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

June 2, 2014

“Second Derivative” Leads Drivers, Despite Near-Term Dayrate Headwinds

Darren Gacicia

(212) 293-3054

[email protected]

GUGGENHEIM SECURITIES, LLC See pages 58 - 59 for analyst certification and important disclosures.

This report is intended for Darren.G

acicia@guggenheim

partners.com at G

uggenheim. U

nauthorized distribution of this report is prohibited.

“Second Derivative” Leads Drivers, Structural Story Positive Backdrop Tough 2014 Apparent, Improving “Second Derivative” Sets New Tone. A fresh look at 2014 floater demand, given project delays and little credit for non-FID demand

indications for 2014, infers a significant oversupply to us. Ultimately, consensus sentiment reflects anticipated sloppy contracting, so we do not see incremental negative

fixtures as meaningful negative catalyst for shares. The ―second derivative‖ of rig demand, which improves per our analysis of 2015 (pg. 10), will likely drive the group from

here. Recent comments across the industry supported a 2015/2016 resumption of offshore projects, which offsets more dire sentiment and supports our ―shorter &

shallower‖ thesis. We underestimated the impact of project delays in prior analysis, but continue to see the need for drilling to meet IOC production & dividend targets,

leveraged to offshore project development (~30-40% of new source production, pg. 29). Investors may renew their focus production targets, if payout strategies see cash

flow risks. Meanwhile, investor-driven capital budget vetting may have spurred project redesign, lower cost production solutions, and confirmation of favorable project

IRR‘s will justify the majority of offshore projects (Kaomba in Angola & Mad Dog in Gulf of Mexico), as highlighted in our Gulf of Mexico report (3/14/14). We suspect

market discussions of 2015 budgets, beginning fall 2014, may show progress and set a roadmap for a more bullish outlook, the next positive catalyst for offshore drillers.

“Shorter” Tailwind, “Shallower” Headwind. Positive commentary during the 1Q14 earnings season comforted investors regarding the duration of the downturn,

satisfying our ―shorter‖ thesis, and stoking a rally in offshore driller shares. With a turn of sentiment in progress, negative fixtures by contractors fighting to maintain rig

utilization may challenge a ―shallower‖ thesis for the remainder of 2014. Post a ~10% rally from March/April lows for the offshore drillers (vs. 5% for the OSX), shares

continue to screen attractively (pgs. 5-8), but the easier long trade from ―peak pessimism‖ and trough price/tangible book valuations looks more mature (see Offshore

Drilling Shares Reflect Cyclical Lows, Fundamentals Do Not, 1/27/14). Stocks have stopped going down on bad news, but negative floater contract optics may leave

offshore driller shares range-bound until rig demand visibility for 2015 and beyond adds a new leg to the story. We would use volatility to buy SDRL (BUY, $38.00) & ESV

(BUY, $52.66) within large caps, and ATW (BUY, $49.35) & PACD (BUY, $10.14) among small/mid caps.

Drive Toward Efficiency & Returns a Tailwind, Not a Capital Budgeting Headwind. If the market factors the current pause/delay in offshore projects as a push for

higher payouts alone, investors may miss brewing strategic industry changes that may improve underlying project economics through faster times to first production, lower

production infrastructure costs, and project management efficiency (project throughput vs. headcount). In our view, the industry‘s renewed returns focus will center on

reduced engineering and increased equipment standardization, as suggested by FTI ‗s (BUY, $58.06)1Q14 commentary. Mix shift toward more complex & deepwater

projects (pgs. 31-33) heightened project engineering to the component level. With the move up the learning curve, the industry may begin to pursue standardized solutions,

decrease engineering expenses (~20% of unit costs), and free internal project management personnel to handle more projects. Not apparent in projects in-progress that

are likely set in current designs, a new approach to project management efficiency may improve project returns by increasing project throughput, given the same

headcount/overhead . Drilling efficiency may improve and well-to-rig ratios may fall, but the total number of projects scheduled for development over the next five years

provides a significant inventory of work for a more efficient system. Bullish offshore equipment /services outlooks support higher project velocity, disconnected with bearish

rig demand outlooks, which supports a near term recovery in offshore activity.

New Dayrate Forecast Reflects 2015 Inflection. A dayrate recovery will likely lag the recovery in demand, given the need to absorb slack capacity and shift perceptions

of market power. Thus, we see floater dayrates finding their trough in 1H15 and beginning to improve in 2H15, as demand recovers (pg. 22). We continue to see jackup

dayrates fading lower, as we see the arrival of a large number of uncontracted newbuilds challenge offshore driller negotiating power, despite current visibility for a tight

market through 2015. We have reorganized our floater dayrate forecast and valuation forecasts by rig generation and the relative specifications within each generation

class. The reclassification exercise allowed for a more granular dayrate forecasts and a better account of the ―normalized‖ earnings power of rigs , based on our view that

―normalized‖ dayrates will allow rigs to earn their cost of capital (~9%), relative to the cost of construction across classes.

Sensitivities Add a Positive to the Outlook. Even after assuming that very few projects are sanctioned and make 2014 & 2015 demand, we still see improved floater

market balances before the end of 2015 (pg. 10-12). If we assume that delayed projects do not go away, but carry to the next year, the market tightens further. The market

looks set to move from a double digit floater surplus in 2014 to a more balanced market in 2015. A total of 18 floaters currently uncontracted, either hot stacked, warm

stacked, or in the shipyard, have helped balances (pg. 19), We see 60 rigs, near 30 years old and on the low end of the specification range, rolling off contract in the next

two years as candidates for stacking/retirement. As highlighted on SDRL‘s call, there are over 50 floaters require to undergo their 30 year special survey in the next 24

months (pg. 20), which will likely require a prohibitive amount of investment in order to maintain top classification. Some of these rigs may also face cold

stacking/retirement. Similarly, if likely delays to Brazil-sponsored newbuilds materialize (6 floater deliveries/year 2016-2018), medium term floater dynamics should become

more favorable. We have not factored any potential retirements into our supply forecast, which may translate into tighter balances than the market currently assumes.

Guggenheim Securities, LLC | 972-638-5502 | guggenheimsecurities.com

<p>Oilfield Services & Offshore Drillers</p> PAGE 2

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EPS Lower Under New Dayrate Forecast Ticker Company Category 2013 2014E 2015E 1Q13 2Q13 3Q13 4Q13 1Q14E 2Q14E 3Q14E 4Q14E

ATW Atwood Oceanics EPS 5.32 4.95 6.80 1.10 1.28 1.37 1.57 1.28 0.78 1.26 1.62

Previous EPS 5.32 5.00 7.10 0.78 1.31 1.62

Consensus EPS 5.02 7.36 0.97 1.17 1.69

Consensus EPS-High 5.60 8.36 1.33 1.64 2.02

Consensus EPS-Low 4.53 5.87 0.71 0.97 1.42

DO Diamond Offshore EPS 4.77 4.10 5.60 1.26 1.33 1.22 0.96 0.93 0.90 1.10 1.16

Previous EPS 4.77 4.45 6.50 0.93 1.28 1.31

Consensus EPS 3.71 4.70 0.67 0.98 1.17



ESV Ensco EPS 6.16 5.60 6.00 1.36 1.55 1.69 1.56 1.23 1.47 1.59 1.31

Previous EPS 6.16 5.85 6.90 1.53 1.64 1.44

Consensus EPS 5.68 5.87 1.37 1.51 1.57



HERO Hercules Offshore EPS 0.24 0.55 0.05 (0.02) 0.01 0.11 0.14 0.22 0.10 0.11 0.12

Previous EPS 0.24 0.50 0.07 0.06 0.11 0.11

Consensus EPS 0.55 0.57 0.03 0.11 0.18


Consensus EPS-Low 0.37 0.07 (0.01) 0.03 0.07

NE Noble Drilling EPS 2.89 3.70 3.90 0.59 0.63 0.85 0.82 1.03 0.67 0.92 1.07

Previous EPS 2.89 3.85 4.75 0.70 0.94 1.18

Consensus EPS 3.42 3.89 0.66 0.85 0.92



ORIG Ocean Rig UDW EPS 0.84 2.00 2.65 0.04 0.19 0.30 0.30 0.24 0.47 0.66 0.63

Previous EPS 0.77 2.10 3.05 0.50 0.70 0.66

Consensus EPS 1.72 2.20 0.37 0.62 0.56



PACD Pacific Drilling EPS 0.42 0.95 1.25 0.07 0.10 0.14 0.12 0.10 0.21 0.26 0.37

Previous EPS 0.42 0.95 1.30 0.21 0.26 0.38

Consensus EPS 0.78 1.25 0.18 0.23 0.27



RDC Rowan EPS 1.96 2.60 4.80 0.55 0.57 0.42 0.42 0.28 0.29 0.75 1.28

Previous EPS 1.96 2.65 4.80 0.32 0.78 1.27

Consensus EPS 2.40 4.26 0.29 0.69 1.09



RIG Transocean EPS 4.12 4.60 4.00 0.93 1.08 1.37 0.73 1.43 1.24 1.00 0.92

Previous EPS 4.12 5.00 4.60 1.33 1.14 1.10

Consensus EPS 4.30 3.64 1.12 0.87 0.82



SDRL Seadrill EPS 3.02 3.25 3.10 0.69 0.96 0.60 0.79 0.59 0.63 0.57 0.67

Previous EPS 3.02 3.30 4.05 0.82 0.86 0.92

Consensus EPS 3.40 3.65 0.68 0.83 0.83 0.89

Consensus EPS-High 8.36 4.55 0.74 1.08 0.92 1.03

Consensus EPS-Low 2.90 2.74 0.56 0.65 0.68 0.73

Source: Thomson Reuters., Guggenheim Securities, LLC.



Positive Leverage for Shares: Asset Quality & Capital Strategies

Leveraged to a Turn in Fundamentals

SDRL – BUY – PT $50 : Delivery of newbuilds &

accretive financing from SDLP (NC, $32.54) offers

upside leverage to distributions and yield-based

valuations. The recent SDLP unit issuance near 6-7%

yields & NADL/Rosneft deal remain positive indicators.

ESV – NEUTRAL – PT $60: Discount to NAV screens

well, with an opportunity for upside with an emerging

track record for its distribution policy, which may

include dividends and share repurchases.

ATW – BUY – PT $58: Attractive growth profile, solid

execution, and potential for future payout-friendly bias.

PACD – BUY – PT $14: Good management, pure-play

ultra-deepwater assets, recent favorable refinancing,

and longer term dividend bias offer meaningful upside

potential.

DO – BUY – PT $65: Overly slighted for its older fleet,

we like DO‘s high payout strategy. We see a more

positive outlook for the rig markets removing the

overhang created by risks to DO‘s older fleet.

Trapped in Multiple Compression

RDC – NEUTRAL – PT $36: Trading closer to NAV,

we see potential for continued multiple compression

as investors infer higher capital budgeting risk , with

the need for scale in its floater fleet or a payout

strategy to give better leverage to its cash flow

profile.

HERO – NEUTRAL – PT $5: Peak-cycle

economics and stretched balance sheet create a

challenging risk/reward, despite solid execution on

recent newbuilds and a good management team.

ATW & PACD: Attractive fleets and

cash flow profiles may see offsets in

slowed growth plans and more distant

term payout strategies.

NE: Concerns about Paragon & capital

budgeting.

ORIG: Concerns about unconventional

ownership and corporate structure may

challenge the story for the shares.

RIG: We see alpha in pot. strategic change,

but need to see execution on fleet renewal &

accretive financing .

SDRL: Investors remain concerned about the

dividend amidst the downturn in dayrates.

Special Situations – Transaction/Catalyst Driven

NE – BUY – PT $42: Potential for further upside on

spin-off of older asset and yield re-rate of premium

assets. Paragon transaction provides a catalyst.

ORIG – BUY – PT $28: The need for cash and ORIG

shares as a source of funding at DRYS should prompt

a dividend strategy from ORIG and efforts to re-rate the

shares on yield-based metrics.

RIG – BUY – PT $55: Meaningful discount to NAV

leaves hope that activist involvement and reformulated

Board of Directors, with renewed dividend policy and

MLP plans, will lead shares to mean-revert.



Large Cap Services 8.4 x

Large Cap Equipment 9.6 x

Small/Mid Cap Svcs &

Equipment 10.3 x

Offshore Drilling 7.2 xOnshore Drilling

6.5 x

Engineering & Construction 8.1x

5.0 x

6.0 x

7.0 x

8.0 x

9.0 x

10.0 x

11.0 x

0% 5% 10% 15% 20% 25%E

V/E

BIT

DA

'14E

EBITDA Growth, '14E vs. '13E

Large Cap Services 8.4 x

Large Cap Equipment 9.6 x

Small/Mid Cap Svcs &

Equipment 10.3 x

Offshore Drilling 7.2 x Onshore Drilling

6.5 x

Engineering & Construction 8.7

x

5.5 x

6.5 x

7.5 x

8.5 x

9.5 x

10.5 x

11.5 x

10.0 x 12.0 x 14.0 x 16.0 x 18.0 x 20.0 x 22.0 x

EV

/EB

ITD

A '14E

Price/Earnings '14E

Offshore Drillers Continue to Screen Well Against Other OFS Segments

Source: Thomson Reuters., Guggenheim Securities, LLC.

2014E P/E vs. 2014E EV/EBITDA- Sub Sectors ‟14E Y/Y EBITDA Growth vs. 2014E EV/EBITDA- Sub Sectors

The mix of low valuations, high

cash flow, and overblown

negative sentiment about rig

supply/demand balances leave

offshore drillers screening

attractively within the group.

We see a potential for rotation out of high

multiple/high growth expectation stocks

with North American leverage into lower

multiple stocks with more visible earnings

growth that screen more attractively, like

the offshore drillers.



ATW

DO

ESV

NE

PACD

RDC

RIG

SDRL

HERO

ORIG

4.00

5.00

6.00

7.00

8.00

9.00

10.00

5% 7% 9% 11% 13% 15% 17%

2014E E

V/E

BIT

DA

2015E EBITDA/Gross Fleet Value

ATW

DO

ESV

NE

PACD

RDC

RIG

SDRL

HERO

ORIG

3.00

4.00

5.00

6.00

7.00

8.00

9.00

10.00

-3.50 -3.00 -2.50 -2.00 -1.50 -1.00 -0.50 0.00 0.50 1.00

2014E E

V/E

BIT

DA

Total FCF ($B) 2Q13E-4Q15E

ATW

DO

ESV

NE

PACD

RDC

RIG

SDRL

HERO

ORIG

4.00

5.00

6.00

7.00

8.00

9.00

10.00

0% 10% 20% 30% 40% 50% 60%

2014E E

V/E

BIT

DA

Net Debt/Gross Fleet Value

ATW

DO

ESV

NE

PACD

RDC

RIG

SDRL

ORIG

4.00

4.50

5.00

5.50

6.00

6.50

7.00

7.50

8.00

8.50

9.00

9.50

10.00

0 5 10 15 20 25 30

2014E E

V/E

BIT

DA

Average Fleet Age (years)

Investors continue to reward smaller

cap names with clearly defined

growth strategies, a bias toward a

higher payout model in the medium

to long term, and newer fleets.

Multiple Compression Reflects Capital Budgeting & Fleet Age Concerns

Net Debt „15/Gross Fleet Value vs. EV/EBITDA FCF Growth vs. EV/EBITDA

SDRL helped

by leverage,

full payout,

and pot.

benefits from

SDLP

financing.

The inverse relationship between

free cash flow (FCF) growth and

multiples suggests concerns

about the dilution of return

structures and risks to

incremental growth investment.

„15 EBITDA/Gross Fleet Value vs. EV/EBITDA Fleet Age vs. EV/EBITDA

Source: IHS Inc. Thomson Reuters, Guggenheim Securities, LLC



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

Company Rating 5/30 Target PX

Rtn to

Target

2014

PE

2015

PE

2014

EV/EBITDA

2015

EV/EBITDA

EV/EBITDA

'14

EV/EBITDA

'15 2014E 2014E 2014E 2014E

ATW Buy 49$ $58 18% 11.7x 8.5x 10.0x 7.3x 7.7x 5.7x 58 66 85% 75%

DO Buy 51$ $65 27% 15.9x 11.6x 12.5x 9.1x 5.3x 4.0x 59 61 87% 84%

ESV Buy 53$ $60 14% 10.7x 10.0x 9.4x 8.8x 6.9x 6.2x 60 60 88% 88%

HERO Neutral 5$ $5 10% 9.1x 100.0x 8.3x 90.8x 4.7x 6.3x 5 5 91% 91%

NE Buy 31$ $42 34% 11.4x 10.8x 8.5x 8.1x 5.4x 5.0x 42 42 75% 75%

ORIG Buy 18$ $28 54% 14.0x 10.6x 9.1x 6.8x 7.0x 6.2x 28 28 65% 65%

PACD Buy 10$ $14 34% 14.7x 11.2x 11.0x 8.3x 8.1x 5.9x 14 14 74% 74%

RDC Neutral 31$ $36 16% 13.8x 7.5x 11.9x 6.4x 7.1x 4.7x 36 43 86% 72%

RIG Buy 42$ $55 29% 12.0x 13.8x 9.2x 10.6x 6.3x 6.8x 55 55 77% 77%

SDRL Buy 38$ $50 32% 15.4x 16.1x 11.7x 12.3x 9.4x 9.1x 29 34 131% 112%

Averages 10.1x 16.9x 6.8x 6.0x 86% 81%

Target Current

NAV Comparison of Offshore Drillers Sees Shares Screen Attractively

Source: IHS Inc. Thomson Reuters, Guggenheim

Securities, LLC

Offshore drillers trade at a significant discount to NAV, suggesting a favorable

risk/reward

Gross Fleet Value Breakdown Estimated EBITDA Breakdown, 2015

Most of our Gross Fleet Value and EBITDA estimates

are derived from jackups, drillships, and 6G

semisubmersibles, but 15-16% of these values comes

from sub-5G floaters, leaving our estimates at risk.

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

ATW 15% 0% 3% 20% 0% 64% 0%

DO 5% 16% 18% 19% 20% 21% 0%

ESV 25% 2% 2% 15% 20% 35% 2%

HERO 70% 0% 0% 0% 0% 0% 30%

NE 37% 0% 13% 10% 11% 29% 0%

ORIG 0% 0% 0% 0% 19% 81% 0%

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

RDC 65% 0% 0% 0% 0% 35% 0%

RIG 7% 3% 11% 11% 31% 36% 0%

SDRL 24% 0% 0% 3% 3% 70% 0%

TOTAL 22% 2% 6% 9% 15% 46% 1%

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

ATW 15% 0% 1% 9% 0% 74% 0%

DO 4% 6% 6% 16% 16% 53% 0%

ESV 33% 1% 1% 10% 21% 35% 1%

HERO 75% 0% 0% 0% 0% 0% 25%

NE 11% 0% 18% 16% 17% 38% 0%

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

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

RDC 60% 0% 0% 0% 0% 40% 0%

RIG 11% 2% 6% 5% 23% 53% 0%

SDRL 24% 0% 0% 1% 3% 72% 0%

TOTAL 17% 1% 7% 8% 14% 53% 0%



65

75

85

95

105

115

125

135

1.0X

1.1X

1.2X

1.3X

1.4X

1.5X

1.6X

1.7X

1.8X

1.9X

Jan-09 Jan-10 Jan-11 Jan-12 Jan-13 Jan-14

Dayra

te I

nd

ex

Pri

ce/T

an

gib

le B

oo

k V

alu

e

P/TBV Average P/TBV Dayrate Index

Price to Tangible Book Value: Offshore Driller Shares Near Bottom

Dayrate index likely to fall as

recent lower fixtures reflect in

dayrates.

P/Tangible book values likely sit near bottom, as assets

at risk from the downturn are nearer to full depreciation.

Source: IHS Inc. Thomson Reuters, Guggenheim

Securities, LLC

Note: Index includes offshore drillers ATW, DO, ESV,

HERO, NE, ORIG, PACD, RDC, RIG



Bottoms Up Analysis Sees Stronger 2015



Demand Setup Continues to Favor ―Shorter & Shallower‖ View on Downturn

Note: All estimates are by Guggenheim Securities, LLC.

Source: IHS Inc., Infield Systems, 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.



Exploration Demand Sees a Slight Uptick from January on Stronger Tendering

Source: IHS Inc., Guggenheim Securities, LLC

Ultradeepwater/Deepwater Exploration Demand Midwater Exploration Demand

Note on Methodology: For 2014, the number of current contracted rigs working on exploration wells is added

to our net demand growth number in order to come up with total exploration demand. For 2015, the previous

year‘s demand number is added to net demand growth to arrive at total exploration demand.

2014E 2015E 2014E 2015E

Current Floaters Working in E&A 58 Current Floaters Working in E&A 28

Raw Demand Raw Demand

"Tender" Demand 8 10 "Tender" Demand 4 4

"Pre-Tender" Demand 10 4 "Pre-Tender" Demand 2 5

"Probable" Demand 10 7 "Probable" Demand 14 12

"Possible" Demand 27 40 "Possible" Demand 31 19

Total Un-risked Demand 55 61 Total Un-risked Demand 51 40

Adjusted "Tender" Demand 8 10 Adjusted "Tender" Demand 4 4

Adjusted "Pre-Tender" Demand 10 4 Adjusted "Pre-Tender" Demand 2 5

Adjusted "Probable" Demand (25-50% probability) 3 4 Adjusted "Probable" Demand (25-50% probability) 4 3

Adjusted "Possible" Demand (25% probability) - 10 Adjusted "Possible" Demand (25% probability) - 1

Total Probability-Weighted Demand 21 28 Total Probability-Weighted Demand 10 13

Subtract: Ultradeepwater Available Rigs 8 14

Subtract: Deepwater Available Rigs 4 6

Subtract: Total UDW/DW Rigs Available 12 20 Subtract: Total MW Rigs Available 9 10

Beginning of Period Demand 58 67 Beginning of Period Demand 28 29

Add: Total Probability Weighted Demand 21 28 Add: Total Probability Weighted Demand 10 13

Subtract Total UDW/DW Rigs Coming Available (12) (20) Subtract Total MW Rigs Coming Available (9) (10)

Total Exploration Demand: Ultra/Deepwater 67 74 Total Exploration Demand: Midwater 29 32

Ulltra/Deepwater Exploration Demand 67 74

Midwater Exploration Demand 29 32

Total Exploration Demand 95 106

Even with greater risk baked into the forecast, an

increase in ―probable‖ exploration tender activity has

increased our near-term exploration forecast. An

uptick in tenders since January is an incrementally

positive signal.



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%

Heavily Risked Demand Reduces Non-FID Downside Through 2015

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.





Forecast More Realistic, But Potentially Too Conservative for Midwater

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


Projects History & Forecast

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

Our probability-weighted UDW/DW

demand better accounts for the

industry‘s ability to bring new

projects online.

Our midwater forecast implies a

number of projects that are not

sanctioned at lower water depths,

but my 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



60

65

70

75

80

85

90

95

100

105

110

115

120

125

130

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

40

50

60

70

80

90

100

110

120

130

140

150

160

170

180

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

Demand Forecasts Resume Structural Growth Trends

We see an increase in

E&A floater demand as

operators try to maintain

production and reserves.

Development Rig Contracted History and

Projections

Floaters Contracted for Exploration & Appraisal

History and Projections

Our forecast calls for a

continued increase in

development drilling,

post pause.


Note: well count excludes shallow water

NOTE: Historical numbers are skewed lower by rigs contracted, but not indicated as either

Development or Exploration.



70%

75%

80%

85%

90%

95%

110 120 130 140 150 160 170 180 190 200 210 220 230 240 250 260 270 280 290 300 310 320 330 340 350 360

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

Total Floater Utilization Total Floaters Forecast Total Floaters

Pace of Contracted Floater Growth Resumes With Structural Trend

Total Contracted Floaters and Our Projections (Quarterly)

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

The 2014 ―pause‖ will

transition to a 2015 recovery,

mainly led by development

activity.

NOTE: Forecast assumes that all floaters work at 100% utilization in order to compare to

number of contracted floaters, historically.



Regional Drivers of Incremental Demand

Regional Drivers of Development Drilling Growth 2014-2016


North Sea, 4% North America, 5%

Mediteranean, 8%

Middle East, 8%

Latin America, 14%

West Africa, 18%

Australasia, 22%

SE Asia, 22%

Regional Drivers E&A Tendering Activity

Tender Pre-tender Probable Possible Total

W Africa 3 1 4 20 28 Indian Ocean 2 3 14 19

SE Asia 1 2 2 3 8

S America 2 5 7

Aus/NZ 1 4 5

Med/Black Sea 1 3 4

Canada East 2 2

Middle East 2 2

Other 1 1

Canada Other 1 1

NW Europe 1 1

US GOM 1 1

Total 7 5 14 53



Shortening Average Contract Durations Illustrate Desire for ―Optionality‖

-

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

5.0

Mar-

03

Au

g-0

3

Jan

-04

Ju

n-0

4

No

v-0

4

Ap

r-05

Sep

-05

Feb

-06

Ju

l-06

Dec-0

6

May-0

7

Oct-

07

Mar-

08

Au

g-0

8

Jan

-09

Ju

n-0

9

No

v-0

9

Ap

r-10

Sep

-10

Feb

-11

Ju

l-11

Dec-1

1

May-1

2

Oct-

12

Mar-

13

Au

g-1

3

Jan

-14

Co

ntr

act

Du

rati

on

(years

)

Drillship - Rolling 6-Month Avg.

-

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

Jan

-03

Ju

n-0

3

No

v-0

3

Ap

r-04

Sep

-04

Feb

-05

Ju

l-05

Dec-0

5

May-0

6

Oct-

06

Mar-

07

Au

g-0

7

Jan

-08

Ju

n-0

8

No

v-0

8

Ap

r-09

Sep

-09

Feb

-10

Ju

l-10

Dec-1

0

May-1

1

Oct-

11

Mar-

12

Au

g-1

2

Jan

-13

Ju

n-1

3

No

v-1

3

Co

ntr

act

Du

raq

tio

n (

years

)

Jackup - Rolling 6-Month Avg.

Drillship Fixture Duration History Jackup Fixture Duration History

Falling floater contract duration is good for offshore

drillers not looking to lock in low rates, if optimistic

about a market recovery. Conversely, lower jackup

contract durations may be a negative sign, given the

recent strength of the jackup market.




Ma

y-14

Au

g-14

No

v-14

Feb-15

Jun

-15

Sep-15

Dec-15

Bredford Dolphin

Noble Therald Martin

Nanhai VI

GSF Grand Banks

GSF Rig 135

Ocean Nomad

Actinia

Ocean Guardian

Transocean Searcher

Noble Ton van Langeveld

Ocean Concord

Transocean Prospect

Noble Phoenix

Ocean Winner

Ocean Worker

Ocean Vanguard

ENSCO 5001

Stena Clyde

Atwood Hunter

Kan Tan III

Ocean Quest

Peregrine I

Sedco 707

Transocean Legend

Kan Tan IV

Songa Mercur

GSF Rig 140

Ocean Yatzy

Olinda Star

GSF Arctic III

ENSCO 6000

Ocean Princess

Ocean Yorktown

Songa Venus

M.G. Hulme, Jr.

Ocean General

Noble Driller

Borgny Dolphin

ENSCO 5005

Ocean Lexington

Ocean Saratoga

ENSCO 5002

Transocean Amirante

Ocean Star

Rig Attrition: Floaters Screening for Retirement Rolling Off Contract

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

We have identified the

bottom ~30% of the

floater fleet by age and rig

specifications. Then

looked at offshore rig

owners likely to retire/cold

stack assets. The

availability chart to the left

identifies the assets

coming available that

have the potential to

come out of the market

through 2015.



Number of Uncontracted Rigs May Reduce Our Floater Supply Assumptions Status Manager Market Category Rig Name Free Date

1 Standby Noble Semi >7500 Noble Paul Wolff Jul-15

2 Yard Gryphon Energy Drillship 5001-7500 Peregrine I Dec-14

3 En route Ensco Semi 3001-5000 ENSCO 6000 Sep-14

4 Yard Japan Drilling Semi <=3000 Hakuryu-5 Aug-14

5 Yard Songa-Opus JV Semi <=3000 Songa Venus Jul-14

6 Yard Essar Oilfields Services Semi <=3000 Essar Wildcat Jun-14

7 Yard Diamond Offshore Semi 5001-7500 Ocean Valiant May-14

8 Warm stacked Ensco Semi <=3000 ENSCO 5002 May-14

9 Warm stacked PetroSaudi Drillship <=3000 PetroSaudi Discoverer Apr-14

10 Yard Arktikmor Drillship 5001-7500 Deep Venture Apr-14

11 Warm stacked Transocean Semi 5001-7500 Sedco Energy Mar-14

12 Warm stacked Jasper Offshore Drillship 3001-5000 Jasper Explorer Feb-14

13 Hot stacked Transocean Semi 5001-7500 GSF Development Driller I Feb-14

14 Warm stacked Noble Semi 5001-7500 Noble Homer Ferrington Jan-14

15 Warm stacked Transocean Semi 3001-5000 Transocean Rather Nov-13

16 Warm stacked Transocean Semi <=3000 Falcon 100 Nov-13

17 Warm stacked Transocean Semi 3001-5000 Transocean Amirante Aug-13

18 Warm stacked Transocean Semi 3001-5000 GSF Arctic I Mar-13

19 Warm stacked Merlin Energy Semi <=3000 Archimedes Nov-11

Status Manager Market Category Rig Name Free Date

1 Cold stacked Transocean Semi <=3000 Sedneth 701 Apr-14

2 Cold stacked Ensco Semi <=3000 ENSCO 5000 Jan-14

3 Cold stacked Transocean Semi 3001-5000 Sedco 710 Nov-13

4 Cold stacked Noble Drillship 3001-5000 Noble Muravlenko Nov-12

5 Cold stacked Diamond Offshore Semi <=3000 Ocean Whittington May-12

6 Cold stacked Transocean Semi <=3000 Sovereign Explorer Oct-11

7 Cold stacked Transocean Semi Harsh Standard J.W. McLean Apr-11

8 Cold stacked Transocean Semi <=3000 Sedco 601 Apr-11

9 Cold stacked Diamond Offshore Semi <=3000 Ocean Epoch Feb-11

10 Cold stacked Noble Semi 3001-5000 Noble Lorris Bouzigard Oct-10

11 Cold stacked Atwood Semi <=3000 Atwood Southern Cross Sep-10

12 Cold stacked Diamond Offshore Semi <=3000 Ocean New Era Sep-10

13 Cold stacked Transocean Semi 3001-5000 Sedco 700 Apr-10

14 Cold stacked Transocean Semi 3001-5000 Sedco 709 Apr-10

15 Cold stacked Transocean Semi <=3000 GSF Aleutian Key Jan-10

16 Cold stacked Transocean Semi <=3000 Sedco 703 Jul-09

17 Cold stacked Transocean Semi <=3000 C. Kirk Rhein, Jr. Mar-09

18 Cold stacked SOCAR Semi <=3000 Absheron Nov-02

Currently, 18 rigs are not

contracted. We have not

removed these rigs from

our supply numbers.

Most of these rig have

gone idle in 2014. We

view these rigs as

candidates for cold

stacking/retirement, which

would have a favorable

impact on our view of

market balances.

The 18 floaters currently

cold stacked are not

included in our rig supply .

We suspect that

uncontracted rigs above

that need significant

investment, like the Paul

Wolff, may join the ranks

of stacked rigs.

Source: IHS Inc., Guggenheim Securities, LLC Guggenheim Securities, LLC | 972-638-5502 | guggenheimsecurities.com


Floaters Required to Undergo 30 year Special Surveys At Risk for Retirement

As highlighted by SDRL

on their 1Q14 call, several

rigs, 25+ years old, are

coming due for their

special classing survey.

Many of the these rigs

may require significant

investment due to this

survey (~$100m). A

number of these rigs

(highlighted in bold and

blue) overlap with our list

of floater that screen for

retirement/cold stacking.


Rig Name

Delivery

Year

Special

Survey

Due Rig Name

Delivery

Year

Special

Survey

Due

1 Noble Roger Eason 1977 Feb-12 49 Falcon 100 1974 Aug-15

2 Noble Discoverer 1976 Jun-12 50 Paul B. Loyd, Jr. 1987 Nov-15

3 WilPhoenix 1982 Jul-12 51 WilHunter 1983 Nov-15

4 Ocean Apex 1976 Mar-13 52 Nanhai VI 1982 Dec-15

5 Deep Venture 1981 Apr-13 53 Atlantic Star 1976 Jan-16

6 Ocean Rover 1973 Jun-13 54 Atwood Eagle 1982 Jan-16

7 Ocean Ambassador 1975 Jul-13 55 Noble Ton van Langeveld 1979 Feb-16

8 Aban Abraham 1976 Aug-13 56 Transocean Winner 1983 Feb-16

9 Naga-1 1974 Oct-13 57 Doo Sung 1984 May-16

10 GSF Rig 140 1983 Oct-13 58 Energy Searcher 1982 May-16

11 Ocean Alliance 1988 Oct-13 59 ENSCO 6000 1986 May-16

12 Noble Phoenix 1979 Nov-13 60 Alaskan Star 1976 Jun-16

13 Ocean Monarch 1974 Nov-13 61 Jack Bates 1986 Jul-16

14 Jasper Explorer 1973 Nov-13 62 Archimedes 1976 Aug-16

15 Atwood Falcon 1983 Nov-13 63 ENSCO 5004 1982 Aug-16

16 GSF Arctic I 1983 Dec-13 64 Zagreb 1 1977 Sep-16

17 Sedco 706 1976 Jan-14 65 Songa Delta 1980 Sep-16

18 Noble Dave Beard 1986 Feb-14 66 Noble Therald Martin 1977 Sep-16

19 GSF Grand Banks 1984 Mar-14 67 Discoverer Seven Seas 1976 Sep-16

20 Borgny Dolphin 1977 Apr-14 68 PetroSaudi Discoverer 1977 Oct-16

21 Aban Ice 1975 Apr-14 69 Ocean Clipper 1977 Oct-16

22 ENSCO 5001 1975 Jun-14 70 PetroSaudi Saturn 1983 Oct-16

23 Scarabeo 6 1984 Jul-14 71 Ocean Saratoga 1976 Oct-16

24 Ocean Yatzy 1989 Jul-14 72 ENSCO 5002 1975 Jan-17

25 Polar Pioneer 1985 Sep-14 73 Noble Leo Segerius 1981 Jan-17

26 Byford Dolphin 1974 Oct-14 74 Sedco 702 1973 Jan-17

27 Olinda Star 1983 Oct-14 75 Nanhai VIII 1982 Jan-17

28 Transocean Arctic 1986 Oct-14 76 Ocean Star 1973 Feb-17

29 GSF Arctic III 1984 Nov-14 77 Ocean Endeavor 1975 Mar-17

30 Noble Homer Ferrington 1985 Nov-14 78 Ocean Baroness 1973 Mar-17

31 Transocean Rather 1988 Nov-14 79 Songa Dee 1984 Apr-17

32 Ocean Concord 1975 Nov-14 80 Transocean Prospect 1983 Apr-17

33 Peregrine I 1983 Jan-15 81 Noble Duchess 1975 Apr-17

34 Scarabeo 4 1975 Jan-15 82 Nanhai II 1974 Apr-17

35 Ocean Winner 1976 Jan-15 83 Ocean Yorktown 1976 Apr-17

36 Nanhai V 1983 Feb-15 84 Scarabeo 3 1975 Apr-17

37 Songa Mercur 1989 Feb-15 85 Kan Tan IV 1983 Apr-17

38 Ocean Guardian 1985 Feb-15 86 Noble Clyde Boudreaux 1987 May-17

39 Songa Venus 1975 Mar-15 87 Bredford Dolphin 1980 May-17

40 Ocean Lexington 1976 Mar-15 88 Atwood Hunter 1981 Aug-17

41 Essar Wildcat 1977 Apr-15 89 Transocean Leader 1987 Sep-17

42 Ocean Vanguard 1982 Apr-15 90 Hakuryu-5 1977 Sep-17

43 Stena Clyde 1976 Jun-15 91 Ocean Worker 1982 Sep-17

44 Henry Goodrich 1985 Jul-15 92 Sedco 711 1982 Oct-17

45 Deepwater Navigator 1971 Jul-15 93 Actinia 1982 Oct-17

46 M.G. Hulme, Jr. 1983 Aug-15 94 Ocean Victory 1972 Nov-17

47 Energy Driller 1977 Aug-15 95 Ocean Quest 1973 Nov-17

48 Deepsea Bergen 1983 Aug-15 96 ENSCO 5005 1982 Dec-17



Dayrate Forecast: Trough & Recovery



Revised Dayrate Forecast Sees Marginal Dayrate Improvement in 2015

Source: IHS Inc., Guggenheim Securities, LLC.

2Q14E 3Q14E 4Q14E 1Q15E 2Q15E 3Q15E 4Q15E 1Q16E 2Q16E 3Q16E 4Q16E 1Q17E 2Q17E 3Q17E 4Q17E 1Q18 2Q18 3Q18 4Q18 1Q19 2Q19 3Q19 4Q19

6G HDHE 530 525 520 515 515 520 525 535 545 555 565 570 575 580 585 570 555 545 530 515 515 515 515

6G High 490 485 480 475 475 480 485 495 505 515 525 530 535 540 545 545 545 545 545 545 545 545 545

6G Low 460 455 450 445 445 450 455 465 475 485 495 500 505 510 515 510 505 505 500 495 495 495 495

5G HDHE 375 370 365 360 360 365 370 380 390 400 410 415 420 425 430 425 420 410 405 400 400 400 400

5G High 375 370 365 360 360 365 370 380 390 400 410 415 420 425 430 410 395 375 360 340 340 340 340

5G Low 350 345 340 335 335 340 345 355 365 375 385 390 395 400 405 385 360 340 315 295 295 295 295

4G HDHE 350 345 340 335 335 340 345 355 365 375 385 390 395 400 405 375 345 310 280 250 250 250 250

4G High 340 335 330 325 325 330 335 345 355 365 375 380 385 390 395 365 335 305 275 245 245 245 245

4G Low 325 320 315 310 310 315 320 330 340 350 360 365 370 375 380 345 310 275 240 205 205 205 205

3G HDHE 310 305 300 295 295 300 305 315 325 335 345 350 355 360 365 330 290 255 215 180 180 180 180

3G High 290 285 280 275 275 280 285 295 305 315 325 330 335 340 345 320 295 275 250 225 225 225 225

3G Low 260 255 250 245 245 250 255 265 275 285 295 300 305 310 315 285 255 230 200 170 170 170 170

HDHE JU 230 225 220 215 210 205 200 195 190 185 180 185 190 195 200 200 200 195 195 195 195 195 195

Prem JU 180 175 170 165 160 155 150 145 140 135 130 135 140 145 150 155 160 165 170 175 175 175 175

High End JU 160 155 150 145 140 135 130 125 120 115 110 115 120 125 130 130 130 125 125 125 125 125 125

Standard JU 130 125 120 115 110 105 100 95 90 85 80 85 90 95 100 100 95 95 90 90 90 90 90

Sub-Standard JU 100 95 90 85 80 75 70 65 60 55 50 55 60 65 70 75 80 85 90 95 95 95 95

Commodity JU 90 85 80 75 70 65 60 55 50 45 40 45 50 55 60 65 65 70 70 75 75 75 75

Legacy 70 65 60 55 50 45 40 40 40 40 40 45 50 55 60 65 70 80 85 90 90 90 90

Trough of Floater Dayrates Floater Market Recovery New Floater Cycle Upswing Normalized (9% Cost of

Capital Returns) Transition

Jackup Dayrates Decline As Newbuilds Arrive

Normalized (9% Cost of

Capital Returns) Transition Modest Dayrate

Recovery



Ultra/Deepwater Rigs Revisit Recent Dayrate Lows, Reflected in Recent Fixtures


Ultradeepwater Floater Dayrate History

Deepwater Floater Dayrate History

Recent fixtures indicate that dayrates

are coming down below recent

averages. The trough of our forecast

revisits 2010-2011 average lows

before recovery. High demand for the

most capable floaters will buffer the

ultradeepwater market.

Deepwater rates have more variance

due to a wider range of rig capabilities

and more competition between

owners to maintain utilization. Again,

recent fixtures indicate that dayrates

are coming down below recent

averages. The trough of our forecast

revisits recent lows before recovery.

50

100

150

200

250

300

350

400

450

500

550

50

100

150

200

250

300

350

400

450

500

550

Jan

-03

Ju

l-03

Jan

-04

Ju

l-04

Jan

-05

Ju

l-05

Jan

-06

Ju

l-06

Jan

-07

Ju

l-07

Jan

-08

Ju

l-08

Jan

-09

Ju

l-09

Jan

-10

Ju

l-10

Jan

-11

Ju

l-11

Jan

-12

Ju

l-12

Jan

-13

Ju

l-13

Jan

-14

DW Avg Dayrate DW Drillship Avg Fixture DW Semi AVGFixture

50

150

250

350

450

550

650

50

150

250

350

450

550

650

Jan

-03

Ju

l-03

Jan

-04

Ju

l-04

Jan

-05

Ju

l-05

Jan

-06

Ju

l-06

Jan

-07

Ju

l-07

Jan

-08

Ju

l-08

Jan

-09

Ju

l-09

Jan

-10

Ju

l-10

Jan

-11

Ju

l-11

Jan

-12

Ju

l-12

Jan

-13

Ju

l-13

Jan

-14

UDW Avg Dayrate UDW Drillship Avg Fixture UDW Semi AVGFixture



Midwater Dayrates Show ―Bifurcation‖ & Room for Rig Attrition


Midwater Floater Dayrate History

Midwater dayrates

remain under the

most pressure, with

potential for

deepwater rigs to

compete with them to

maintain near-term

utilization. The

separation of higher

spec. and lower spec.

midwater dayrates

lends to the argument

that less capable rigs

will be retired in the

near term, especially

those requiring higher

levels of investment.

50

100

150

200

250

300

350

400

450

500

50

100

150

200

250

300

350

400

450

500

Jan

-03

Ju

n-0

3

No

v-0

3

Ap

r-04

Sep

-04

Feb

-05

Ju

l-05

Dec-0

5

May-0

6

Oct-

06

Mar-

07

Au

g-0

7

Jan

-08

Ju

n-0

8

No

v-0

8

Ap

r-09

Sep

-09

Feb

-10

Ju

l-10

Dec-1

0

May-1

1

Oct-

11

Mar-

12

Au

g-1

2

Jan

-13

Ju

n-1

3

No

v-1

3

Ap

r-14

MW Avg Dayrate Upper MW Avg Fixture Lower MW AVG Fixture



50

100

150

200

250

300

350

400

450

500

550

600

650

50

100

150

200

250

300

350

400

450

500

550

600

650

Jan

-03

Ju

n-0

3

No

v-0

3

Ap

r-04

Sep

-04

Feb

-05

Ju

l-05

Dec-0

5

May-0

6

Oct-

06

Mar-

07

Au

g-0

7

Jan

-08

Ju

n-0

8

No

v-0

8

Ap

r-09

Sep

-09

Feb

-10

Ju

l-10

Dec-1

0

May-1

1

Oct-

11

Mar-

12

Au

g-1

2

Jan

-13

Ju

n-1

3

No

v-1

3

Ap

r-14

Harsh Env. Avg Dayrate Harsh Deepwater Avg. Fixture

Harsh High Spec Avg. Fixture Harsh Standard Avg. Fixture

Harsh Environment Floaters Enjoy Their Niche


Harsh Environment Floater Dayrate History

Harsh environment rigs seem shielded

by their niche markets. We continue

to forecast a strong market for these

assets. The announcement of the

SDRL/NADL/Rosneft deal, indicating

more demand in the Russian arctic will

only continue to support dayrates for

this class of floaters.



20

30

40

50

60

70

80

90

100

110

120

130

140

150

160

170

180

190

200

210

20

30

40

50

60

70

80

90

100

110

120

130

140

150

160

170

180

190

200

210

Jan

-03

Ju

n-0

3

No

v-0

3

Ap

r-04

Sep

-04

Feb

-05

Ju

l-05

Dec-0

5

May-0

6

Oct-

06

Mar-

07

Au

g-0

7

Jan

-08

Ju

n-0

8

No

v-0

8

Ap

r-09

Sep

-09

Feb

-10

Ju

l-10

Dec-1

0

May-1

1

Oct-

11

Mar-

12

Au

g-1

2

Jan

-13

Ju

n-1

3

No

v-1

3

Ap

r-14

JU >300ft Avg. Dayrate JU Premium Avg. Fixture JU High End Avg. Fixture

Both the Premium & Standard Jackup Markets See Higher New Fixtures


Jackup: Premium/High End Dayrate History

Jackup: Standard Dayrate History

25

50

75

100

125

150

175

200

225

25

50

75

100

125

150

175

200

225

Jan

-03

Ju

n-0

3

No

v-0

3

Ap

r-04

Sep

-04

Feb

-05

Ju

l-05

Dec-0

5

May-0

6

Oct-

06

Mar-

07

Au

g-0

7

Jan

-08

Ju

n-0

8

No

v-0

8

Ap

r-09

Sep

-09

Feb

-10

Ju

l-10

Dec-1

0

May-1

1

Oct-

11

Mar-

12

Au

g-1

2

Jan

-13

Ju

n-1

3

No

v-1

3

Ap

r-14

JU 300-IC Avg Dayrate JU Standard Avg. Fixture

Jackup fixtures continue to trend

above current dayrate averages.

Although there are few signs of

weakness, we see the optics of the

arrival of several uncontracted

newbuilds as an overhang on

dayrates in the near term. As a result,

we forecast a fade in average

dayrates over the near term.



Harsh Environment Jackups Maintain a Strong Market


Jackup: Harsh-Standard Dayrate History

25

50

75

100

125

150

175

200

225

250

25

50

75

100

125

150

175

200

225

250 Jan

-03

Ju

n-0

3

No

v-0

3

Ap

r-04

Sep

-04

Feb

-05

Ju

l-05

Dec-0

5

May-0

6

Oct-

06

Mar-

07

Au

g-0

7

Jan

-08

Ju

n-0

8

No

v-0

8

Ap

r-09

Sep

-09

Feb

-10

Ju

l-10

Dec-1

0

May-1

1

Oct-

11

Mar-

12

Au

g-1

2

Jan

-13

Ju

n-1

3

No

v-1

3

Ap

r-14

JU Harsh Standard Avg Dayrate JU Harsh Standard Avg Fixture



Market Dynamics Support Our Forecast



1%2%

5%

8%

14%

21%

27%

0%

5%

10%

15%

20%

25%

30%

-

1,000

2,000

3,000

4,000

5,000

6,000

7,000

2014 2015 2016 2017 2018 2019 2020

Pe

rce

nt U

ns

an

cti

on

ed

mb

oe

/d

New Source Incremental - SanctionedNew Source Incremental - UnsanctionedDeepwater - % New Source Unsanctioned

Deepwater Projects Represent ~30-40% of New Source Production


Note: Subset of companies consists of

APC, APA, BG, BHP, BP, COP, CVX,

E, XOM, HES, MPC, MUR, NBL,

PEMEX, PBR, PETRONAS, REP,

RDS, STO, TLM, TOT, TLW, WPL,

XOM

Forecast Cumulative New Source Production

Deepwater Contribution to Forecast Cumulative New Source Oil Production

32%33%

34% 33%35%

37%39%

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

2014 2015 2016 2017 2018 2019 2020

Deepwater - % New Source

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

PEMEX

Marathon Oil

BHP Billiton

PETRONAS

Apache

ConocoPhillips

Hess

ExxonMobil

Repsol

TOTAL

Anadarko

Woodside

BP

Noble Energy

Murphy

Statoil

Chevron

BG Group

Eni

Shell

Petrobras

Tullow

Most Deepwater New Source Production Sanctioned



6.0

7.0

8.0

9.0

10.0

11.0

12.0

13.0

14.0

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

Ave

rag

e Y

ea

rs: D

isc

ove

ry to

De

ve

lop

me

nt

Industry Had Efficiency Track Record For Improved Time to Field Development

Average Time to Development from Year Discovered: Actual & Forecast

The evolution of economies of scale,

learning curves, and standardized

solutions have reduced the time to

develop fields. In our view, the push

toward further standardization will

continue to drive down production

infrastructure costs and improve field

development times.

Source: Infield Systems, Guggenheim Securities, LLC



02468

101214161820222426283032343638404244464850525456

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

20

21

Nu

mb

er o

f P

roje

cts

Midwater Deepwater Ultradeepwater

0

20

40

60

80

100

120

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

20

21

Nu

mb

er

of

Pro

jec

ts


Engineering Challenges Will Find Standardize Solutions For Deepwater Projects

Rising percentage of deepwater

projects in the mix suggest s that

project complexity is increasing. As

upstream operators engineer

solutions to initial challenges, we see

room for greater efficiencies with less

incremental engineering and more

standardization in the production

solutions.




Number of HPHT Projects Highlight Increase ―Degree of Difficulty‖

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

The upstream industry is learning how

to process more challenging high

pressure/high temperature (HPTH)

production environment offshore.




-

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

- 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000

De

vele

op

me

nt D

rilli

ng

Co

st E

st. (

$m

m)

CAPEX ($mm)

Non-FID FID

Economics Favorable, Infrastructure CAPEX Bigger Factor vs. Drilling Costs

5%

10%

15%

20%

25%

30%

35%

40%

45%

50%

55%

60%

65%

70%

75%

80%

-5% 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50%

Dev

elo

pm

en

t Fo

rwa

rd IR

R (%

)

Full Cycle IRR (%)

FID Projects Non-FID Projects


Greater spend on project

infrastructure CAPEX versus

development drilling costs, suggests

that focus on returns may be more

concentration on standardization and

project management efficiency than

rig costs.

The vast majority of projects have

return structures on a full-cycle and

development-forward basis that are

above 20% IRRs.



PFC Deepwater Discovery Monitor – Suggest High Success Rates


Deepwater Discoveries, 2008-2013

Arctic, 2 , 1%

Asia-Pacific, 70 , 18%

Europe, 45 , 12%

Latin America, 77 , 20%

MENA, 15 , 4%

North America, 59 , 15%

Sub-Saharan Africa, 115 , 30%

2008-2013 Total Discovery Breakdown by Region

12

76 78

56

76

85

0%

10%

20%

30%

40%

50%

60%

-

10

20

30

40

50

60

70

80

90

2008 2009 2010 2011 2012 2013

Su

ccess R

ate

Nu

mb

er

of

Pro

jects

Discovery Year

Grand Total Success Rate

We take historical exploration and

appraisal well quarters, multiple by 2x for

the well/rig ratio, and then divide that by

the number of discoveries to determine the

success rate.



Industry Maturity: Rig Supply & “Attrition” Thesis



100 108 114 118 118

80 80 80 82 83

131 142

160 171 179

311 330

354 371

380

-

50

100

150

200

250

300

350

400

2014E 2015E 2016E 2017E 2018E

Pro

jecte

d T

ota

l R

ig S

up

ply


4 3 2 1 4 - - - - 2 1 1 1

11 6 7

13

6 19 19 15

5 6 5 1

12

18

25

38

44

63

82

97 102

108 113

-

20

40

60

80

100

1Q

14

2Q

14

3Q

14

4Q

14

1Q

15

2Q

15

3Q

15

4Q

15

1Q

16

2Q

16

3Q

16

4Q

16

Nu

mb

er

of

Rig

s

Contracted Uncontracted Cumulative Uncontracted

Uncontracted Fleet Growth Leaves the Market Concerned


Source: IHS Inc., Infield Systems, PFC Energy-Guggenheim

Jackup Newbuild Projections Floater Newbuild Projections

Floater Fleet Growth Projections Jackup Fleet Growth Projections

1

6

-

5 3 4

1 2 2 1 4 4

-

1

8

4

3 2

3

9

- 3 1

3

-

1

9

13

16

18

21

30 30

33 34

37

-

5

10

15

20

25

30

35

40

1Q

14

2Q

14

3Q

14

4Q

14

1Q

15

2Q

15

3Q

15

4Q

15

1Q

16

2Q

16

3Q

16

4Q

16

Nu

mb

er

of

Rig

s

Contracted Uncontracted Cumulative Uncontracted

95 96 96 96 96

180 181 181 181 181

173 198

243 255 257

48 53

70 82 82

496 527

590 614 616

-

100

200

300

400

500

600

700

2014E 2015E 2016E 2017E 2018E

Pro

jecte

d T

ota

l R

ig S

up

ply

Commodity Standard Premium Harsh Environment

The ramp in

uncontracted jackup

deliveries may lead to

increased anxiety as

time presses forward.



0

2

4

6

8

10

12

14

16

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

# o

f R

igs

Drillship Semisubmersible

-

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


Floater Fleet Grows With Market, but May See Room for Midwater Obsolescence

Floater Additions by Year

Floater Attrition by Year

Older 3G and upgraded 2G units likely ripe for

retirement, given increasing need for higher

specifications.

Note: All estimates for 2013-2020 are by Guggenheim Securities, LLC.


Previous attrition during

downturns may reaccelerate

with the 2G/3G fleet becoming

increasingly challenged.



0

2

4

6

8

10

12

14

16

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

# o

f R

igs

-

10

20

30

40

50

60

70

80

90

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

Jackup Additions/Attrition Cycle Independent of Strong Market

Jackup Additions by Year

Jackup Attrition by Year

Fleet replacement cycle

currently underway

Historically, rigs retired

during downturns, but the

past two years have seen

retirement of obsolete rigs

contract drillers are not

willing to upgrade. Thus, we

see potential for a super

spike in retirements in the

next downturn.

Note: All estimates for 2013-202 are by Guggenheim Securities, LLC.




Order Date History

Jackup Orders by Year

Floater Orders by Year



-

20

40

60

80

100

120

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

-

5

10

15

20

25

30

35

40

45

50

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




Tender Demand Visibility Explains Outlook



Midwater

2014E 2015E

Exploration 6 5

Appraisal - -

Development 4 5

Other - -

Tender 10 9

Exploration 2 6

Appraisal - -

Development 4 5

Other - -

Pre-Tender 6 9

Firm Demand 16 18

Exploration (20-45% Probability) 3 6

Appraisal (20-45% Probability) 1 1

Development (20-65% Probability) 1 4

Other 1 -

Probable 6 11




Other 1 -

Possible 6 12

Potential Demand 12 23

Total Midwater Availability 27 53

Total Availability 27 53

Less: Firm Demand (16) (18)

Less: Carried Demand - (1)

Surplus/(Deficit), Firm & Adjusted 11 34

Adjusted Potential Demand (12) (23)

Midwater Surplus/(Deficit) (1) 11

Deepwater Availability (Surplus) 13 36

Total Floater Surplus/(Deficit) 12 47

Deepwater

2014E 2015E

Exploration 9 9

Appraisal - 1

Development 8 10

Other - 1

Tender 17 21

Exploration 8 4

Appraisal 1 1

Development 1 6

Other - -

Pre-Tender 10 11

Firm Demand 27 32




Other 1 1

Probable 5 7


Appraisal (5-35% Probability) - 1

Development (25-65% Probability) - -

Other - 1

Possible 2 16


Ultra-Deepwater Availability 28 60

Deepwater Availability 19 31



Less: Firm Demand (27) (32)

Less: Carried Demand - -

Surplus/(Deficit), Firm & Adjusted 20 59

Adjusted Potential Demand (7) (23)

Deepwater Surplus/(Deficit) 13 36

Floater Marginal S/D Balanced for 2014, Less Visible for 2015

Deepwater Midwater and Total Floater

The tender market sends the

message that the floater

market has slack supply.

Given a the activity slowdown

in 2014, we are not surprised

by the dearth of tender

activity. We look for an

inflection as indications of

demand for 2015 become

more apparent.

With a never-ending list of

potential project and tenders,

―Probable‖ & ―Possible‖

demand must be risk-

weighted in order to better

represent reality.





High End Jackup Market Looks Tight, Despite Pending Uncontracted Supply

Jackups

Given that tenders target higher-end jackups, we

segmented market availability only looking at rigs rated

above 300ft water depth, 2,000 ton+ variable deck loads,

18k+ drilling depths, 15k+ BOP psi ratings, and hook load

capacities above 1.5m lbs.

Historically, the jackup market has

operated as a ―spot‖ market, with

tendering activity only prevalent for the

high end of the rig market.

Probability-weighted demand

looks to better gauge actual

demand from an extensive

project inventory.



Jackups

2014E 2015E

Exploration 16 18

Appraisal 1 -

Development 20 23

Other 2 2

Tender 39 42

Exploration 13 11

Appraisal 2 -

Development 9 14

Other 1 3

Pre-Tender 23 27

Firm Demand 62 69




Other - 1

Probable 6 27




Other 4 3

Possible 11 30




Less: Firm Demand 62 69

Less: Carried Demand - 19

Surplus/(Deficit), Firm & Adjusted (2) 36

Adjusted Potential Demand 17 57

Surplus/(Deficit), Firm & Adjusted (19) (21)



Key Assumptions



Composition of Model Supply

2014 2015 2016 2017 2018

Ultradeepwater

Beginning of Period 125 131 142 160 171

Newbuilds Partial Initial Year 6 6 5 4 3

Newbuilds Full Year - 5 13 7 5

End of Period 131 142 160 171 179

Deepwater


Newbuilds Partial Initial Year - - 0 1 1

Newbuilds Full Year - - - 1 0

End of Period 80 80 80 82 83

Midwater


Newbuilds Partial Initial Year 0 5 2 1 -

Newbuilds Full Year - 3 4 3 0

End of Period 100 108 114 118 118

Utilization: Total Floater Supply within the Supply/Demand Model



We assume no rigs are

retired and partial

employment for the

arrival of newbuilds, on a

rig-by-rig basis. We

conservatively assume

that the Brazilian

newbuilds in the order

book arrive on schedule.

That said, the timely

delivery of these rigs

remains unlikely, skewing

the floater market

balance tighter over time.



83%

88%

86%

84%

83%

80%

77%

78%

80%

82%

83%84%

86%87%

85%84%

86%85%

88%

90%

89%

88%

90%

89%

87%86%

87%

84%

86%

84%

88%

90%

89%

90% 90%

89%88%

86%

75%76%77%78%79%80%81%82%83%84%85%86%87%88%89%90%91%

Our Assumption (85%) Marketed Util % Average 2001-2013

Floater Utilization Forecasted at 85%, Near Historical Averages


Floater Working Utilization

Note:―Working‖ utilization includes only time drilling, so it dips

when there is rig downtime

In the aftermath of the Macondo

incident, many rigs remained under

contract but were not working because

of the drilling moratorium, thus creating

a big difference between ―contracted‖

and ―working‖ utilization.

Historical

utilization

averages are

closer to 80-85%.



Valuation & EPS Comp Sheets



NADL 9.2%

OII 2.5%

SDLP, 6.6%DO, 6.9%

ESV, 5.7%

NE, 4.8%

ORIG, 4.2%

RDC, 1.3%

RIG, 7.1%

SDRL, 10.6%

CRR, 0.9%

SPN, 7.4%

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%

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

Div

iden

d Y

ield

(L

ate

st

Qu

art

er

An

nu

ali

zed

)

DPS/CEPS 2Q14E (annulaized)

Clear Relationship Between Yield & Payout Ratios

Yield vs. DPS/CEPS

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

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.



DO, 6.9%

ESV, 5.7%

NE, 4.8%

ORIG, 4.2%

RDC, 1.3%

RIG, 7.1%

SDRL, 10.6%

NADL, 9.2%

SDLP, 6.6%

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%

60% 70% 80% 90% 100% 110% 120% 130% 140%

Div

iden

d Y

ield

(L

ate

st

Qu

art

er

An

nu

ali

zed

)

P/NAV - Break-up 2013E

Yield-Based Values Above NAV Offer Arbitrage Between Equity & Yield Capital Markets

Yield vs. P/NAV relationship




OFS Earnings Metrics

Source: Thomson Reuters, Guggenheim Securities, LLC

Price Gugg EPS PE Consensus EPS EPS Variance

Company Ticker Rating 5/30 Target Upside P/NAV* 2Q14E 13 14E 15E 13 14E 15E 2Q14E 14E 15E 2Q14E 14E 15E

S&P 500 SPX 1,924 17.7 16.4 15.1 117.32 127.11

Large Cap Services

Baker Hughes BHI Sell 70.52 55 -22% NA 0.85 2.69 3.90 4.20 26.2 18.1 16.8 0.89 4.15 5.34 -5% -6% -21%

Halliburton HAL Neutral 64.64 60 -7% NA 0.87 3.15 3.80 4.30 20.5 17.0 15.0 0.91 3.97 5.09 -5% -4% -16%

Schlumberger SLB Buy 104.04 130 25% NA 1.35 4.79 5.65 6.75 21.7 18.4 15.4 1.36 5.69 6.78 0% -1% 0%

Weatherford WFT Neutral 21.69 18 -17% NA 0.21 0.60 1.10 1.50 36.2 19.7 14.5 0.21 1.08 1.66 1% 2% -10%8.54

Mean 26.2 18.3 15.4

Large Cap Equipment

Cameron CAM Buy 63.95 75 17% NA 0.85 3.28 3.90 5.00 19.5 16.4 12.8 0.87 3.92 4.91 -2% 0% 2%

FMC Tech FTI Buy 58.06 75 29% NA 0.63 2.11 2.70 3.40 27.5 21.5 17.1 0.63 2.70 3.34 0% 0% 2%

Nat Oil Varco NOV Buy 81.87 100 22% NA 1.46 5.52 6.15 6.60 14.8 13.3 12.4 1.47 6.12 6.89 -1% 1% -4%

Tenaris TS Neutral 44.85 47 5% NA 0.70 2.62 2.60 3.05 17.1 17.2 14.7 0.70 2.78 3.07 0% -6% -1%

Mean 19.7 17.1 14.2

SMid Cap Svcs & Equipment

Aker Solutions AKSO Buy kr 105.00 kr 125 19% NA kr 1.41 kr 5.25 kr 5.80 kr 7.45 20.0 18.1 14.1 1.66 kr 6.82 kr 8.71 -15% -15% -14%

C&J Energy Svcs CJES Sell 30.61 20 -35% NA 0.21 1.21 1.00 1.05 25.3 30.6 29.2 0.26 1.23 2.14 -18% -19% -51%

Core Laboratories CLB Neutral 159.85 170 6% NA 1.34 5.32 5.85 6.30 30.0 27.3 25.4 1.34 5.93 6.75 0% -1% -7%

Carbo Ceramics CRR Sell 137.57 110 -20% NA 0.91 3.70 3.95 4.75 37.2 34.8 29.0 0.95 4.28 5.69 -4% -8% -16%

Dresser-Rand DRC Neutral 61.20 67 9% NA 0.39 3.00 2.70 3.35 20.4 22.7 18.3 0.40 2.65 3.18 -2% 2% 5%

Dril-Quip DRQ Neutral 102.22 110 8% NA 1.15 4.23 4.85 5.90 24.2 21.1 17.3 1.16 5.01 6.15 -1% -3% -4%

Forum Energy Tech FET Neutral 33.04 32 -3% NA 0.41 1.46 0.74 0.95 22.6 18.2 34.8 0.42 1.81 2.27 -3% -59% -58%

Frank's International FI Buy 23.84 30 26% NA 0.31 1.98 1.30 1.45 12.0 18.3 16.4 0.31 1.28 1.45 -1% 2% 0%

Oceaneering OII Neutral 72.05 80 11% NA 1.01 3.40 4.00 4.55 21.2 18.0 15.8 1.01 4.04 4.70 0% -1% -3%

Oil States Int'l OIS Neutral 107.58 96 -11% NA 1.15 6.18 5.30 5.60 17.4 20.3 19.2 1.22 5.48 6.31 -6% -3% -11%

Superior Energy Svcs SPN Neutral 33.19 34 2% NA 0.39 1.56 1.50 2.25 21.3 19.4 14.8 0.41 1.71 2.45 -5% -12% -8%

U.S. Silica Holdings SLCA NC 50.57 NC - NA - - - - 34.4 25.9 18.0 0.46 1.96 2.80 - - -18% 39.91

Mean 23.8 22.9 21.0

Offshore Drilling

Atwood Oceanics* ATW Buy 49.35 58 18% 85% 1.26 5.32 4.95 6.80 9.3 10.0 7.3 1.17 5.02 7.36 7% -1% -8%

Diamond DO Buy 51.06 65 27% 87% 0.90 4.77 4.10 5.60 10.7 12.5 9.1 0.67 3.71 4.70 35% 11% 19%

Ensco plc ESV Buy 52.66 60 14% 88% 1.47 6.16 5.60 6.00 8.5 9.4 8.8 1.37 5.68 5.87 8% -1% 2%

Hercules Offshore HERO Neutral 4.54 5 10% 91% 0.10 0.24 0.55 0.05 18.9 8.3 90.8 0.03 0.55 0.57 194% 1% -91%

Noble Corp NE Buy 31.46 42 34% 75% 0.67 2.89 3.70 3.90 10.9 8.5 8.1 0.66 3.42 3.89 1% 8% 0%

Ocean Rig UDW ORIG Buy 18.19 28 54% 65% 0.47 0.84 2.00 2.65 21.7 9.1 6.9 0.37 1.72 2.20 26% 16% 21%

Pacific Drilling PACD Buy 10.14 14 38% 72% 0.21 0.42 0.95 1.25 24.1 10.7 8.1 0.18 0.78 1.25 19% 22% 0%

Rowan RDC Neutral 30.96 36 16% 86% 0.29 1.96 2.60 4.80 15.8 11.9 6.4 0.29 2.40 4.26 0% 8% 13%

Transocean RIG Buy 42.49 55 29% 77% 1.24 4.12 4.60 4.00 10.3 9.2 10.6 1.12 4.30 3.64 11% 7% 10%

Seadrill SDRL Buy 38.00 50 32% 131% 0.63 3.02 3.25 3.10 12.6 11.7 12.3 0.83 3.39 3.66 -24% -4% -15%

Mean 86% 12.1 10.2 19.2

Onshore Drilling

Helm & Payne* HP Sell 109.95 80 -27% NA 1.56 5.67 6.05 5.05 19.4 18.2 21.8 1.62 6.31 7.06 -4% -4% -28%

Nabors NBR Sell 26.23 21 -20% NA 0.21 1.02 1.15 1.50 25.7 22.8 17.5 0.35 1.16 1.92 -40% -1% -22%

Precision Drilling PDS NC 12.95 NC - NA - - - - 21.2 16.0 11.9 (0.00) 0.81 1.08 - - -

Patterson UTI PTEN Sell 33.09 22 -34% NA 0.31 1.16 1.40 1.00 28.5 23.6 33.1 0.31 1.42 1.93 -1% -1% -48%

Mean 23.7 20.2 21.1

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



OFS EBITDA & Cash Flow Valuation

Source: Thomson Reuters, Guggenheim Securities, LLC

Price Mkt Net Dt 2014E FCF EBITDA EV / EBITDA CFPS P / CFPS

Company 5/30 Cap Cap FCFPS Yield 13 14E 15E 13 14E 15E 13 14E 15E 13E 14E 15E

S&P 500 1,924 9.0 9.1 8.9

Large Cap Services

Baker Hughes 70.52 30,745 15% 1.72 2.4% 3,871 4,582 4,840 8.8 7.4 7.0 6.51 7.87 8.30 10.8 9.0 8.5

Halliburton 64.64 54,590 26% 2.17 3.4% 6,185 7,034 7,799 9.7 8.6 7.7 5.26 6.28 6.99 12.3 10.3 9.2

Schlumberger 104.04 135,304 10% 3.79 3.6% 12,346 13,765 15,635 11.4 10.2 9.0 7.54 8.49 9.63 13.8 12.3 10.8

Weatherford 21.69 16,758 51% (0.00) 0.0% 2,659 3,196 3,597 9.7 8.0 7.2 2.41 2.87 3.26 9.0 7.6 6.7

Mean 2.4% 9.9 8.6 7.7 11.5 9.8 8.8

Large Cap Equipment

Cameron 63.95 13,058 23% 1.51 2.4% 1,460 1,603 1,918 10.4 9.5 7.9 4.57 5.62 6.79 14.0 11.4 9.4

FMC Tech 58.06 13,655 28% 1.57 2.7% 938 1,203 1,474 15.7 12.2 10.0 2.99 3.63 4.38 19.4 16.0 13.3

Nat Oil Varco 81.87 35,126 -2% 4.75 5.8% 4,223 4,722 5,055 8.2 7.3 6.8 7.28 8.09 8.65 11.2 10.1 9.5

Tenaris 44.85 26,474 -9% 0.63 1.4% 2,796 2,736 3,057 9.0 9.2 8.2 3.62 3.53 4.00 12.4 12.7 11.2

Mean 3.1% 10.8 9.6 8.3 14.3 12.5 10.8

SMid Cap Svcs & Equipment

Aker Solutions kr 105.00 kr 28,770 18% 0.62 0.6% kr 3,951 kr 4,607 kr 5,277 8.4 7.2 6.3 kr 10.64 kr 11.39 kr 13.52 9.9 9.2 7.8

C&J Energy Svcs 30.61 1,696 20% (0.02) -0.1% 190 202 219 9.9 9.3 8.6 2.56 2.80 3.08 12.0 10.9 9.9

Core Laboratories 159.85 7,173 58% 6.38 4.0% 362 382 401 20.6 19.5 18.5 5.87 6.46 6.97 27.2 24.7 22.9

Carbo Ceramics 137.57 3,178 -15% 1.39 1.0% 172 188 223 17.8 16.2 13.7 5.77 6.26 7.40 23.8 22.0 18.6

Dresser-Rand 61.20 4,681 45% 1.58 2.6% 475 481 558 12.5 12.3 10.6 4.20 3.94 4.62 14.6 15.5 13.2

Dril-Quip 102.22 4,174 -33% 0.43 0.4% 260 297 356 14.4 12.6 10.5 4.95 5.65 6.81 20.7 18.1 15.0

Forum Energy Tech 33.04 3,079 22% 1.88 5.7% 279 335 364 12.5 10.4 9.6 2.09 2.44 2.66 15.8 13.5 12.4

Frank's International 23.84 3,660 -31% 0.30 1.3% 451 457 499 7.2 7.1 6.5 2.47 1.71 1.87 9.7 13.9 12.7

Oceaneering 72.05 7,782 -1% (0.18) -0.2% 751 857 975 10.3 9.1 8.0 5.30 6.08 7.00 13.6 11.9 10.3

Oil States Int'l 107.58 5,708 15% (1.66) -1.5% 822 738 760 7.6 8.4 8.2 11.18 10.57 10.88 9.6 10.2 9.9

Superior Energy Svcs 33.19 5,198 26% 0.28 0.8% 1,105 1,146 1,370 6.1 5.9 4.9 5.46 5.68 6.96 6.1 5.8 4.8

U.S. Silica Holdings 50.57 2,719 33% 0.40 0.8% 160 198 267 18.3 14.8 11.0 1.57 2.80 3.80 32.3 18.0 13.316,936 18,550 20,854 76 81 93

Mean 1.3% 12.1 11.1 9.7 16.3 14.5 12.6

Offshore Drilling

Atwood Oceanics* 49.35 3,208 35% (11.04) -22.4% 547 567 770 8.4 8.1 6.0 7.10 7.22 9.77 7.0 6.8 5.1

Diamond 51.06 7,072 13% (4.87) -9.5% 1,302 1,328 1,766 6.1 6.0 4.5 7.56 7.52 9.39 6.8 6.8 5.4

Ensco plc 52.66 12,186 26% (1.17) -2.2% 2,409 2,357 2,629 7.0 7.1 6.4 8.81 8.52 9.25 6.0 6.2 5.7

Hercules Offshore 4.54 735 51% 0.32 7.1% 299 386 290 6.1 4.7 6.3 1.22 1.59 1.12 3.7 2.9 4.1

Noble Corp 31.46 7,994 39% (2.63) -8.4% 1,952 2,491 2,689 7.0 5.5 5.1 6.35 7.75 8.14 5.0 4.1 3.9

Ocean Rig UDW 18.19 2,397 48% (1.07) -5.9% 563 808 905 10.2 7.1 6.3 2.63 4.17 4.96 6.9 4.4 3.7

Pacific Drilling 10.14 2,205 50% (2.71) -26.7% 360 557 767 12.2 7.9 5.7 1.11 1.91 2.74 9.1 5.3 3.7

Rowan 30.96 3,861 18% (11.63) -37.6% 597 764 1,149 8.8 6.8 4.5 4.14 5.15 7.73 7.5 6.0 4.0

Transocean 42.49 15,339 31% 0.16 0.4% 3,522 3,598 3,340 6.8 6.6 7.1 7.18 7.72 7.19 5.9 5.5 5.9

Seadrill 38.00 18,734 46% (0.20) -0.5% 2,748 3,043 3,139 10.8 9.8 9.5 4.46 4.92 5.04 8.5 7.7 7.5

Mean -10.6% 8.3 7.0 6.1 6.6 5.6 4.9

Onshore Drilling

Helm & Payne 109.95 11,890 -14% (1.27) -1.2% 1,401 1,525 1,423 8.0 7.4 7.9 10.27 11.15 10.91 10.7 9.9 10.1

Nabors 26.23 7,802 35% (0.56) -2.1% 1,664 1,777 1,942 6.7 6.3 5.8 5.33 5.09 5.46 4.9 5.2 4.8

Precision Drilling 12.95 3,786 33% (0.12) -0.9% 631 797 946 8.0 6.3 5.3 1.63 2.34 2.68 7.9 5.5 4.8

Patterson UTI 33.09 4,781 15% (0.92) -2.8% 919 946 917 5.8 5.6 5.8 4.99 5.69 5.68 6.6 5.8 5.8

Mean -1.8% 7.1 6.4 6.2 7.5 6.6 6.4

*PDS estimates in CAD. All units in $m except per share data.



OFS EPS Comp


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

Large Cap Services

SLB Schlumberger EPS 4.79 5.65 6.75 1.01 1.15 1.29 1.35 1.21 1.35 1.50 1.59

Consensus EPS 5.69 6.78 1.36 1.51 1.63



HAL Halliburton EPS 3.15 3.80 4.30 0.67 0.73 0.83 0.93 0.73 0.87 1.05 1.15

Consensus EPS 3.97 5.09 0.91 1.11 1.23



BHI Baker Hughes EPS 2.69 3.90 4.20 0.65 0.61 0.81 0.62 0.84 0.85 1.07 1.14

Consensus EPS 4.15 5.34 0.89 1.16 1.29



WFT Weatherford EPS 0.60 1.10 1.50 0.15 0.15 0.23 0.07 0.13 0.21 0.35 0.43

Consensus EPS 1.08 1.66 0.21 0.34 0.41



Large Cap Equipment

CAM Cameron International EPS 3.28 3.90 5.00 0.70 0.79 0.81 1.00 0.75 0.85 1.08 1.23

Consensus EPS 3.92 4.91 0.87 1.09 1.24



FTI FMC Technologies EPS 2.11 2.70 3.40 0.43 0.48 0.53 0.69 0.57 0.63 0.69 0.81

Consensus EPS 2.70 3.34 0.63 0.70 0.80



NOV National Oilwell Varco EPS 5.52 6.15 6.60 1.29 1.33 1.34 1.56 1.40 1.46 1.60 1.69

Consensus EPS 6.12 6.89 1.47 1.57 1.67



TS Tenaris EPS 2.62 2.60 3.05 0.72 0.72 0.51 0.69 0.72 0.70 0.61 0.71

Consensus EPS 2.78 3.07 0.70 0.63 0.72





OFS EPS Comp



SMid Cap Services & Equipment

AKSO-NOAKSO Aker Solutions EPS kr 5.25 kr 5.80 kr 7.45 kr 0.99 kr 1.40 kr 1.46 kr 1.40 kr 1.12 kr 1.41 kr 1.62 kr 1.66

Consensus EPS kr 6.82 kr 8.71 kr 1.66 kr 1.73 kr 1.89

Consensus EPS-High kr 8.63 kr 11.57 kr 2.02 kr 1.96 kr 2.34

Consensus EPS-Low kr 5.40 kr 7.10 kr 1.36 kr 1.35 kr 1.63

CJES C&J Energy Services EPS 1.21 1.00 1.05 0.46 0.39 0.24 0.13 0.21 0.21 0.26 0.32

Consensus EPS 1.23 2.14 0.26 0.35 0.38



CLB Core Laboratories EPS 5.32 5.85 6.30 1.22 1.32 1.36 1.43 1.38 1.34 1.50 1.63

Consensus EPS 5.93 6.75 1.34 1.52 1.61



CRR Carbo Ceramics EPS 3.70 3.95 4.75 0.76 0.71 1.31 0.90 0.80 0.91 0.06 1.17

Consensus EPS 4.28 5.69 0.95 1.24 1.28



DRC Dresser-Rand EPS 3.00 2.70 3.35 0.43 0.69 0.64 1.24 0.22 0.39 -- --

Consensus EPS 2.65 3.18 0.40 0.85 1.18



DRQ Dril-Quip EPS 4.23 4.85 5.90 0.85 1.05 1.12 1.20 1.04 1.15 1.27 1.39

Consensus EPS 5.01 6.15 1.16 1.33 1.44



FET Forum Energy EPS 1.46 0.74 0.95 0.33 0.72 0.44 0.37 0.40 0.41 0.45 0.48

Consensus EPS 1.81 2.27 0.42 0.48 0.52



FI Frank's Intl. EPS 1.98 1.30 1.45 0.60 0.85 0.34 0.37 0.27 0.31 0.35 0.37

Consensus EPS 1.28 1.45 0.31 0.34 0.35



OII Oceaneering Intl. EPS 3.40 4.00 4.55 0.69 0.91 0.96 0.86 0.84 1.01 1.07 1.08

Consensus EPS 4.04 4.70 1.01 1.13 1.06



OIS Oil States Intl. EPS 6.18 5.30 5.60 1.80 1.50 1.42 1.47 1.34 1.15 1.31 1.49

Consensus EPS 5.48 6.31 1.22 1.39 1.53



SPN Superior Energy EPS 1.56 1.50 2.25 0.40 0.72 0.43 0.30 0.26 0.39 0.40 0.44

Consensus EPS 1.71 2.45 0.41 0.52 0.51





OFS EPS Comp



Offshore Drillers

ATW Atwood Oceanics EPS 5.32 4.95 6.80 1.10 1.28 1.37 1.57 1.28 0.78 1.26 1.62

Consensus EPS 5.02 7.36 0.97 1.17 1.69



DO Diamond Offshore EPS 4.77 4.10 5.60 1.26 1.33 1.22 0.96 0.93 0.90 1.10 1.16

Consensus EPS 3.71 4.70 0.67 0.98 1.17



ESV Ensco EPS 6.16 5.60 6.00 1.36 1.55 1.69 1.56 1.23 1.47 1.59 1.31

Consensus EPS 5.68 5.87 1.37 1.51 1.57



HERO Hercules Offshore EPS 0.24 0.55 0.05 (0.02) 0.01 0.11 0.14 0.22 0.10 0.11 0.12

Consensus EPS 0.55 0.57 0.03 0.11 0.18


Consensus EPS-Low 0.37 0.07 (0.01) 0.03 0.07

NE Noble Drilling EPS 2.89 3.70 3.90 0.59 0.63 0.85 0.82 1.03 0.67 0.92 1.07

Consensus EPS 3.42 3.89 0.66 0.84 0.92



ORIG Ocean Rig UDW EPS 0.84 2.00 2.65 0.04 0.10 0.30 0.30 0.24 0.47 0.66 0.63

Consensus EPS 1.72 2.20 0.37 0.62 0.56



PACD Pacific Drilling EPS 0.42 0.95 1.25 0.07 0.10 0.14 0.12 0.10 0.21 0.26 0.37

Consensus EPS 0.78 1.25 0.18 0.23 0.27



RDC Rowan EPS 1.96 2.60 4.80 0.55 0.57 0.42 0.42 0.28 0.29 0.75 1.28

Consensus EPS 2.40 4.26 0.29 0.69 1.09



RIG Transocean EPS 4.12 4.60 4.00 0.93 1.08 1.37 0.73 1.43 1.24 1.00 0.92

Consensus EPS 4.30 3.64 1.12 0.87 0.82



SDRL Seadrill EPS 3.02 3.25 3.10 0.69 0.96 0.60 0.79 0.59 0.63 0.57 0.67

Consensus EPS 3.39 3.66 0.83 0.82 0.89



Land Drillers

HP Helmrich & Payne EPS 5.67 6.05 5.05 1.40 1.36 1.44 1.47 1.56 1.43 1.56 1.50

Consensus EPS 6.31 7.06 1.48 1.62 1.68



NBR Nabors EPS 1.02 1.15 1.50 0.46 0.10 0.20 0.26 0.16 0.21 0.36 0.42

Consensus EPS 1.16 1.92 0.22 0.35 0.43



PTEN Patterson-UTI Energy EPS 1.16 1.40 1.00 0.38 0.28 0.23 0.27 0.25 0.31 0.41 0.43

Consensus EPS 1.42 1.93 0.31 0.42 0.45





OFS Valuations & Risks


Ticker Valuation Risks

BHI BHI currently trades at approximately 18x our 2014 EPS and 7x our 2014 EBITDA estimates. Our 12-month

price target of $55 is based on 13.5x our forw ard 4 quarter EPS and 5.5x our forw ard 4 quarter EBITDA

estimates.

In addition to the macro environment being more robust than w e currently expect, BHI could outperform should its asset turnover

improve, w hich in turn w ould push operating margins higher. In 2013, BHI‘s PPE turnover w as 2.6x, vs. 2.7x for HAL and 3.0x for

SLB. How ever, given BHI‘s higher mix of product sales (i.e., manufacturing vs. services), w e believe it should have higher PPE

turnover than its peers. Should BHI execute on its current ―self-help‖ initiatives and deliver peer-leading turnover, our estimates

w ould likely prove too conservative.

HAL HAL currently trades at approximately 17x our 2014 EPS and 8x our 2014 EBITDA estimates. Our 12-month


estimates.

HAL‘s U.S. onshore execution has been excellent, and should the company be able to demonstrate higher EPS grow th into 2015,

our estimates w ould prove to be too low . Admittedly, EPS grow th more in-line w ith current consensus w ould support higher target

multiples as w ell.

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

price target of $130 is based on 19.0x our 2015 EPS and 11.5x our 2015 EBITDA estimates.

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 19x our 2014 EPS and 8x our 2014 EBITDA estimates. Our 12-month


estimates.

This year, WFT needs to 1) execute on both its strategic divestitures, 2) high-grade its core portfolio of businesses to focus on

higher margin projects, and 3) deliver +/-$1bn in free cash f low from higher earnings, improved w orking capital turns, and low er

capex. It‘s a tall order, but should the company deliver—particularly on the free cash f low generation—its relative valuation should

begin to improve. How ever, w ith its early production facilities contracts in Iraq not likely to be completed until 3Q14, the company

remains susceptible to further cash losses associated w ith this w ork, and potential disappointments w ith respect to cash f low

generation.

CAM CAM currently trades at approximately 16x our 2014 EPS estimate and 10x our 2014 EBITDA estimate. Our

12-month price target of $75 reflects a multiple of 17.0x our forw ard 4 quarter EPS and 10.5x our forw ard 4

quarter EBITDA estimates.

Although the stock has started to act better recently, investor confidence in management‘s ability to execute remains low .

Although w e believe the low level of confidence should be view ed as a low bar—and therefore easy to deliver upon—w e

acknow ledge that failure to execute could leave CAM in a value trap zip code.

FTI FTI currently trades at approximately 21x our 2014 EPS and 12x our 2014 EBITDA estimates. Our 12-month

price target of $75 reflects a multiple of 22.0x our 2015 EPS and 13.0x our 2015 EBITDA estimates.

Execution continues to be the biggest risk for FTI. In our view , management needs to deliver on its stated goal of mid-teens

margins, and overruns and delays on the current backlog to get full credit for the 30% y/y increase in revenue/tree in backlog.

NOV NOV currently trades at approximately 13x our 2014 EPS estimate and 7x our 2014 EBITDA estimate. Our 12-

month price target of $100 reflects a multiple of 15.0x our forw ard 4 quarter EPS and 8.5x our forw ard 4

quarter EBITDA estimates.

Many investors still believe that NOV only w orks as a stock w hen backlog is grow ing (i.e., book-to-bill is greater than 1x) and

margins are expanding. Whereas last year, orders w ere strong and margins w eak, the concern for 2014 is the exact opposite:

that orders w ill be w eak even as margins improve modestly q/q. In our view , this conventional approach to the stock is more

consistent w ith a philosophy of momentum investing in oil services—a philosophy that does not apply in the current slow /no

grow th environment. How ever, w ithin a more relevant framew ork of sustainable competitive advantage, low capital intensity, and

high cash return, w e believe NOV screens w ell.

TS TS currently trades at approximately 17x our 2014 EPS and 9x our 2014 EBITDA estimates. Our 12-month

price target of $47 is based on 15.5x our 2015 EPS and 8.5x our 2015 EBITDA estimates.

The trade case before the ITC remains a w ildcard for TS and other U.S. OCTG manufacturers. The nine countries against w hich

the industry f iled the trade petition (―the P9‖) still accounted for more than 50% of all OCTG imports as recently as 3Q13, so a

meaningful tariff ruling by the ITC could tighten the pipe supply-demand balance for 2H14 and 2015, and boost spot OCTG prices.

How ever, w e believe the industry‘s case against the P9 countries has w eakened not only by the evidence of continued imports

from P9 manufacturers (in the face of the potential for retroactive penalties), but by the the late December preliminary f inding of

―de minimis‖ countervailing duties on OCTG from India and Turkey.






AKSO We arrive at our price target of kr125/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 21.6x multiple on our 2014 EPS estimate and a 16.8x 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.

CJES CJES currently trades at approximately 9x our 2014 EBITDA and 11x our 2014 OCFPS estimates. Our 12-

month price target of $20 is based on 6.0x our forw ard four-quarter EBITDA and 6.5x our forw ard four-

quarter OCFPS estimates.

In our view , short of a major macro shift in the E&P spending outlook, w e believe much of CJES‘s organic grow th option value has

been deferred. Should E&P spending grow at a faster rate than w e now expect, how ever, our estimates could prove too low .

CLB We arrive at our price target of $170 per share by triangulating betw een our P/E valuation framew ork, yield-

based metrics, 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 28.5x multiple on our 2014 EPS

estimate and a 27.7x 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. In addition,

w e see yield-based metrics magnifying the benefit of outsized returns, free cash f low grow th, and a fuller

payout strategy. In our view , CLB shares w ill continue to benefit from yield uplif t, as payouts grow , providing

catalysts for the shareholders.

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 $110 per share by triangulating betw een our P/E valuation framew ork, yield-

based metrics, 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 25.9x multiple on our 2014 EPS

estimate and a 24.4x multiple on our 2015 EPS estimate. Our DCF valuation implies a value of $110 per share,

given strong grow th 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.

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 throughout 2014, CRR‘s stock could rise. In the near term,

short covering may keep upw ard pressure on shares.

DRC DRC currently trades at approximately 23x our 2014 EPS and 12x our 2014 EBITDA estimates. Our 12-month

price target of $67 is based on 20.0x our forw ard four-quarter EPS and 11.5x our forw ard four-quarter

EBITDA estimates.

As a leading compression manufacturing and services company, DRC‘s grow th is highly correlated w ith energy infrastructure

investment… investment that throughout 2013 w as ―slipping to the right.‖ Should these projects stop slipping and get booked,

orders in 2014 could prove to be far stronger than the +15% level built into our model, and visibility of earnings grow th in 2015

w ould improve. Macroeconomic shocks or a falling oil price environment could result in budget constraints and further delays and

project slippage, leaving dow nside risk to our grow th estimates.

DRQ We arrive at our price target of $110/sh by calibrating against our P/E valuation framew ork and our



our 2015 EPS estimate. Our DCF valuation implies a value of $110/sh, given strong grow th over the explicit

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

The permitting delays in the Gulf of Mexico plagued drilling activity in the region during 2010 and 2011. The slow dow n continues to

negatively impact DRQ‘s w ellhead and other offshore equipment businesses. In recent months permit issuance has accelerated,

but persistent w eakness in the Gulf of Mexico remains a risk to future earnings – w hereas the Gulf of Mexico represented 44%

and 31% of revenues in 1Q10 and full year 2011, respectively. Also, 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.

FET We arrive at our price target of $32 per share by calibrating betw een our P/E valuation framew ork and our


capital implies a valuation range betw een an 17.1x multiple on 2013 EPS and a 18.7x multiple on our 2014

EPS estimate. Our DCF valuation implies a value of $32/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.

FI FI currently trades at approximately 18x our 2014 EPS and 10x our 2014 EBITDA estimates. Our price target

of $30 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.

OII We arrive at our price target of $80/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 20.0x multiple on our 2014 EPS estimate and a 16.0x 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.

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. Given OII‘s strategy to pass on low er margin contracts w ith Petrobras, one of the largest incremental consumers of

offshore rigs, OII may place their grow th prospects at risk. Also, if regulatory issues persist in the GoM, they may impede the

recovery activity. If offshore rig activity proves stronger than expectations, OII w ould likely benefit.

OIS OIS currently trades at approximately 18x our 2014 EPS and 8x our 2014 EBITDA estimates. Our price target

of $96 is based on 17.5x our forw ard 4 quarter EPS and 7.5x our forw ard 4 quarter EBITDA estimates.

In our view , the dow nside risk to OIS is minimal, given the event-driven catalysts of the Accommodations spin and M&A potential

of ―remain co.‖ How ever, should the company not receive IRS approval for REIT conversion, w e w ould expect the

Accommodations business to trade at a valuation level closer to non-REIT comps such as Black Diamond (BDI CN, Not Covered,

C$29.26), w hich now trades at 7.7x consensus 2014 EBITDA. Under this scenario, our sum-of-the-parts valuation w ould have

dow nside to $100—about in-line w ith w here the stock currently trades. If the REIT conversion materializes earlier than expected,

our valuation may be conservative.

SPN We arrive at our price target of $34 per share by calibrating betw een our P/E valuation framew ork and our



our 2015 EPS estimate. Our DCF valuation implies a value of $34/sh, given strong grow th over the explicit

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

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. Investors have become fairly secure that oil prices w ill remain w ithin recent ranges. If U.S.

production grow th bumps up against domestic refining capacity, w ithout potential to relieve any potential glut, or exports from Iran

or Libya recover faster than expected, creating a disorderly international crude market, oil prices could fall. While global upstream

activity may see a negative impact from low er oil prices, shorter lead time, & higher marginal costs, North American

unconventional activity may fall off. Reduced activity, both domestic and international, w ould negatively impact our SPN thesis. If

N.A. activity surprises on the upside, SPN shares could strengthen.






ATW We arrive at a price target of $58/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 $65/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 $60/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 $5/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 $42/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 $28/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.

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 $36/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 $55/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 7x our 2014 EBITDA and 9x our 2014 CFPS estimates. Our 12-month

price target of $80 is based on 17.0x our 2015 EPS estimate and 6.0x our 2015 EBITDA estimate.

Our investment thesis is predicated upon the idea that the rate of HP‘s market share gains remains relatively stable, and that

overall utilization suffers as a result of a market dow nturn in 2015. How ever, should HP‘s share gains accelerate into any potential

dow nturn next year, w e could be underestimating f leet utilization and earnings. Additionally, w e expect several large tenders this

year (for w ork in 2015-16) in countries like Saudi Arabia. Should HP w in any of these large international tenders, our estimates

w ould prove too conservative, as w e have assumed essentially f lat international revenue and operating income.

NBR NBR currently trades at approximately 6x our 2014 EBITDA and 5x our 2014 CFPS estimates. Our 12-month

price target of $21 is based on 15.0x our 2015 EPS estimate and 5.0x our 2015 EBITDA estimate.

The risk in being NEUTRAL a low multiple stock is that a re-rate event (e.g., management change, execution of meaningful non-

core asset divestiture, etc.) could occur at any point. We continue to believe the event risk in NBR is low , as the leverage,

challenged asset base, and shareholder rights plan create challenges for potential activists.

PTEN PTEN currently trades at approximately 5x our 2014 EBITDA and 6x our 2014 CFPS estimates. Our 12-month

price target of $22 is based on 4.0x our 2015 EBITDA and 4.0x our 2015 CFPS estimates.

We continue to believe that the market for AC-electric rigs remains under-supplied by +/-600 rigs, 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. How ever, our expectations of a

commodity-price induced reduction in drilling activity in 2015 should create an air pocket in overall rig demand—including demand

for AC-electric rigs. Should the market hold up next year, our estimates for PTEN w ould very likely prove too conservative, and

much of the dow nside risk w ould be mitigated.



Additional Companies Mentioned (priced as of 5/30/14)


Company Name Ticker Price Rating Company Name Ticker Price Rating

Apache Corp APA 93.21$ NEUTRAL Petroleo Brasileiro Petrobras SAPBR 93.21$ NC

Anadarko Petroleum Corp APC 102.85$ BUY Petronas NA NC

BG GROUP PLC BG.-LN 1,221.00$ NC N/A RDS'A 1,221.00$ NC

BHP Billiton Ltd BHP 67.87$ NC Repsol SA REP-MC 67.87$ NC

BP PLC BP 50.45$ NC Statoil ASA STO 50.45$ NC

CONOCOPHILLIPS COP 79.92$ BUY Talisman Energy Inc TLM 79.92$ NC

Chevron Corp CVX 122.79$ NC Total SA TOT 122.79$ NC

Eni SpA E 50.97$ NC TULLOW OIL PLC TLW 50.97$ NC

Hess Corp HES 91.29$ NEUTRAL Exxon Mobil Corp XOM 91.29$ NC

Marathon Petroleum Corp MPC 89.38$ NC Woodside Petroleum Ltd WPL 89.38$ NC

Murphy Oil Corp MUR 61.67$ NC Seadrill Partners LLC SDLP 61.67$ NC

Noble Energy Inc NBL 72.07$ BUY North Atlantic Drilling Ltd NADL 72.07$ NC

PEMEX NA NC



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.



https://guggenheimsecurities.bluematrix.com/sellside/Disclosures.action

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 101 55.19% 23 22.77%

Neutral 77 42.08% 5 6.49%

Sell 5 2.73% 0 0.00%

OTHER DISCLOSURES

This research is for our clients and prospective clients only. Other than disclosures relating to Guggenheim Securities and its affiliates, this research is based on current public information that we considerreliable, but we do not represent it is accurate or complete, and it should not be relied on as such. We seek to update our research as appropriate, but various regulations may prevent us from doing so.Other than certain industry reports published on a periodic basis, the large majority of reports are published at irregular intervals as appropriate in the research analyst's judgment. Guggenheim Securitiesconducts a full-service, integrated investment banking and brokerage business, and one or more of its affiliates conduct an investment management business. Guggenheim Securities is a member of SIPC(http://www.sipc.org). Our salespeople, traders, and other professionals may provide oral or written market commentary or trading strategies to our clients and our employees trading for our own account thatreflect opinions that are contrary to the opinions expressed in this research. Guggenheim Securities or certain of its affiliates conducts an investment management business, trades for its own account, andconducts an investment business, and may make investment decisions that are inconsistent with the recommendations or views expressed in this research.

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.

This research is not an offer to sell or the solicitation of an offer to buy any security. It does not constitute a personal recommendation or take into account the particular investment objectives, financial situations,or needs of individual clients. Clients should consider whether any advice or recommendation in this research is suitable for their particular circumstances and, if appropriate, seek professional advice, includingtax advice. The price and value of investments referred to in this research and the income from them may fluctuate. Past performance is not a guide to future performance, future returns are not guaranteed,and a loss of original capital may occur. Fluctuations in exchange rates could have adverse effects on the value or price of, or income derived from, certain investments.

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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