States Int'l OIS Neutral 57.48 119 3,175 0.3 532 477 507 6.0 6.7 6.3 7.90 6.73 7.12 7.3 8.5 8.1 2.32 4.0% NA NA

Superior Energy Svcs SPN Neutral 24.21 1,666 5,350 1.4 1,222 1,389 1,458 4.4 3.9 3.7 6.04 7.11 7.88 4.0 3.4 3.1 2.01 8.3% NA NA

U.S. Silica Holdings SLCA Buy 42.75 203 2,508 1.5 243 333 401 10.3 7.5 6.3 3.30 4.56 5.53 13.0 9.4 7.7 2.46 5.8% NA NA

TESCO TESO Buy 16.32 (88) 559 0.0 106 126 139 5.3 4.4 4.0 2.08 2.42 2.66 7.8 6.7 6.1 1.11 6.8% NA NANA

Mean 7.7 6.7 6.6 10.3 8.9 8.1 6.2%

*All units in $m except per share data.



OFS EBITDA & Cash Flow Valuation


Price Net Current Debt / EBITDA EV / EBITDA CFPS P / CFPS FCFPS FCF NAV

Company Ticker Rating 11/12 Debt EV EBITDA 14E 15E 16E 14E 15E 16E 14E 15E 16E 14E 15E 16E 15E Yield NAV P/NAV*

Smid Cap Equipment

Aker Solutions AKSO Buy kr 43.45 kr 2,201 kr 14,021 1.1 kr 3,322 kr 2,995 kr 3,478 4.2 4.7 4.0 kr 8.03 kr 7.79 9.13 5.4 5.6 4.8 kr 5.17 11.9% NA NA

Dresser-Rand DRC Neutral 81.62 1,223 7,479 2.4 475 545 - 15.8 13.7 NA 3.88 4.52 - 21.0 18.1 NA 2.60 3.2% NA NA

Dril-Quip DRQ Neutral 86.78 (345) 3,080 0.0 299 320 345 10.3 9.6 8.9 5.77 6.37 6.88 15.0 13.6 12.6 2.60 3.0% NA NA

Forum Energy Tech FET Buy 27.19 317 2,877 1.2 349 406 445 8.2 7.1 6.5 2.56 3.08 3.51 10.6 8.8 7.7 2.35 8.6% NA NA

Oceaneering OII Neutral 70.20 71 7,443 0.3 861 937 1,026 8.6 7.9 7.3 6.13 6.79 7.52 11.5 10.3 9.3 2.93 4.2% NA NA16,206 17,383 17,836 71 79

Mean 8.3 7.4 6.6 11.2 9.8 8.3 6.2%

Offshore Drilling

Atwood Oceanics* ATW Buy 35.52 1,705 3,990 3.2 552 727 755 7.2 5.5 5.3 7.16 9.45 9.73 5.0 3.8 3.7 (0.18) -0.5% 55 65%

Diamond DO Buy 35.84 2,188 7,103 2.4 1,080 1,191 1,158 6.6 6.0 6.1 6.26 6.51 5.97 5.7 5.5 6.0 0.68 1.9% 50 72%

Ensco plc ESV Neutral 39.27 4,878 14,077 2.5 2,357 2,397 2,513 6.0 5.9 5.6 8.57 8.61 8.74 4.6 4.6 4.5 (0.21) -0.5% 44 89%

Hercules Offshore HERO Neutral 1.61 1,054 1,313 5.3 230 158 44 5.7 8.3 30.1 0.66 0.61 (0.03) 2.4 2.6 NA (0.21) -12.8% 0.75 215%

Noble Corp NE Buy 21.54 4,758 10,192 2.4 1,999 1,692 1,719 5.1 6.0 5.9 6.18 5.01 4.94 3.5 4.3 4.4 1.46 6.8% 30 72%

Ocean Rig UDW ORIG Neutral 12.87 3,752 5,449 4.6 951 1,012 1,066 5.7 5.4 5.1 4.95 5.35 5.75 2.6 2.4 2.2 0.14 1.1% 15 86%

Pacific Drilling PACD Buy 6.87 2,444 3,887 4.3 554 730 741 7.0 5.3 5.2 1.74 2.40 2.45 3.9 2.9 2.8 0.61 8.9% 14 49%

Rowan RDC Neutral 24.05 2,549 5,544 4.1 689 1,071 1,031 8.0 5.2 5.4 4.63 7.05 6.57 5.2 3.4 3.7 0.12 0.5% 25 96%

Transocean RIG Buy 27.08 7,045 16,855 2.7 3,713 3,068 3,196 4.5 5.5 5.3 7.91 6.28 6.56 3.4 4.3 4.1 1.05 3.9% 45 60%

Seadrill SDRL Buy 21.27 10,954 21,442 3.9 2,450 2,955 - 8.8 7.3 NA 4.46 4.99 - 4.8 4.3 NA (0.72) -3.4% 28 76%

Mean 6.5 6.0 8.2 4.1 3.8 3.9 0.6% 88%

Onshore Drilling

Helm & Payne HP Neutral 85.56 (634) 8,626 0.1 1,559 1,822 - 5.5 4.7 NA 10.22 11.65 - 8.4 7.3 NA (2.01) -2.4% NA NA

Nabors NBR Neutral 17.24 3,470 8,460 2.2 1,800 2,327 - 4.7 3.6 NA 5.20 6.69 - 3.3 2.6 NA 0.09 0.5% NA NA

Patterson UTI PTEN Neutral 21.64 567 3,736 0.7 985 1,247 - 3.8 3.0 NA 5.83 7.22 - 3.7 3.0 NA (0.75) -3.5% NA NA

Seventy Seven Energy SSE Buy 11.73 1,564 2,161 3.3 481 589 675 4.5 3.7 3.2 7.14 9.27 10.48 1.6 1.3 1.1 1.90 16.2% NA NA

Mean 4.6 3.8 3.2 4.3 3.5 1.1 2.7%

*Quarterly EPS figures for ATW and HP reflect calendar year reporting basis. NAV figures for Offshore Drilling companies are Break-Up NAVs. In $m except per share data.



Offshore Drillers EPS Comp


SDRL 3Q14 is an estimate

ATW 4Q14 and 2014 are actual EPS

Ticker Company Category 2013 2014E 2015E 2016E 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 4Q14E 1Q15E

Offshore Drillers

ATW Atwood Oceanics EPS 5.32 4.89 6.60 6.50 1.10 1.28 1.37 1.57 1.28 0.78 1.11 1.72 1.31

Consensus EPS 4.91 6.62 6.35 1.55 1.56

Consensus EPS-High 5.36 7.40 9.00 1.78 1.88

Consensus EPS-Low 4.49 5.05 4.95 1.36 1.27

DO Diamond Offshore EPS 4.77 3.05 3.25 3.00 1.26 1.33 1.22 0.96 0.93 0.53 0.97 0.62 0.23

Consensus EPS 3.09 3.36 2.28 0.65 0.66



ESV Ensco EPS 6.16 6.05 6.10 6.30 1.36 1.55 1.69 1.56 1.23 1.58 1.87 1.37 1.39

Consensus EPS 6.15 5.21 4.74 1.53 1.27



HERO Hercules Offshore EPS 0.24 (0.39) (0.45) (0.71) (0.02) 0.01 0.11 0.14 0.22 (0.04) (0.07) (0.51) (0.17)

Consensus EPS (0.08) (0.12) (0.12) (0.29) (0.14)

Consensus EPS-High 0.90 0.81 0.30 (0.03) (0.02)

Consensus EPS-Low (0.39) (0.63) (0.71) (0.51) (0.23)

NE Noble Drilling EPS 2.89 2.93 2.30 2.35 0.59 0.63 0.85 0.82 1.03 0.93 0.57 0.40 0.49

Consensus EPS 2.96 2.25 1.86 0.50 0.49



ORIG Ocean Rig UDW EPS 0.84 2.52 2.70 3.00 0.04 0.10 0.30 0.30 0.24 0.53 0.96 0.80 0.41

Consensus EPS 2.00 2.16 1.71 0.56 0.49



PACD Pacific Drilling EPS 0.42 0.81 1.15 1.04 0.07 0.10 0.14 0.12 0.10 0.23 0.22 0.26 0.26

Consensus EPS 0.82 1.05 0.73 0.27 0.25



RDC Rowan EPS 1.96 2.10 3.90 3.25 0.55 0.57 0.42 0.42 0.28 0.33 0.63 0.87 0.70

Consensus EPS 2.18 3.57 3.68 0.91 0.76



RIG Transocean EPS 4.12 4.75 3.05 3.50 0.93 1.08 1.37 0.73 1.43 1.61 0.98 0.73 0.71

Consensus EPS 4.69 2.66 1.95 0.71 0.65



SDRL Seadrill EPS 3.02 3.10 3.50 -- 0.69 0.96 0.60 0.79 0.59 1.23 0.60 0.69 0.84

Consensus EPS 2.99 3.23 3.33 0.67 0.71 0.73

Consensus EPS-High 3.98 5.83 4.88 0.85 0.87 0.84

Consensus EPS-Low 2.18 2.39 2.56 0.55 0.54 0.62



OFS Valuations & Risks


` Ticker Valuation Risks

BHI BHI currently trades at approximately 13x our 2014 EPS and 6x our 2014 EBITDA estimates. Our 12-month

price target of $72 is based on 15x our 2015 EPS and 6.5x our 2015 EBITDA estimates.

While w e believe that current consensus capex is still achievable even if WTI averages $85/bbl next year, and w hile w e note that BHI has several

buffers w hich should protect its 2015 earnings grow th, w e submit that another prolonged leg dow n in oil prices due to domestic or international

factors w ould likely put E&P spending at risk, and therefore our estimates may prove too high.

HAL HAL currently trades at approximately 14x our 2014 EPS and 7x our 2014 EBITDA estimates. Our 12-month

price target of $75 is based on 10.5x our 2015 EPS and 8.0x our 2015 EBITDA estimates.

In our view , the risks to the stock are all macro related right now . As our “Picking Up the Pieces” report of October 20 pointed out, should the price

of WTI collapse and average $75/bbl or less next year, the organic contraction in E&P spending w ould be an estimated 18%—a gap vs. current

consensus that w ould be too w ide to close w ith incremental debt. Under this scenario, w e believe N American earnings w ould fall by roughly one-

third (to the 1H13 level), removing roughly $1.00 from our current 2015 EPS estimate. Additionally, HAL maintains a relatively high level of exposure

to Iraq; consequently, should the conflict w ith ISIS interfere w ith operations (as it did during 3Q14), EPS could be adversely impacted.

SLB SLB currently trades at approximately 18x our 2014 EPS and 10x our 2014 EBITDA estimates. Our 12-month


Much of the investment thesis for SLB rests w ith its ability to grow market share by delivering superior services quality and tool reliability, and

reduce the cost of services delivery. To the extent that execution of this strategy takes longer than w e currently expect, our estimates—especially

margins—could prove too aggressive. Similarly, SLB’s human resources program has long been a competitive advantage, and to the extent that the

company loses key people (particularly to IOCs), its competitive positioning in the industry could w eaken.

WFT WFT currently trades at approximately 14x our 2014 EPS and 7x our 2014 EBITDA estimates. Our 12-month


Over the course of this year, WFT’s progress on its transformation initiatives has led it to begin to improve margins and cash flow w hile shedding

underperforming businesses, allow ing it to begin to trade more in line w ith peers; how ever, should commodity prices encounter any w eakness due

to crude saturation in North America, or should WFT be unable to execute on its remaining divestitures in a timely manner, multiples may begin to

compress again and our estimates may prove too high.

CAM CAM currently trades at approximately 15x our 2014 EPS estimate and 8x our 2014 EBITDA estimate. Our 12-

month price target of $75 reflects a multiple of 12.4x our 2015 EPS and 8x our 2015 EBITDA estimates.

In addition to the obvious macro risks, w e believe CAM has several company-specif ic risks. For instance, Drilling Products still make up about one-

third of the company’s revenue, and new orders for offshore rig equipment have been w eak as a result of the decline in offshore rig rates. Next

year, w e believe the Drilling group’s contribution to revenue and earnings grow th w ill be determined by the aftermarket segment in w hich the

company has very little forw ard visibility. Moreover, CAM has onshore U.S. exposure through its surface and distributor valves segments. Should

oil prices w eaken enough to push U.S. onshore E&P spending materially low er next year, our current 2015 earnings estimate w ould likely prove to

be too high.

FTI FTI currently trades at approximately 20x our 2014 EPS and 11x our 2014 EBITDA estimates. Our 12-month

price target of $70 reflects a multiple of 16.4x our 2015 EPS and 9.5x our 2015 EBITDA estimates.

In addition to oil-price related macro risks, w e believe FTI has a couple of company specif ic risks, including: 1) the timing of the delivery of its

intervention stacks next year (w hich w ould impact the timing of incremental subsea services revenues and earnings); and 2) the risk that frac

company’s scale back meaningfully on capex next year, adversely impacting FTI’s f luid-end orders, revenues, and earnings.

NOV NOV currently trades at approximately 12x our 2014 EPS estimate and 7x our 2014 EBITDA estimate. Our 12-

month price target of $90 reflects a multiple of 11.6x our 2015 EPS and 6.3x our 2015 EBITDA estimates.

Maintaining EPS of $6+ over the next tw o years requires onshore equipment orders to remain strong through 1H15, visibility of w hich w eakens as

oil prices retrench to the $70/bbl level.

TS TS currently trades at approximately 15x our 2014 EPS and 8x our 2014 EBITDA estimates. Our 12-month


In addition to the risk to the U.S. rig count brought on by the recent correction in oil prices, w e believe the biggest risk to TS is margin associated

w ith shifting product mix. For instance, the absence of premium shipments to Saudi Arabia in 3Q14 are expected to contribute to a 100bp

contraction in EBITDA margin. Should premium volumes not recover in 4Q and 2015 in other regions, providing better balance to TS's mix, margins

could remain under pressure as volumes and revenues from commodity products (e.g., U.S. w elded OCTG) drive grow th.





Ticker Valuation Risks

CJES CJES currently trades at approximately 6x our 2014 EBITDA and 6x our 2014 OCFPS estimates. Our 12-

month price target of $32 is based on 6.5x our 2015 EBITDA and 6.5x our 2015 OCFPS estimates.

In our view , risk to our estimates stems from C&J’s ability to execute on the cost synergies it expects to realize from the merger; should integration

issues cause the transition to take longer than w e expect, there could be dow nside risk to our estimates. Conversely, should sustained higher oil

prices result in higher E&P spending levels than w e now expect, our estimates could prove too low .

CLB We arrive at our price target of $170/sh by calibrating against our P/E valuation framew ork and our

discounted cash f low valuation methodology. Future estimated earnings grow th discounted by our cost of

capital implies a valuation range betw een a 28.4x multiple on 2014 EPS and a 26.0x multiple on our 2015 EPS

estimate. Our DCF valuation implies a value of $170/sh, given strong grow th over the explicit forecast,

reinvestment of capital, and a normalization of returns w ithout economic rents. Also, yield-based metrics

support our $170 target.

Since CLB’s largest customers conduct roughly 75% of their reservoir testing in-house, there is a risk that they w ill look to fully integrate their

reservoir diagnostics internally. If the major integrated oil companies w ere to bring their testing in-house, roughly 30% of CLB’s revenues may prove

at risk. Secondly, increased perforation product competition from the larger pressure pumping players, like HAL, BHI, and SLB, w ould challenge

economics for CLB. In addition, if discovery of reserves in less challenging basins shifts the sources of production, the need for more data,

diagnostic tests, and equipment may decline w hich w ould adversely impact CLB’s earnings. Finally, if macro factors reduce commodity demand,

resulting in a collapse of oil and natural gas prices, numerous f ields may prove uneconomic, leading to reduced upstream spending to the detriment

of CLB economics. If macro factors turn out stronger than our expectations, thus increasing commodity demand, operator spending may provide

upside to CLB earnings.

CRR We arrive at our price target of $55 per share by triangulating betw een our P/E valuation framew ork, yield-

based metrics, and our discounted cash f low valuation methodology. In our view , yield metrics may offer

support but investor focus on grow th and operating leverage w ill continue to drive shares through traditional

earnings and cash f low metrics. Future estimated earnings grow th discounted by our cost of capital implies

a valuation range betw een an 16.3x multiple on our 2014 EPS and a 17.6x multiple on our 2015 EPS estimate.

Our DCF valuation implies a value of $55 per share, given grow th expectations over the explicit forecast,

reinvestment of capital, and a normalization of returns. Given management’s desire to maintain grow th of a

sustainable dividend, potential upside may lie in yield-based metrics, w hich may magnify the benefit of

outsized returns, free cash f low grow th, and the emergence and communication of a fuller payout strategy.

Market Oversupply from Low er or Higher Quality Entrants. In our view , the threat of higher marginal cost Chinese supply likely caps the excess

returns that may be seen in the North American proppant business. The threat of heightened pricing volatility from poorly managed inventories,

given the presence of distributors, likely increases the amplitude of economics across the business cycle. Superior Product Takes Market Share.

CRR appears to be the innovator in the industry, especially w ith the upcoming introduction of proppant for deepw ater use. If a new or existing

player w ere to create a better product alternative, CRR’s economics may prove at risk. Service Intensity Declines Across Basins. Grow th in

reservoir complexity, unconventional plays, and deepw ater activity continue to drive service intensity. If discovery of reserves in less challenging

basins shifts the sources of production, the need for more and higher quality proppant may w ane, adversely affecting CRR’s economics. Capital

Budgeting. CRR may overbuild capacity or add lines w ithin plants too quickly, expanding f ixed overhead to the detriment of returns. Since it costs

$70-75M to add a production line w ithin a nine-month timeline, CRR might f ind it easy to create a hiccup if it does not have clarity on the means of

how to sell out the new line upon start of additional operations. Macroeconomic Risks and Commodity Price Decline. Oil prices have recently

declined. If oil prices declined too far, numerous f ields may prove uneconomic, leading to reduced upstream spending to the detriment of CRR

economics.

Macroeconomic and Commodity Price Strength. If macro factors turn out stronger than our expectations, thus increasing commodity demand,

operator spending may provide upside to CRR earnings. Positive Investor Sentiment and Short Covering. If investors become more optimistic on

North American oil & gas activity in 2015, CRR’s stock could rise. In the near term, short covering may keep upw ard pressure on shares.

FI FI currently trades at approximately 16x our 2014 EPS and 5x our 2014 EBITDA estimates. Our price target of

$27 is based on 20x our 2015 EPS and 11x our 2015 EBITDA estimates.

Given that FI generates an estimated 72% of its revenue offshore—the majority of w hich comes from DW and UDW projects that have a higher

degree of complexity and are subject to delays related to engineering and project management constraints at the operator level, grow th beyond

2015 may not accelerate as w e currently expect. In addition, should the changes mgmt has made over the last several quarters require a longer

transition period to produce results than w e now expect, there may be dow nside risk to our estimates.

OIS OIS currently trades at approximately 14x our 2014 EPS and 6x our 2014 EBITDA estimates. Our price target

of $60 is based on 13.3x our 2015 EPS and 6.6x our 2015 EBITDA estimates.

Should oil prices drop below $80/bbl for a quarter or more, w e believe OIS's Wellsite Services—both completion and drilling segments—w ould

experience a decline in revenues and earnings. Conversely, the stock could move higher on M&A speculation, as OIS is often talked about as a

takeover candidate due to the strength of its franchises and management team.

SPN We arrive at our price target of $26 per share by calibrating betw een our P/E valuation framew ork and our

discounted cash f low valuation methodology. Future estimated earnings grow th discounted by our cost of

capital implies a valuation range betw een a 14.5x multiple on our 2014 EPS estimate and a 11x multiple on our

2015 EPS estimate. Our DCF valuation implies a value of $25/sh, given strong grow th over the explicit

forecast, reinvestment of capital, and a normalization of returns.

Undisciplined Grow th in International Markets. Given SPN’s international grow th ambitions, if it w ere to take an undisciplined approach, adding large

f ixed costs ahead of potentially risky revenue streams, SPN profitability may suffer. Failure to properly leverage capital expenditure may adversely

impact returns and economics. Lack of Execution Removes Competitive Advantage from Completions Business. Many of SPN’s larger competitors in

the pressure pumping business either bundle services, gain share w ith scale, or offer more value added services (IP) in order to maintain their

market share lead. While raw horsepow er continues to commoditize in the face of over-supply, SPN w ill need to maintain crew s and service

reliability in order to differentiate its offering. Macroeconomic Risks and Commodity Price Decline. Oil prices have recently declined. If oil prices

declined too far, numerous f ields may prove uneconomic, leading to reduced upstream spending to the detriment of SPN economics.

North American Market Strength. If the North American services market reaches a positive inflection point in the near/medium term, SPN w ould likely

benefit given its high leverage to the region.

SLCA We arrive at our price target of $70 per share by triangulating betw een our P/E valuation framew ork, yield-

based metrics, and our discounted cash f low valuation methodology. In our view , yield metrics may offer

support, but investor focus on grow th and operating leverage w ill continue to drive shares through

traditional earnings and cash f low metrics. Future estimated earnings grow th discounted by our cost of

capital implies a valuation range betw een a 24.3x multiple on our 2014 EPS estimate and a 21.1x multiple on

our 2015 EPS estimate. Our DCF valuation implies a value of $70 per share, given grow th expectations over

the explicit forecast, reinvestment of capital, and a normalization of returns. Given the f irm’s ability to convert

to an MLP structure, potential upside may lie in yieldbased metrics, w hich may magnify the benefit of

outsized returns, free cash f low grow th, and a fuller payout strategy.

Risks to our investment thesis include a shift in the market tow ards frac sand alternatives such as ceramic proppants; increased regulation

surrounding either sand mining activities or hydraulic fracturing; SLCA's customer concentration, as SLCA's top ten customers represented 52% of

its sales revenue during 2013; a logistical disruption or cost increases pertaining to transportation and handling as transportation costs represent a

signif icant portion of the delivered cost of sand; plant dow ntime, namely at one of the f irm's major plants; and, an economic/cyclical dow nturn that

reduces commodity demand and prices. Economic cycles impact commodity prices, w hich in turn impact fracking activity and sand demand.

TESO TESO currently trades at approximately 18x our 2014 EPS and 6x our 2014 EBITDA estimates. Our price

target of $23 is based on 11.3x our 2015 EPS and 4.4x our 2015 EBITDA estimates.

Last year, TESO generated roughly $100mm in revenue from equipment sales and services in Russia; how ever, this year, Russia as an end market

should be closer to $60mm. Although the market has proven to be very lumpy in the $60-100mm range over the last several years, w e believe the

U.S. and E.U. sanctions have started to have an impact on the outlook—both in terms of TESO’s w illingness to take the credit risk associated w ith

Russian sales, as w ell as the actual capex budgets of TESO’s Russian customers. Consequently, w e w ould expect Russian revenue next year to

drop to +/-$25mm, w hich TESO has indicated to be its recurrent services revenue. We also believe that the risk to this revenue—along w ith the

sentiment surrounding TESO’s historical exposure to Russia—could w eigh on multiples as w ell.






AKSO We arrive at our price target of kr75/sh by calibrating against our P/E valuation framew ork and our

discounted cash flow valuation methodology. Future estimated earnings grow th discounted by our cost of

capital implies a valuation range betw een a 17.8x multiple on our 2014 EPS estimate and a 14x multiple on our

2015 EPS estimate. Our DCF valuation implies a value of kr125/sh, given strong grow th over the explicit

forecast, reinvestment of capital, and a normalization of returns w ithout economic rents.

Business Model Risk - The transition to a matrix business model that crosses regional management and product management in order to create a

single point of contact w ith customers poses a risk to existing client relationships that may threaten future orders. At the same time, the change in

management structure may also lead to supply chain and other execution issues. There is a risk that AKSO may choose to grow revenues by

underbidding the competition on price. Resultant low er margin business may challenge the company’s margin expansion goals.

DRC DRC currently trades at approximately 31x our 2014 EPS estimates, and 16x our 2014 EBITDA estimates;

after the announcement of the acquisition by SIE, w e expect the deal to be completed and therefore have

based our target price on the agreed upon value of $83/sh, w hich implies target multiples of 25.5x our 2015

EPS and 14.0x our 2015 EBITDA estimates.

As w ith any acquisition, there is alw ays risk that the deal does not go through, in w hich case there may be dow nside risk to our estimates. In

addition, there is risk that a third-party intervenes w ith a higher offer, in w hich case our expectations may prove too low . How ever, as w e have

stated previously, w e believe SIE presents the best industrial f it for DRC, and consequently believe that the stock w ill trade in a relatively tight range

around $83 until the deal is completed in 2Q15.

DRQ We arrive at our price target of $100/sh by calibrating against our P/E valuation framew ork and our


capital implies a valuation range betw een a 19.9x multiple on our 2014 EPS estimate and a 18.2x multiple on

our 2015 EPS estimate. Our DCF valuation implies a value of $100/sh, given strong grow th over the explicit

forecast, reinvestment of capital, and a normalization of returns w ithout economic rents.

Not Hedge Its Raw Material Inputs. Given that Dril-Quip does not hedge its steel or other inputs, the risk remains that rising input costs may erode

margins on its f ixed price equipment. Historically, management has successfully aligned costs and revenues through thoughtful coordination of

tender pricing and supply chain management. Product Adoption. Management is focused on its core competency in w ellheads and specialty

connectors, but they have allocated capital and budgeted manufacturing capacity for grow th in liner hangers, manifolds, subsea trees and control

systems. Despite our view that the company w ill utilize its current relationships to increase its presence in these products in the improving market,

there is a risk that a failure to gain traction w ith customers may hamper capacity utilization and performance. Macroeconomic Risks and Commodity

Price Decline. Oil prices have recently declined. If oil prices declined too far, numerous f ields may prove uneconomic, leading to reduced upstream

spending to the detriment of DRQ economics. Macroeconomic and Commodity Price Strength. If macro factors turn out stronger than our

expectations, thus increasing commodity demand, operator spending may provide upside to DRQ earnings.

FET We arrive at our price target of $40 per share by calibrating betw een our P/E valuation framew ork and our


capital implies a valuation range betw een an 21.9x multiple on 2014 EPS and a 17.3x multiple on our 2015

EPS estimate. Our DCF valuation implies a value of $40/share, given strong grow th over the explicit forecast,

reinvestment of capital, and a normalization of returns.

We see the ability to f inance an acquisition strategy through debt or to maintain a valuation multiple that provides an accretive equity currency as

potential risks. The company may face competition from larger competitors if they enter FET's specif ic markets. If macro factors reduce commodity

demand, resulting in a collapse of oil and natural gas prices, reduced upstream spending w ould negatively impact the company's operations. In

terms of positive risks, if the North American services market reaches a positive inflectiion point, FET w ould likely benefit gtiven its high leverage to

the region.

OII We arrive at our price target of $80/sh by calibrating against our P/E valuation framew ork and our discounted

cash flow valuation methodology. Future estimated earnings grow th discounted by our cost of capital implies

a valuation range betw een a 20.1x multiple on our 2014 EPS estimate and a 17.7x multiple on our 2015 EPS

estimate. Our DCF valuation implies a value of $80/sh, given strong grow th over the explicit forecast,

reinvestment of capital, and a normalization of returns w ithout economic rents.

Macroeconomic Risks and Commodity Price Decline. We assume that the ROV business grow s w ith the expansion of the offshore rigs f leet and the

acceleration of offshore drilling activity. That said, oil prices have recently declined w hich may cause operators to reevaluate or delay certain

projects in the nearerterm. If oil prices declined too far, numerous f ields may prove uneconomic, leading to reduced upstream spending to the

detriment of OII economics. Contract Rolls. A signif icant portion of OII’s ROVs rolling off contract in 2015 do not yet have new contracts negotiated.

If low er-spec drilling rig attrition occurs during 2015 w e could see a decrease in demand for OII’s yet-to-be contracted ROVs. Strong Offshore Rig

Fundamentals. Persistently high dayrates and favorable supply/demand dynamics in the offshore rig market may benefit earnings.






ATW We arrive at a price target of $55/sh. Our methodology w eighs our NAV - Break-Up, or liquidation value of

the company, and our NAV - Reinvestment Value, w hich discounts the value of assumed future investment

against our view of the company’s capital budgeting strategy and our future forecast of the offshore rig

market across asset classes.

Risks include construction (4 new builds), BOP maintenance dow ntime & dayrate exposure. Rig construction programs run the risk of costs and

delivery overruns that may impact earnings. Operational execution risk leaves the chance for higher maintenance costs and dow ntime that may

impact earnings. In a higher scrutiny, post-Macondo w orld, the risk of higher maintenance is prevalent. Economic cycles impact commodity prices,

w hich in turn impact drilling activity and rig demand. Thus, an economic dow nturn may negatively impact earnings pow er.

DO We arrive at a price target of $50/sh. Our methodology triangulates betw een NAV - Break-Up, NAV -

Reinvestment, and yield based valuation metrics. While NAV provides baseline support, w e derive our price

target against yield- based valuation metrics, w here w e probability w eight the timing and magnitude of future

dividends in relation to the current capital market for yield entities.

Should midw ater dayrates exceed expectations DO could outperform, dow nside risks include construction and strategy (favoring dividends over

more aggressive reinvestment). Operational execution risk leaves the chance for higher maintenance costs and dow ntime that may impact

earnings. In a higher scrutiny, post-Macondo w orld, the risk of higher maintenance is prevalent. Economic cycles impact commodity prices, w hich

in turn impact drilling activity and rig demand. Thus, an economic dow nturn may negatively impact earnings pow er.

ESV We arrive at a price target of $44/sh. Our methodology triangulates betw een NAV - Break-Up, NAV -




Risks include construction and GOM exposure. Operational execution risk leaves the chance for higher maintenance costs and dow ntime that may

impact earnings. In a higher scrutiny, post-Macondo w orld, the risk of higher maintenance is prevalent. A potential overbuild w ithin any segment of

the rig market can depress dayrates and shorten contract durations to the detriment of earnings. Economic cycles impact commodity prices, w hich

in turn impact drilling activity and rig demand. Thus, an economic dow nturn may negatively impact earnings pow er.

HERO We arrive at a price target of $1.50/sh. Our methodology triangulates betw een NAV - Break-Up, NAV -




Risks include construction (1 new build) and GOM exposure. Operational execution risk leaves the chance for higher maintenance costs and

dow ntime that may impact earnings. In a higher scrutiny, post-Macondo w orld, the risk of higher maintenance is prevalent. A potential overbuild

w ithin any segment of the rig market can depress dayrates and shorten contract durations to the detriment of earnings. Economic cycles impact

commodity prices, w hich in turn impact drilling activity and rig demand. Thus, an economic dow nturn may negatively impact earnings pow er.

Persistently high dayrates and favorable supply/demand dynamics may benefit earnings.

NE We arrive at a price target of $30/sh. Our methodology triangulates betw een NAV - Break-Up, NAV -




Risks include construction (12 new builds), GOM and Mexico exposure, and RoF exposure. Given the volatility of contract dayrates and contract

terms, the company maintains a risk of low bids as the rig market improves as w ell as a false confidence in bargaining pow er as the market

declines. Rig construction programs run the risk of costs and delivery overruns that may impact earnings. Operational execution risk leaves the

chance for higher maintenance costs and dow ntime that may impact earnings.

ORIG We arrive at a price target of $15/sh. Our methodology triangulates betw een NAV - Break-Up, NAV -




Risks include construction (4 new builds). Given the volatility of contract dayrates and contract terms, the company maintains a risk of low bids as

the rig market improves as w ell as a false confidence in bargaining pow er as the market declines. Rig construction programs run the risk of costs

and delivery overruns that may impact earnings. Operational execution risk leaves the chance for higher maintenance costs and dow ntime that may

impact earnings. ORIG's relationship w ith DRYS may leave it exposed to unpalatable agency risk and dry bulk shipping exposure.

PACD We arrive at a price target of $14/sh. Our methodology w eighs our NAV - Break-Up, or liquidation value of




Risks include construction (4 new builds) and BOP maintenance dow ntime. Rig construction programs run the risk of costs and delivery overruns

that may impact earnings. Operational execution risk leaves the chance for higher maintenance costs and dow ntime that may impact earnings. In a

higher scrutiny, post-Macondo w orld, the risk of higher maintenance is prevalent. Economic cycles impact commodity prices, w hich in turn impact

drilling activity and rig demand. Thus, an economic dow nturn may negatively impact earnings pow er.

RDC We arrive at a price target of $25/sh. Our methodology w eighs our NAV - Break-Up, or liquidation value of




Risks include construction (4 new builds) and entry into new markets, w hich could potentially carry higher costs (UDW and SE Asia). Given the

volatility of contract dayrates and contract terms, the company maintains a risk of low bids as the rig market improves as w ell as a false confidence

in bargaining pow er as the market declines. Rig construction programs run the risk of costs and delivery overruns that may impact earnings. A

potential overbuild w ithin any segment of the rig market can depress dayrates and shorten contract durations to the detriment of earnings.

Persistently high dayrates and favorable supply/demand dynamics may benefit earnings.

RIG We arrive at a price target of $45/sh. Our methodology triangulates betw een NAV - Break-Up, NAV -

Reinvestment, and yield-based valuation metrics. While NAV provides baseline support, w e derive our price

target against yield-based valuation metrics, w here w e probability-w eight the timing and magnitude of future


Macondo involvement remains a risk to the dow nside. Given the volatility of contract dayrates and contract terms, the company maintains a risk of

low bids as the rig market improves as w ell as a false confidence in bargaining pow er as the market declines. Operational execution risk leaves the

chance for higher maintenance costs and dow ntime that may impact earnings. In a higher scrutiny, post-Macondo w orld, the risk of higher

maintenance is prevalent. Economic cycles impact commodity prices, w hich in turn impact drilling activity and rig demand. Thus, an economic

dow nturn may negatively impact earnings pow er.

SDRL We arrive at a price target of $50/sh. Our methodology triangulates betw een NAV - Break-Up, NAV -

Reinvestment, and yield-based valuation metrics. While NAV provides baseline support, w e derive our price

target against yield-based valuation metrics, w here w e probability-w eight the timing and magnitude of future


Risks include construction (16 rig new builds) and f inancial leverage, SDRL is the most levererd name in our group. Rig construction programs run

the risk of costs and delivery overruns that may impact earnings. Operational execution risk leaves the chance for higher maintenance costs and

dow ntime that may impact earnings. In a higher scrutiny, post-Macondo w orld, the risk of higher maintenance is prevalent. A potential overbuild

w ithin any segment of the rig market can depress dayrates and shorten contract durations to the detriment of earnings.

HP HP currently trades at approximately 6x our 2014 EBITDA and 8x our 2014 CFPS estimates. Our 12-month

price target of $110 is based on 16.0x our CY2015 EPS estimate and 6.5x our CY2015 EBITDA estimate.

Given our outlook that improved E&P liquidity due to higher Brent prices, the new condensate export relief valve, and continued capital markets

activity, should provide ample room for NA spending to continue to grow ~10% this year and next, w e expect utilization to remain ~90% and drive

earnings grow th of nearly 10% next year. How ever, should Brent begin to w eaken and saturation risk begin to w eigh on NA fundamentals going

into the end of 2014, our estimates may prove too high.

NBR NBR currently trades at approximately 5x our 2014 EBITDA and 3x our 2014 CFPS estimates. Our price target

of $32 is based on 14.0x our 2015 EPS estimate and 5.5x our 2015 EBITDA estimate.

The deal w ith CJES gives NBR the opportunity to refocus on its core drilling operations, thus allow ing NBR to benefit from the streamlining of its

portfolio as w ell as a “sum of the parts” valuation boost resulting from a real-time mark-to-market mechanism in CJES stock. How ever, should the

deal be delayed in getting approved, there may be dow nside risk to our estimates. On the other hand, should the deal be approved and the tw o

companies begin to realize synergies faster than w e now expect, w e submit our estimates may prove too conservative.

PTEN PTEN currently trades at approximately 4x our 2014 EBITDA and 4x our 2014 CFPS estimates. Our 12-month

price target of $40 is based on 5.5x our 2015 EBITDA and 5.5x our 2015 CFPS estimates.

We continue to believe that the market for AC-electric rigs remains under-supplied and that PTEN has emerged as a real leader in the AC market as

a result of the eff iciency of its APEX fleet and w orkforce. With our current outlook for improved E&P liquidity heading into 2015, w e expect this w ill

translate into continued market share grow th as heightened focus on eff iciency has led customers to prefer AC market leaders such as PTEN.

How ever, should NA fundamentals begin to break dow n due to Brent w eakness or unforeseen roadblocks in the condensate export relief valve,

commodity price w eakness may have a negative effect on E&P spending going into 2015, in w hich case our estimates may prove too high.

SSE SSE currently trades at approximately 5x our 2014 EBITDA and 2x our 2014 CFPS estimates. Our 12-month

price target of $33 is based on 5.5x our 2015 EBITDA and 3.5x our 2015 CFPS estimates.

Over the next 12 months, w e see tw o major risks, including 1) SSE's dependence on CHK and 2) operating leverage. With 80% of its revenue linked

to the capex budget of just one company, SSE has a level of customer dependence that is far greater than any of its peers. In addition, w hile w e've

identif ied that operating leverage is a source of potential upside for SSE, should PTL's margins begin to erode due to rising consumables costs,

labor, job ineff iciency, etc., the EPS leverage could cut the other w ay.



Appendix 1: Rig Status Definitions

RIG Status Definitions

Acceptance Testing - Either post newbuild delivery or pre-contract testing

Accommodation - Temporary accommodation mode

Accident - Operations on hold due to accident/incident

Cold stacked - Watch crew only. Equipment mothballed. Requires several months to reactivate

Drilling - Any operation related to a drilling contract

En Route - Rig is moving between two regions

Hot Stacked - Idle rig is crewed and ready to mobilize at short notice

In Port - At inshore location eg. offloading 3rd party equipment, sorting out ship’s papers

Moving to Location - Rig move between two countries or within one country

On Order - Newbuild order placed but construction yet to begin

Other - On contract activity other than Drilling, Accommodation, Production or Support

Out of Service - Not capable of re-entering service without major equipment upgrade/renewal taking minimum 6-12 months

Production - Temporary production mode

Retired - Rig is no longer part of drilling rig fleet.

Rigging Down - Platform rig demob (take down)

Rigging Up - Platform rig set up

Standby - Waiting at a location to begin another activity

Support - Temporary support mode (platform installs, hurricane restoration, recovery work, etc.)

Under Construction - Newbuild under construction

Warm Stacked - Maintenance crew only but ready to mob at relatively short notice

WOW - Waiting on weather

Yard - Shipyard or rig inspection/repair at shipyard, inshore or offshore location




Appendix 2: Additional Companies Mentioned

Source: Guggenheim Securities, Bloomberg

Note: All prices in USD; as of 11/12/14 close

Additional Companies Mentioned Ticker Last Price Rating Additional Companies Mentioned Ticker Last Price Rating

1 Anadarko APC US $91.4 BUY 38 Arktikmor Not Public - NOT PUBLIC

2 ConocoPhillips COP US $71.2 BUY 39 BRASFELS Not Public - NOT PUBLIC

3 Marathon MRO US $32.7 BUY 40 Caspian Drilling Not Public - NOT PUBLIC

4 Apache APA US $73.7 NEUTRAL 41 COSL Not Public - NOT PUBLIC

5 Hess Hes US $82.5 NEUTRAL 42 Crosco Not Public - NOT PUBLIC

6 Japan Drilling 1606 JT $36.3 NOT COVERED 43 Deepwater Drilling & Services Not Public - NOT PUBLIC

7 North Atlantic Drilling NADL US $4.9 NOT COVERED 44 Ecovix-Engevix Not Public - NOT PUBLIC

8 Transocean Partners RIGP US $20.0 NOT COVERED 45 Essar Oilfields Services Not Public - NOT PUBLIC

9 Seadrill Partners SDLP US $22.4 NOT COVERED 46 Estaleiro Atlantico Sul Not Public - NOT PUBLIC

10 Sinopec 386 HK $0.8 NOT COVERED 47 Estaleiro Enseada do Paraguacu Not Public - NOT PUBLIC

11 Aban Offshore ABAN IN $10.2 NOT COVERED 48 Estaleiro Jurong Aracruz Not Public - NOT PUBLIC

12 Maersk Drilling AMKBY US $10.5 NOT COVERED 49 Etesco Not Public - NOT PUBLIC

13 Awilco Drilling AWDR NO $15.3 NOT COVERED 50 Etesco / OAS Not Public - NOT PUBLIC

14 Keppel FELS KEP SP $7.2 NOT COVERED 51 Friede Goldman Offshore Not Public - NOT PUBLIC

15 Dolphin (Fred Olsen) FOE NO $12.2 NOT COVERED 52 Frigstad Offshore Not Public - NOT PUBLIC

16 Odfjell Drilling ODL NO $3.0 NOT COVERED 53 Gazflot Not Public - NOT PUBLIC

17 Odfjell Galvao ODL NO $3.0 NOT COVERED 54 Gryphon Energy Not Public - NOT PUBLIC

18 ONGC ONGC IN $6.4 NOT COVERED 55 IPC Not Public - NOT PUBLIC

19 Petrobras PBR US $10.6 NOT COVERED 56 Jet Drilling Not Public - NOT PUBLIC

20 Paragon Offshore PGN US $4.8 NOT COVERED 57 Jurong Not Public - NOT PUBLIC

21 Songa Offshore SONG NO $0.3 NOT COVERED 58 KEPCO Not Public - NOT PUBLIC

22 Songa Opus Offshore Drilling song no $0.3 NOT COVERED 59 KNOC Not Public - NOT PUBLIC

23 Saipem SPM IM $16.0 NOT COVERED 60 LLOG Not Public - NOT PUBLIC

24 Vantage Drilling VTG US $0.9 NOT COVERED 61 Nexen Not Public - NOT PUBLIC

25 Statoil STL NO $22.3 NOT COVERED 62 North Sea Rigs Not Public - NOT PUBLIC

26 BP BP US $41.2 NOT COVERED 63 Odebrecht Not Public - NOT PUBLIC

27 Shell RDSA NA $35.0 NOT COVERED 64 PEMEX Not Public - NOT PUBLIC

28 Total FP FP $57.1 NOT COVERED 65 Petro SA Not Public - NOT PUBLIC

29 Chevron CVX US $117.7 NOT COVERED 66 PetroSaudi Not Public - NOT PUBLIC

30 Eni ENI IM $20.1 NOT COVERED 67 Petroserv Not Public - NOT PUBLIC

31 ExxonMobil XOM US $95.4 NOT COVERED 68 QGOG Constellation Not Public - NOT PUBLIC

32 Murphy MUR US $52.5 NOT COVERED 69 Queiroz Galvao Not Public - NOT PUBLIC

33 Woodside WPL AU $35.1 NOT COVERED 70 Rig Management Nor. Not Public - NOT PUBLIC

34 BG BG/ LN $16.3 NOT COVERED 71 Schahin Not Public - NOT PUBLIC

35 Freeport-McMoRan Oil & Gas FCX US $28.6 NOT COVERED 72 SOCAR Not Public - NOT PUBLIC

36 Tullow Oil TLW LN $7.8 NOT COVERED 73 Stena Not Public - NOT PUBLIC

37 Talisman Sinopec TLM US $5.7 NOT COVERED



ANALYST CERTIFICATION

By issuing this research report, each Guggenheim Securities, LLC ("Guggenheim Securities") research analyst whose name appears in this report hereby certifies that (i) all of the views expressed in thisreport accurately reflect the research analyst's personal views about any and all of the subject securities or issuers discussed herein and (ii) no part of the research analyst's compensation was, is, or will bedirectly or indirectly related to the specific recommendations or views expressed by the research analyst.

IMPORTANT DISCLOSURESThe research analyst(s) and research associate(s) have received compensation based upon various factors, including quality of research, investor client feedback, and Guggenheim Securities, LLC's overallrevenues, which includes investment banking revenues.

Guggenheim Securities, LLC or its affiliates expect(s) to receive or intend(s) to seek compensation for investment banking services from Atwood Oceanics, Inc., Diamond Offshore Drilling Inc., Ensco plc,Hercules Offshore, Inc., Noble Corp., Ocean Rig UDW Inc., Rowan Companies Inc., Seadrill Ltd., Transocean Ltd. and Pacific Drilling S.A. in the next 3 months.

Please refer to this website for company-specific disclosures referenced in this report: https://guggenheimsecurities.bluematrix.com/sellside/Disclosures.action. Disclosure information is also available fromCompliance, 330 Madison Avenue, New York, NY 10017.

RATING DEFINITIONSBUY (B) - Describes stocks that we expect to provide a total return (price appreciation plus yield) of 15% or more within a 12-month period.NEUTRAL (N) - Describes stocks that we expect to provide a total return (price appreciation plus yield) of plus 15% or minus 15% within a 12-month period.SELL (S) - Describes stocks that we expect to provide a total negative return (price appreciation plus yield) of 15% or more within a 12-month period.NR - The investment rating and price target have been temporarily suspended. Such suspensions are in compliance with applicable regulations and/or Guggenheim Securities, LLC policies.CS - Coverage Suspended. Guggenheim Securities, LLC has suspended coverage of this company.NC - Not covered. Guggenheim Securities, LLC does not cover this company.



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Restricted - Describes issuers where, in conjunction with Guggenheim Securities, LLC engagement in certain transactions, company policy or applicable securities regulations prohibit certain types ofcommunications, including investment recommendations.

Monitor - Describes stocks whose company fundamentals and financials are being monitored, and for which no financial projections or opinions on the investment merits of the company are provided.

Guggenheim Securities, LLC methodology for assigning ratings may include the following: market capitalization, maturity, growth/value, volatility and expected total return over the next 12 months. The pricetargets are based on several methodologies, which may include, but are not restricted to, analyses of market risk, growth rate, revenue stream, discounted cash flow (DCF), EBITDA, EPS, cash flow (CF),free cash flow (FCF), EV/EBITDA, P/E, PE/growth, P/CF, P/FCF, premium (discount)/average group EV/EBITDA, premium (discount)/average group P/E, sum of the parts, net asset value, dividend returns,and return on equity (ROE) over the next 12 months.

RATINGS DISTRIBUTIONS FOR GUGGENHEIM SECURITIES:IB Serv./ Past 12Mos.

Rating Category Count Percent Count Percent

Buy 108 59.67% 19 17.59%

Neutral 73 40.33% 4 5.48%

Sell 0 0.00% 0 0.00%

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We and our affiliates, officers, directors, and employees, excluding equity and credit analysts, will from time to time have long or short positions in, act as principal in, and buy or sell, the securities or derivatives,if any, referred to in this research. We and our affiliates also may sell to or buy from customers on a principal basis the securities described herein. We and our affiliates also do business with, or that relatesto, companies covered in Guggenheim Securities’ research, and may have a position in the debt of the company or companies discussed herein.

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TACTICAL TRADING IDEA DISCLAIMERGuggenheim Securities, LLC produces "Tactical Trade Ideas" that identify short-term, catalyst-driven trading opportunities impacting companies within the Firm’s coverage universe. Tactical Trade Ideas mayexist on companies in this report and may be contrary to the analyst’s published rating.

Copyright © 2014 by Guggenheim Securities, LLC, ("Guggenheim") a FINRA registered broker-dealer. All rights reserved. The contents of this report are based upon information or are obtained from sourcesthat Guggenheim generally considers reliable, but Guggenheim makes no representations or warranties with respect to their accuracy, completeness, timeliness, suitability or otherwise, and assumes noresponsibility to update them for subsequent events or knowledge. Guggenheim is not responsible for your use of this information.



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