2012-09-20 Market Power Shifting to Subsea Equipment Players - D. Gacicia

People. Ideas. Success.

Guggenheim Securities, LLC Oil Services & Equipment

September 20, 2012

Darren Gacicia

(212) 293-3054

[email protected]

Robert Miller - Associate

(972) 638-5504

[email protected]

Market Power Shifting to Subsea Equipment Players Upgrading FTI to Buy From Neutral

GUGGENHEIM SECURITIES, LLC See pages 53 - 54 for analyst certification and important disclosures.

Investment Thesis

Market Power Shifting Toward Subsea Equipment Players. The credit crisis and recession, coupled with the Macondo incident, slowed offshore activity and

demand of equipment from 2008-2010. Market power shifted to offshore operators, as oilfield equipment players competed to win awards amid more limited

subsea tree demand. The inflection of offshore activity in 2011 marked a migration in market power back to the oilfield equipment players. In this report, we track

the shift in market power with a “deep dive” into the subsea tree business, through an in-depth analysis of subsea tree demand, manufacturing capacity, orders,

and backlog across the industry. Our analysis distills to our conclusion that visibility for demand from offshore fleet growth, rising utilization, and emergent signs of

capacity constraints likely translate into revenue growth (asset turns), improved mix/pricing (higher margins), and returns for oilfield equipment players. Given

operating leverage across equipment businesses, we believe the stage is set for upward revisions to consensus estimates and valuation multiples for subsea

players, and oilfield equipment players more broadly.

High Visibility for Subsea Tree Demand. Our revised subsea tree forecast calls for nearly three times the number of deliveries in 2017 from 2011, a ~19%

CAGR annually. We calibrated our forecast for subsea trees against the Guggenheim/PFC offshore rig supply/demand model and field-by-field data from Infield

(pgs. 10-18). Our new forecast falls below our previous estimates and below popular industry outlooks, as we tailored our assumptions to better represent

relationships with prior tree deliveries, especially related to well water depths. Albeit tempered from our original estimates, strong growth in our new forecast is

anchored by existing orders that support near-term estimates and high visibility into offshore fleet growth (pgs. 12-13). Likewise, our analysis of demand by region

and company, relative to existing orders, planned projects, and potential projects, implies strong new order flow if operators look to schedule deliveries in front of

projects in the coming years (pgs. 15-18).

Capacity Utilization Increasing. Rising demand for subsea trees likely lifts production capacity utilization from below 50% to above 70% and beyond during the

next five years. Within this report, our estimation of manufacturing capacity by major manufacturer and region suggests the subsea tree market is tightening (pgs.

20-22). The key constraints on capacity remain engineers and the supply chain (emphasis on forging), both less adjustable in the near term due to longer training

cycles and capacity/logistical solutions requiring time. As industry backlogs sit above two times current annual production capacity and new order lead times

appear poised to expand, we see potential for pricing power on the horizon (pgs. 24-25, 28).

Asset Turns and Operating Margins Set to Drive ROE Equation. Improved capacity utilization, pricing power, and expanding new order lead times look set to

drive revenue growth, asset turns, and operating margins (pg. 26). A steady rise in average revenue per tree across industry backlogs, either from improved mix or

pricing, supports our view of improving incremental economics, especially as lower margin backlog rolls off (pg. 23). The absorption of production capacity and

lengthening of lead times may also give equipment providers sway to push for greater subsea tree design standardization, likely a further boost to turns of existing

capacity and a benefit to bottom line economics (pgs. 21, 24-25). In our view, subsea tree estimates remain low as we emerge from the recession-driven lull in

tree orders and deliveries (pg. 12). Amid low expectations, we see room for upward revisions to consensus estimates and re-rating of multiples higher as investors

discount greater earnings growth.

Upgrading FTI to Buy from Neutral, Raising Price Target to $64, Increasing 2013 estimates. We are upgrading FMC Technologies to Buy from Neutral and

raising our price target to $64 from $46. Likewise, we are raising our 2013 EPS estimate to $2.70 from $2.65. As the largest subsea tree provider, FTI has the

greatest leverage to improving subsea market economics. Over the next 12 months, we believe the positive trajectory of its subsea business will overshadow risks

to its Surface business, implicit from volatility in North American activity. If our bullish thesis plays out, we anticipate upward consensus estimate revisions and

multiple expansion to propel FTI shares higher (pgs. 3, 34-36).

Positive Read-Throughs for CAM, AKSO, & GE (not covered). As most industry players will likely benefit from improved subsea economics, our analysis of the

subsea market supports our estimates and outlooks for our other Buy-rated oilfield equipment companies: Cameron (pgs. 41-42) and Aker Solutions (pgs. 43-44).

Guggenheim Securities, LLC | 972.638.5500 | guggenheimpartners.com

Market Power Shifting to Subsea Equipment Players - Upgrading FTI to Buy From Neutral PAGE 2

FTI – Upgrading to Buy – Seeking Leverage to Improving Subsea Economics

We are upgrading FTI to Buy from Neutral. We see improving subsea economics

overshadowing North American-related risks to the Surface business. Although risks for

near-term quarters from lower margin subsea backlog remains, we believe the upside from

asset turns from completion of near-term deliveries and incrementally better economics

baked into backlog should outweigh near-term risks that Subsea margins may fall below

2H12 guidance of 12.5-13.5% (pg. 35). Forecasted to expand from ~55% of operating

income, we think the outlook for the continued improvement in the trajectory of Subsea

margins since 4Q11 will remain the key driver for FTI shares. Given operating leverage in

FTI’s business model from outsourcing, we see potential upward revisions to consensus

earnings estimates with growth in the Subsea business. Additionally, we see valuation

multiple expansion for the shares as the combination of growth and a favorable return

structure hits stride. We would take advantage of the current consolidation within FTI shares

as an entry point.

Raising Our Price Target & 2013 Estimate. We are raising our price target to $64 from

$46. Given our more positive outlook, we are raising our 2013E EPS to $2.70 from $2.65.

Subsea Technologies Growth to Take Lead. After gaining 600bps of market share from

2009-2011, a competitive bidding environment and lower margin backlog has forced 2012

Subsea margin guidance down to 11-12%. Improved revenue/tree in backlog and visibility

into accelerating deliveries into 2013 (pg. 35), likely improves revenue, asset turns, and

margins through 2H12. As a result, we are more confident in 2H12 Subsea margin guidance

for an uptick to 12.5-13.5%. As industry manufacturing capacity tightens and lead times

expand, we see room for improved pricing and greater standardization of tree orders, which

may propel subsea economics ahead of our current estimates.

Surface Technologies Remains a Risk, but Reflected in Estimates. Our forecast for a

2H12 decline in North American activity risks 18-20% 2012 margin guidance for the Surface

business and leads our margin numbers lower for 2013, as backlog protection fades.

Exposure to North American surface wellheads, as well as pressure pumping equipment,

rentals, and consumables, lead us to revise our estimates below current guidance (pg. 36).

Although strength in international businesses may offset downside, negative revision risk

likely remains. In our view, upside in the Subsea business will offset this drag.

-

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

1Q

10

2Q

10

3Q

10

4Q

10

1Q

11

2Q

11

3Q

11

4Q

11

1Q

12

2Q

12

3Q

12E

4Q

12E

1Q

13E

2Q

13E

3Q

13E

Segm

ent

Revenue (

$m

)

Subsea Technologies Surface Technologies Energy Infrastructure

15%

25%

35%

45%

55%

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

12E

1Q

13E

3Q

13E

1Q

14E

3Q

14E

1Q

15E

3Q

15E

Retu

rn o

n E

quity(A

nnualz

ed Q

uart

ers

)

Source: Company Reports, Guggenheim Securities, LLC


FTI Annualized Return on Equity

FTI Segment Revenue Breakdown

Source: FactSet, Guggenheim Securities, LLC

Company Category 2008 2009 2010 2011 2012E 2013E 1Q12 2Q12 3Q12E 4Q12E 1Q13E 2Q13E 3Q13E 4Q13E

FMC Technologies EPS 2.94 2.93 3.06 1.64 2.00 2.70 0.41 0.43 0.56 0.60 0.63 0.65 0.67 0.74

Previous EPS 2.00 2.65 0.56 0.60 0.63 0.64 0.66 0.72

Consensus EPS 2.09 2.61 0.57 0.64 0.56 0.61 0.67 0.73

Consensus EPS-High 2.16 2.90 0.60 0.71 0.63 0.66 0.73 0.87

Consensus EPS-Low 2.00 2.00 0.54 0.57 0.52 0.50 0.49 0.49



Guggenheim Subsea Tree Forecast Expected to Grow at 19% CAGR 2011-2017

269 258

386 338

296

237 262

464 496

539

613

736 753 757 807

853

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2011

2012E

2013E

2014E

2015E

2016E

2017E

2018E

2019E

2020E

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eries

Worldwide Subsea Tree Expected Deliveries Worldwide Subsea Tree Deliveries

Guggenheim Annual Worldwide Subsea Tree Deliveries History & Forecast

Source: Infield, PFC Energy - Guggenheim

Actual subsea tree deliveries into

the market

Subsea tree deliveries expected

to nearly triple from 2011 to 2017

The subsea tree market expected

to grow at 19% CAGR from

2011-2017

Our forecast sees 2012 surpass

previous high delivery year of

2007



Manufacturing Capacity Utilization Suggests Market Power for Equipment Names

138

173

182

230

298

306

331

336

351

363

384

410

498

515

534

548

558

628

713

718

718

64%

74%

67%

75%

82%

54%

70%

66%58%

44%

70%

63%

77%

66%

55%

43%

47%

74%

70%

75%

85%

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0%

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anufa

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apacity

Capaci

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tiliz

ation

Subsea Tree Manufacturing Capacity Capacity Utilization

Guggenheim Estimated Subsea Tree Production Capacity

Source: Infield, Guggenheim Securities, LLC

The ramp in estimated

deliveries in 2012 and

beyond looks set to rapidly

increase utilization of

subsea tree manufacturing

capacity across the

industry, despite capacity

expansions for all of the

major equipment providers.

The subsea tree market is

headed back to utilization

levels that heralded high

margins, high assets turns,

and favorable return

structures during that last

cycle.

We see potential for rising utilization to push

toward more standardized tree designs in order to

minimize engineering bottlenecks seen with

specially designed trees.



Visible Near-Term Demand Supports Estimates & Suggests Strong Order Flow

464 496

539

613

736 753 757 807

853

436 396

253

156 110

52 36 17 8

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900

2012E 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E

Subse

a T

ree

Deliv

eries

Guggenheim Subsea Tree Demand Forecast Ordered Wedge

Guggenheim Worldwide Subsea Tree Demand vs. Current Orderbook Existing orders and delivery dates support

our delivery forecast for 2012 and 2013.

In our view, the market does not see the

ramp in scheduled deliveries during this

year and next, which should both drive

capacity utilization and burn off lower

margin backlog awarded during the recent

downturn.

Unordered portions of demand should

translate into strong new order numbers

across companies over the next few

years.




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599 632 6

92

769

868

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eries

Guggenheim's Previous Forecast

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464

496

539 6

13

736

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296

237

262

436

396

253

156

110

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2013E

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Total Forecast Demand Delivered/Ordered

New Forecast More Conservative Than Previous Estimates

Guggenheim Annual Worldwide Subsea Tree

Deliveries History & Forecast


Guggenheim Previous Forecast, Before Tighter

Calibration Against Historical Deliveries

Source: PFC Energy - Guggenheim

Our forecast becomes more conservative after back testing

historical well counts and tree deliveries. The key drivers of the

downward revisions stem from lowered expected subsea tree

demand from shallow water projects.



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464

496

539 6

13

736

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2013E

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Total Forecast Demand Delivered/Ordered438

462

452

432

318 3

74

311

551

661

664 7

23

798

0

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500

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900

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2012E

2013E

2014E

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2016E

Subse

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ree A

ward

s

FMC Industry Awards

Multi-Year Book-to-Build Ratio Above “1” ─ Positive Demand Indicator

Guggenheim Annual Worldwide Subsea Tree

Deliveries History & Forecast


FMC Forecasted Industry Subsea Tree Awards as

Attributed to Quest Offshore

Source: FMC Company Presentation, Guggenheim Securities, LLC

Awards can run higher than

deliveries in any given year, as

future large orders may have

multi-year lead times.

Our forecast differs in both

approach and scale relative to

other benchmarks published in

company presentations.

Although a Quest number, FTI

guidance sees ~400-500 wet

trees ordered in 2012.



Key Drivers & Assumptions



Guggenheim/PFC Offshore Rig Demand Model Supports & Constrains Subsea

Tree Demand Outlook

Source: RigLogix, PFC Energy-Guggenheim Source: RigLogix, PFC Energy-Guggenheim

20 22 26 32 36 38 44 55 63 69 94 92 88

92 97

83 82 84 80

88

103 105 101 100 99

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2012E 2013E 2014E 2015E 2016E

Num

ber

of

Rig

s

7500+ WD 5000-7500 WD3000-5000 WD 1000-3000 WD400-1000 WD UDW SupplyUDW & DW Supply UDW&DW&MW Supply

99 99 98 101 109

331 331 330 333 339

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500

2012E 2013E 2014E 2015E 2016E

Num

ber

of

Rig

s

300-400000-300Premium & High End JackupsStandard & Lower Spec Jackups

Global Supply / Demand of Floaters Global Supply / Demand of Jackups

We derive our subsea tree model from our offshore rig supply/demand

model. Within this context, we cross-reference input data from PFC

Energy with Infield data.

Potential demand could be much greater if not constrained by rig

undersupply. Accordingly, as further new floater constructions are

announced, our model would continue to suggest upward demand

revisions for subsea trees.

Historically, shallow water activity has not proved a large source of subsea

tree demand. Our forecast for high jackup utilization, especially for

premium rigs, may offer potential upside to subsea tree demand, as plays

become both more complex and remote from existing infrastructure.



Assumptions Applied to Guggenheim/PFC Offshore Rig Supply/Demand Model

2005 2006 2007 2008 2009 2010 2011 2012E 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E

Percent of Wells Needing Tieback (by well type)

Exploration 5% 5% 5% 5% 5% 5% 5% 10% 10% 10% 10% 10% 10% 10% 10% 10%

Appraisal 5% 5% 5% 5% 5% 5% 5% 10% 10% 10% 10% 10% 10% 10% 10% 10%

Development 90% 90% 90% 90% 90% 90% 90% 100% 100% 100% 100% 100% 100% 100% 100% 100%

Percent of Wells Needing a Wet Tree (by water depth)

0-300 WD 5% 5% 5% 5% 5% 5% 5% 7% 7% 7% 7% 7% 7% 7% 7% 7%

300-400 WD 5% 5% 5% 5% 5% 5% 5% 10% 10% 10% 10% 10% 10% 10% 10% 10%

400-1000 WD 10% 10% 10% 10% 10% 10% 10% 20% 25% 30% 35% 40% 45% 45% 45% 45%

1000-3000 WD 30% 30% 30% 30% 30% 30% 30% 40% 45% 50% 55% 60% 65% 65% 65% 65%

3000-5000 WD 60% 60% 60% 60% 60% 60% 60% 65% 75% 80% 85% 90% 95% 95% 95% 95%

5000-7500 WD 80% 80% 80% 80% 80% 80% 80% 90% 95% 100% 100% 100% 100% 100% 100% 100%

7500+ WD 80% 80% 80% 80% 80% 80% 85% 95% 100% 100% 100% 100% 100% 100% 100% 100%

Rig/Frictional Delays

% 0-400 WD Slippage 0% 0% 0% 0% 0% 0% 0% 0% 0%

% 1,000 WD Slippage 10% 13% 15% 15% 15% 15% 15% 15% 15%

Only a smaller number of E&A

wells have needed trees, but we

see more of these wells

transitioned to production in the

future.

We made assumptions to conform previous

subsea tree deliveries with prior well count

data, using “rules of thumb” for the probability

for tree demand among water depths.

As incremental plays become more remote,

moving away from established infrastructure,

we see the penetration of subsea tree demand

increasing, especially in the midwater.

Our forecast factors a certain amount of

demand slippage, as rig shortages push

demand further out.

Source: Guggenheim Securities, LLC



Midwater Subsea Tree Demand Growth Foreshadows Path for Ultra/Deepwater

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Shallow Water Midwater Deepwater Ultra Deepwater

Subsea Tree Deliveries by Water Depth

Growth in subsea tree demand

from Midwater drilling grew

slowly with growth of the floater

fleet and transition of drilling

activity from exploration to

development.

The slow growth of subsea tree

demand for Ultra/Deepwater

projects has begun to expand

slowly, similar to what was seen

with the evolution of Midwater

demand.

Shallow water penetration has

also begun to expand, as fields

become both more complex and

more remote.




Floater Fleet & Subsea Tree Market Grow in Tandem


Total Subsea Tree Deliveries to Track Floater Deliveries

Exhibit 1: Guggenheim

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GLobal F

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Total Deliveries Total Floaters

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rders

Total Orders Total Floaters

We see the continued growth of

the floater fleet as directly

correlated with subsea tree

deliveries.

New Orders to Recover with Fleet Growth

The recession and Macondo incidents de-

railed the progression of subsea tree

orders and deliveries. We expect growth

to resume its correlation with floater fleet

growth and drilling activity.

Source: Infield, RigLogix, Guggenheim Securities, LLC Note: 2012 Subsea Orders are shown year-to-date

Source: Infield, RigLogix, Guggenheim Securities, LLC



Near-Term Demand More Firm, Rising Activity Supports Possible Demand

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Delivered/Ordered Planned Project - Potential Orders Possible Project - Potential Orders

Worldwide Subsea Tree Demand Tiered by Ordered, Planned, and Possible


Ordered and planned demand supports

estimates for 2012-2014.

Visibility on firm demand trails off later in

the forecast. In our view, an increase in

the number of announcement for EPC

and FEED studies for offshore projects

illustrate the initial steps to converting

“Possible” projects into “Planned” project.

The number of planned projects that jump

in deliveries in 2012 and 2013 remains

sustainable, even if “Possible” demand

proves at risk.

The risk lies in companies underbidding

projects, without giving weight to the wave

of “Possible” project demand.



0

100

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600

700Petr

obra

s

Tota

l

BP

Shell

Chevro

n

Sta

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Exx

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Gazp

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mie

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Subse

a T

rees

Deliv

eries

Ordered / Undelivered Planned Project - Potential Orders Possible Project - Potential Orders

Demand from Key Operators Represents Wave of New Orders

Top Offshore Operator Subsea Tree Orders and Demand

Sources: Infield, Guggenheim Securities, LLC

The largest offshore operators have

ordered few trees in relation to their total

potential demand. In particular, the largest

operators still must order 989 trees in

order to meet planned project demand.

CVX and PBR are known for greater

engineering content and longer lead

times for orders.

BP and Shell are known for more subsea

standardization.

Wall of ordered trees and a constrained

supply chain may lead to greater subsea

tree order standardization.

Petr

obra

s

Tota

l

BP

Shell

Chevro

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ON

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To

tal T

op

40

Oth

er

To

tal

Ordered / Undelivered 389 91 34 83 50 51 31 45 3 11 11 18 12 9 4 12 8 12 17 18 6 3 5 22 10 14 21 10 17 17 0 15 1 1 0 10 0 0 3 4 1,068 105 1,173

Planned Project - Potential Orders 62 111 120 82 125 39 72 37 48 16 10 11 14 25 8 15 25 29 12 2 10 12 14 0 9 1 5 4 2 10 8 2 13 9 1 3 3 11 6 3 989 101 1,090

Possible Project - Potential Orders 241 289 286 242 222 220 167 115 128 111 107 80 78 63 70 54 40 24 32 41 42 41 34 26 22 22 11 22 16 5 24 14 17 17 26 11 21 12 11 12 3,016 420 3,436

Total 692 491 440 407 397 310 270 197 179 138 128 109 104 97 82 81 73 65 61 61 58 56 53 48 41 37 37 36 35 32 32 31 31 27 27 24 24 23 20 19 5,073 626 5,699



Market Share by Top 40 Subsea Tree Customers 2000-2011

Operator

Total

Orders

'00-'11 Cameron

Aker

Solutions

GEOG

VetcoGray FMC Dril-Quip Other

Petrobras 832 27% 21% 19% 29% - 3%

Statoil 590 2% 29% 16% 53% - -

Total 295 23% 24% 2% 52% - -

Shell 275 15% 1% 37% 39% 7% -

BP 253 59% - 5% 36% - -

ExxonMobil 222 38% - 26% 36% - -

Chevron 206 28% - 41% 31% 1% -

Eni 98 42% 9% 18% 30% 1% -

Talisman 91 16% 9% 43% 32% - -

Anadarko 76 - - 9% 91% - -

Apache 67 72% 3% 10% 12% 3% -

Nexen 58 7% - 90% 2% 2% -

Canadian Natural Resources 57 35% - 9% 56% - -

ConocoPhillips 56 20% - 16% 36% 29% -

BHP Billiton 55 75% 2% 24% - - -

Woodside 55 - 16% - 84% - -

BG Group EGPC Petronas 43 100% - - - - -

Hess 41 71% 7% 10% 12% - -

Centrica 39 - - 59% 8% 33% -

Marathon 40 28% 53% 20% - - -

Maersk 34 32% - 68% - - -

Suncor Energy/Petro-Canada 33 - - - 100% - -

KNOC 33 27% - 70% - 3% -

Murphy 33 15% 48% - 30% 6% -

BG Group 31 71% - 6% 23% - -

Husky 30 100% - - - - -

ATP 29 45% - - 3% 52% -

Petronas 29 - 7% 31% 62% - -

Walter 26 - - 4% - 96% -

ADNEC 26 50% - 31% 19% - -

Tullow 26 4% - 15% 77% 4% -

CNOOC 26 - - - 100% - -

Premier 23 - - 74% 26% - -

Noble 20 75% - 10% 5% 10% -

GDF Suez 19 16% - 16% 68% - -

PetroSA 19 - - 21% 79% - -

EnQuest 18 - 33% 22% 44% - -

PEMEX 17 - - - 100% - -

Fairfield 16 94% - 6% - - -

Reliance 16 - 100% - - - -

Market Share 2000-2011

Total

Orders

'00-'11

% of

Market

Total Top 40 3,953 93%

Other 275 7%

Total Tree Demand 2000-2011 4,228

The largest 40 operators represent nearly

all of subsea tree demand.


Green indicates #1 provider status



Unordered Trees Demographics Point to Expansion of Subsea Tree Market

0

100

200

300

400

500

600

700

UK

Angola

USA

Aust

ralia

Nig

eria

Bra

zil

Norw

ay

Russ

ia (

FSU

)

Indonesi

a

Congo (

Bra

zzavill

e)

India

Ghana

Canada

Mala

ysi

a

Egypt (M

editerr

anean)

Equato

rial G

uin

ea

Moza

mbiq

ue

Falk

land I

slands

Isra

el

Italy

Aze

rbaijan (

FSU

)

Mexi

co

Republic

of

South

Afr

ica

Tanza

nia

Lib

ya

Maurita

nia

Sie

rra L

eone

Chin

a (

PRC)

Irela

nd

Russ

ia (

FSU

) (S

akhalin

)

Ivory

Coast

Phili

ppin

es

Trinid

ad

Tunis

ia

Lib

eria

Myanm

ar

Bru

nei

Guyane (

Fre

nch

Guia

na)

Vie

tnam

Oth

er

Unord

ere

d S

ubse

a T

rees

Possible Planned

0

500

1,000

1,500

2,000

2,500

3,000

SW MW DW UDW

Unord

ere

d S

ubse

a T

rees

Planned Possible

We expect Ultra/deepwater demand to

grow comparable to Midwater subsea

tree demand over time.

Unordered Midwater Demand Remains Significant

Traditional & Non-Traditional Sources of Demand





Guggenheim “Watch List” for Subsea Tree Awards

Historical Historical

Operator Field Country Trees Preference #1 Preference #2 FTI CAM GE AKSO DRQ

Gazprom Shtokmanovskoye Russia (FSU) 72 - - - - -

Maersk Chissonga (Block 16) Angola 39 GEOG VetcoGray Cameron - - - - -

Total Egina (OML 130 Ex OPL 246) Nigeria 39 FMC Aker Solutions - - - - -

BP Green Canyon 826 Mad Dog South USA 38 Cameron FMC - - - - -

Shell Bonga North (OML 118 Ex OPL 212) Nigeria 29 FMC GEOG VetcoGray - - - - -

Chevron Lucapa (Block 14) Angola 28 GEOG VetcoGray FMC - - - - -

Chevron Rosebank UK 28 GEOG VetcoGray FMC - - - - -

BP Shah Deniz (Phase 2) Azerbaijan (FSU) 26 Cameron FMC - - - - -

Fairfield Darwin (North West Hutton Phase 2) UK 21 Cameron GEOG VetcoGray - - - - -

ExxonMobil Scarborough (WA-1-R) Australia 16 Cameron FMC - - - - -

GDF Suez Petrel (NT/RL1 & WA-6-R) (Bonaparte LNG) Australia 16 FMC Cameron - - - - -

Woodside Calliance (Ex Brecknock Sth) (WA-31-R Browse) Australia 16 FMC Aker Solutions - - - - -

Petrobras Franco (Phase 2) (2-ANP-1-RJS) Brazil 16 FMC Cameron - - - - -

Gazprom Kamennomysskoye More (Obskaya Bay) Russia (FSU) 16 - - - - -

Shell Mississippi Canyon 391-392 & 348 Appomattox USA 16 FMC GEOG VetcoGray - - - - -

Tullow Tweneboa (TEN) (Deepwater Tano) Ghana 14 FMC GEOG VetcoGray - - - - -

Chevron Nsiko (OML 140 Ex OPL 249) Nigeria 14 GEOG VetcoGray FMC - - - - -

Chevron Negage (Block 14) Angola 13 GEOG VetcoGray FMC - - - - -

Total Gindungo (Kaombo 1) (Block 32) Angola 12 FMC Aker Solutions - - - - -

Total Canela (Kaombo 2) (Block 32) Angola 12 FMC Aker Solutions - - - - -

Total Louro (Kaombo 2) (Block 32) Angola 12 FMC Aker Solutions - - - - -

PTT Cash/Maple (AC/RL7) Australia 12 - - - - -

Petrobras Carioca (Phase 1) (BM-S-9) (Sugarloaf) Brazil 12 FMC Cameron - 2 - - -

Tullow Enyenra (TEN) (Ex Owo) (Deepwater Tano) Ghana 12 FMC GEOG VetcoGray - - - - -

Noble Leviathan (Med) Israel 12 Cameron GEOG VetcoGray - - - - -

Chevron Aparo (OML 132 & OPL 249) Nigeria 12 GEOG VetcoGray FMC - - - - -

ONGC Krishna-Godavari UD-1 (KG-DWN-98/2) (D5) India 11 - - - - -

ConocoPhillips South Belut Indonesia 11 FMC - - - - -

ExxonMobil Erha North Extension (OML 133) Nigeria 11 Cameron FMC - - - - -

BP Plutao (PSVM) (Block 31 North East) Angola 10 Cameron FMC - 11 - - -

ExxonMobil Mbulumbumba (Kizomba Block 15) Angola 10 Cameron FMC - - - - -

ExxonMobil Vicango (Kizomba Block 15) Angola 10 Cameron FMC - - - - -

BP Urano (Block 31 South East) Angola 10 Cameron FMC - - - - -

Petrobras Lula North (BM-S-11) Brazil 10 FMC Cameron - - - - -

Tullow Ntomme (TEN) (Deepwater Tano) Ghana 10 FMC GEOG VetcoGray - - - - -

PEMEX Kosni Mexico 10 FMC Cameron - - - - -

Hess Green Canyon 468 Pony (Knotty Head North) USA 10 Cameron FMC - - - - -

Total Gengibre (Kaombo 1) (Block 32) Angola 9 FMC Aker Solutions - - - - -

Total Mostarda (Kaombo 2) (Block 32) Angola 9 FMC Aker Solutions - - - - -

Shell Brunei Government Geronggong Brunei 9 - - - - -

E.ON Ruhrgas Huntington UK 9 GEOG VetcoGray Cameron 4 - - - -

BP Saturno (PSVM) (Block 31 North East) Angola 8 Cameron FMC - 13 - - -

BP Cesio (PCC) (Block 18) Angola 8 Cameron FMC - - - - -

BP Chumbo (PCC) (Block 18) Angola 8 Cameron FMC - - - - -

Noble Aphrodite (Cyprus Block 12) Cyprus 8 Cameron GEOG VetcoGray - - - - -

Kosmos Odum (West Cape Three Points) Ghana 8 - - - - -

Chevron Gendalo Indonesia 8 GEOG VetcoGray FMC - - - - -

PEMEX Lakach Mexico 8 FMC Cameron - - - - -

Anadarko Windjammer/Barquentine (Prosperidade) Mozambique 8 FMC GEOG VetcoGray - - - - -

Shell DeSoto Canyon 353 & 397 & MC 393 Vicksburg USA 8 FMC GEOG VetcoGray - - - - -

Current Field Installations

Methodology: Our

“Watch List” is

comprised of the

largest potential

orders for planned

projects that

currently remain

unordered. We

have determined

the preferred

subsea tree

providers for each

operator through

an assessment of

market shares for

orders since 2000.

Sources: Infield,

Guggenheim Securities, LLC



Manufacturing Capacity



Total Market Subsea Tree Manufacturing Capacity by Company


46 67 68 68 92 100 117 117 121 121 121 121 199 199 199 199 209 239 269 269 269

44 46 46 70

83 83 86 86 86 87 96 103

103 115 115 129 129

169 189 189 189

40 40 40

49 61 61

63 63 63 74 86 86

95 95 95 95 95

95

115 115 115

3 15 23

32

51 51 51 54 54 54

54 73

74 79 98 98 98

98

113 118 118

5 5 5

11

11 11 14 16 27 27

27 27

27 27 27 27 27

27

27 27 27

-

100

200

300

400

500

600

700

800

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012E

2013E

2014E

2015E

Subse

a T

ree M

anufa

cturing Capaci

ty

FMC Cameron GEOG VetcoGray Aker Solutions Dril-Quip

Methodology. Using a history of the maximum number of deliveries across

different regions over the last 20+ years, we estimated the manufacturing capacity

of each of the major manufacturers in the subsea tree industry. As production and

supply chains are set up geographically, we organized our maximum production

capacity between Middle East/Asia/Australia, Europe/Africa, and North

America/South America.

Constraints on Manufacturing Capacity. We anticipate that nominal

manufacturing capacity relies on roofline, machines, and number of work

shifts. A look at these elements alone likely overstates real production

capacity. Accordingly, we assess recent trends in maximum actual

deliveries as a better reflection of real manufacturing capacity. In our view,

the most significant constraint on real capacity remains engineers to

quarterback projects from design to physical production. Training an

engineer may take 2-5 years, with team/project leaders running on the long

end of the spectrum. Secondly, there are numerous potential constraints in

the supply chain, most notably forging.

Announced Capacity Additions

FMC – Announced adding capacity in both Southeast Asia and Brazil

CAM – Announced a doubling of capacity in Brazil

AKSO – Announced a doubling of its capacity in its Norwegian and

Malaysian facilities by 2014. Adding 200 engineers to their London office.

GEOG VetcoGray – Announced capacity expansion in Southeast Asia




Manufacturing Capacity Utilization Suggests Market Power for Equipment Names

138

173

182

230

298

306

331

336

351

363

384

410

498

515

534

548

558

628

713

718

718

64%

74%

67%

75%

82%

54%

70%

66%58%

44%

70%

63%

77%

66%

55%

43%

47%

74%

70%

75%

85%

-

100

200

300

400

500

600

700

800

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012E

2013E

2014E

2015E

Subse

a T

ree M

anufa

cturin

g C

apacity

Capaci

ty U

tiliz

ation

Subsea Tree Manufacturing Capacity Capacity Utilization



The ramp in estimated

deliveries in 2012 and

beyond looks set to rapidly

increase utilization of

subsea tree manufacturing

capacity across the

industry, despite capacity

expansions for all of the

major equipment providers.

The subsea tree market is

headed back to utilization

levels that heralded high

margins, high assets turns,

and favorable return

structures during that last

cycle.

We see potential for rising utilization to push

toward more standardized tree designs in order to

minimize engineering bottlenecks seen with

specially designed trees.



9 27

4

5

12

2

14

11

3

16

15

16

32

42

24

28

14 6

0 57

86

113 175

115

144

134

131

77 1

58

177 229

184

140

128

112

19 45

33 5

5

57

47

73

77

71

66

96

65

125

112

132

81

136

-

50

100

150

200

250

300

350

400

450

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

Subse

a T

ree D

eliv

eries

ME/Asia/Australia Europe/Africa NA/LA

5 8 12 5 4 21 2 9 23 1847 53 59

22 38 3388

5858

176

92134135 93

211170119

236231

189167230

110137

139

9831

26

57

8246 81

99

98

67

102

122172171

167

167

205 93

128

0

50

100

150

200

250

300

350

400

450

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

New

Subse

a T

ree O

rders


Deliveries & Manufacturing Capacity by Region

Subsea Tree Production Capacity by Region Subsea Tree Deliveries

Subsea Tree New Orders

More orders from Australia and Asia, as well as more visibility for

drilling activity in the region, has spurred an expansion of

capacity.

Recession and Macondo limited

the growth in activity.

Recession and

Macondo

reduced order

growth.

The visible expansion in activity in the Gulf of Mexico and Brazil

looks set to grow new tree orders from current depressed levels.

A fast ramp in activity in traditional markets, like the North Sea

and West Africa, looks set to increase orders from these basins.

Meanwhile, growth in activity from non-traditional African markets

will lead to growth in the overall market.


9

27

30

30

38

38

43

43

43

48

49

49

50

59

63

77

77

87

132

137

137

94

94

100

138

187

187

191

191

195

195

195

221

285

285

285

285

285

285

285

285

285

35

52

52 62 7

3

81

97

102

113

120

140

140 163

171

186

186

196

256 296

296

296

-

100

200

300

400

500

600

700

800

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012E

2013E

2014E

2015E

Subse

a T

ree M

anufa

cturing Capaci

ty




“Calorie Count” Subsea Backlog Indicates Uptick in Industry Economics

6.46.4

7.2

7.3 7.3

7.9

8.1 8.1

8.2

8.1

6.0

6.5

7.0

7.5

8.0

8.5

1Q10 2Q10 3Q10 4Q10 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12

$/S

ubse

a T

ree

Backlog - $/Subsea Tree

We expect a backlog conversion at not much longer than two

years. Accordingly, we expect the burn off of low Rev/Tree

backlog will yield to higher Rev/Tree backlog, likely leading to

improved Asset Turns and Margins across equipment players.

Note: Average of FTI, CAM, & ASKO backlog figures.


Revenue/Subsea Tree Improving in Industry Backlog ($M)

More revenue per tree in backlog, either

translates to an improvement in mix (more

manifolds or control systems) or better

average pricing since the bottom of the

cycle.



Marking Capacity Constraint and Pricing Power Through New Order Lead Time

300

500

700

900

1,100

1,300

1,500 1

Q0

1

3Q

01

1Q

02

3Q

02

1Q

03

3Q

03

1Q

04

3Q

04

1Q

05

3Q

05

1Q

06

3Q

06

1Q

07

3Q

07

1Q

08

3Q

08

1Q

09

3Q

09

1Q

10

3Q

10

1Q

11

3Q

11

1Q

12

Day

s fr

om

Ne

w O

rde

r to

De

live

ry

Trailing Twelve Month Average New Order Lead Time

Longer lead times from new orders to

delivery marked the tightening of

production capacity and foundation of

pricing power during the last cycle.

New order lead times appear to show

signs of finding a base and moving higher.

We continue to see the expansion of order

lead times as a positive indicator for the

direction of equipment player economics.

As lead times expand, operators

concerned about near-term delivery dates

will either move toward more standardized

tree designs or pay more for specialized

product that requires more engineering.

Industry Lead Times May Show Signs of Lengthening Again




0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

1Q

1999

4Q

1999

3Q

2000

2Q

2001

1Q

2002

4Q

2002

3Q

2003

2Q

2004

1Q

2005

4Q

2005

3Q

2006

2Q

2007

1Q

2008

4Q

2008

3Q

2009

2Q

2010

1Q

2011

4Q

2011

LTM

Rolli

ng A

vera

ge

Days

to D

eliv

er

Cameron Aker Solutions

GEOG VetcoGray FMC

Dril-Quip

Positive Lead Times Trend: Field Complexity & Shift in the Company Pack

0

500

1,000

1,500

2,000

2,500

1Q

02

3Q

02

1Q

03

3Q

03

1Q

04

3Q

04

1Q

05

3Q

05

1Q

06

3Q

06

1Q

07

3Q

07

1Q

08

3Q

08

1Q

09

3Q

09

1Q

10

3Q

10

1Q

11

3Q

11

1Q

12

LTM

Rolli

ng A

vera

ge

Days

to D

eliv

er

SW MW DW

Move to greater field complexity within ultradeepwater, greater

drilling depths, or pre-salt structures will likely lead to greater

need for engineering content.

DRQ is an outlier that will only look to win

small, high margin tree awards.

Lead times across companies appear to

be in the same channel, possibly showing

signs of inflection.





0.8

0.9

1.0

1.1

1.2

1.3

1.4

100

150

200

250

300

350

1Q

06

2Q

06

3Q

06

4Q

06

1Q

07

2Q

07

3Q

07

4Q

07

1Q

08

2Q

08

3Q

08

4Q

08

1Q

09

2Q

09

3Q

09

4Q

09

1Q

10

2Q

10

3Q

10

4Q

10

1Q

11

2Q

11

3Q

11

4Q

11

1Q

12

2Q

12

Ass

et

Turn

s

Rolli

ng N

TM

Subse

a T

ree D

eliv

eries

Rolling NTM Subsea Tree Deliveries Asset Turns

Asset Turns and Deliveries in Aggregate

Note: Average of FTI and CAM


Since companies book revenues on

percentage of completion, a wave of

scheduled deliveries over the next four

quarters implies higher revenues and

asset turns in the coming quarters.

Accordingly, we see potential for asset

turns to recover to heights seen during the

last cycle.



Company Breakdown



Rising Backlog Coverage Has Bullish Implications

0.0

0.5

1.0

1.5

2.0

2.5

3.0

-

100

200

300

400

500

600

FMC Cameron GEOG VetcoGray Aker Solutions

Years o

f Back

log (B

ack

log/A

nnual C

apacity

)

Num

ber

of

Subse

a T

rees

in B

ack

log

-

100

200

300

400

500

600

1Q

05

2Q

05

3Q

05

4Q

05

1Q

06

2Q

06

3Q

06

4Q

06

1Q

07

2Q

07

3Q

07

4Q

07

1Q

08

2Q

08

3Q

08

4Q

08

1Q

09

2Q

09

3Q

09

4Q

09

1Q

10

2Q

10

3Q

10

4Q

10

1Q

11

2Q

11

3Q

11

4Q

11

1Q

12

2Q

12

Num

ber

of

Subse

a T

rees

in B

ack

log

Cameron Aker Solutions GEOG VetcoGray

FMC Dril-Quip

Total Subsea Trees in Backlog Subsea Trees in Backlog Over Time

CAM’s flat backlog likely

illustrates less aggressive

bidding.

FTI and GE appear to have

gained share amid more

competitive pricing.

Source: Infield, Guggenheim Securities, LLC Source: Infield, Guggenheim Securities, LLC

Except for Aker Solutions, each

company has over two years of

backlog relative to current annual

production capacity.



Comparative New Orders

-

50

100

150

200

250

300

1Q

01

3Q

01

1Q

02

3Q

02

1Q

03

3Q

03

1Q

04

3Q

04

1Q

05

3Q

05

1Q

06

3Q

06

1Q

07

3Q

07

1Q

08

3Q

08

1Q

09

3Q

09

1Q

10

3Q

10

1Q

11

3Q

11

1Q

12

3Q

12

Subse

a T

ree N

ew

Ord

ers

Cameron Aker Solutions GEOG VetcoGray FMC Dril-Quip

-

50

100

150

200

250

300

350

400

450

2005 2006 2007 2008 2009 2010 2011

Subse

a T

ree N

ew

Ord

ers

Cameron Aker Solutions GEOG VetcoGray FMC Dril-Quip

FTI and GE appear to have

gained share amid more

competitive pricing.

Bigger mix for CAM in 2008,

likely helped CAM from 2009-

2011.

Both 4Q and 1Q continue to demonstrate seasonally strong

patterns, as operators set budgets and place orders ahead of

newly scheduled projects.




Date Operator Value ($m) Field Region Country

Subsea

Trees Delivery Comments Scope of Supply

05-Jul-12 Statoil $200 Gullfaks South Field Europe Norway 7 To commence in 2Q13 7 subsea production trees, 7 wellhead systems, 2

integrated protection structures with manifolds, and

additional controls and equipment

29-Mar-12 Petrobras $1,500 Brazil Pre-Salt L Amer Brazil 130 To commence in 2014 4 year Pre-Salt agreement ~ 130 subsea trees, subsea

multiplex controls and related tools and equipment

29-Mar-12 "initial call-off" (from contract above)

$900 Brazil Pre-Salt L Amer Brazil 78

20-Mar-12 Statoil $70 H-Nord Europe Norway 1 Throughout 2013 1 subsea production tree, 1 manifold, 1 multiphase

meter, an integrated template structure, one umbilical,

two wellheads and additional controls and equipment

10-Jan-12 Anadarko Lucius N Amer GOM 5 To commence in 4Q12 5 subsea production trees and 2 manifolds

09-Jan-12 Woodside $150 Greater Western Flank Phase 1 APAC Australia 6 To commence in 2H12

and continue through

2013

6 subsea production trees, 6 wellheads, 2 manifolds,

subsea and topside controls and flow line connection

systems

12-Dec-11 BP Block 18 Africa Angola 4 To be delivered in 2013 4 subsea trees, control systems, wellheads, tubing

hangers, well jumpers and subsea distribution systems

07-Dec-11 LLOG $40 Who Dat N Amer GOM 7 To commence in 2012 7 subsea production trees and control systems

30-Nov-11 Chevron $325 Wheatstone APAC Australia 11 To commence in 2013 11 subsea production trees, 11 wellheads, 3 manifolds,

subsea and topside controls and well access systems

20-Sep-11 BG Norge $135 Knarr Europe Norway 3 To commence in 2Q13 3 subsea production trees, 3 water injection trees, 6

subsea control modules, 5 wellheads, 2 manifolds and

other related equipment and controls.

27-Jun-11 Shell Prelude APAC Australia 7 7 large bore subsea production trees, production

manifolds, riser bases, subsea control systems and other

related equipment

06-Jun-11 Statoil $50 Visund Europe Norway 2 Commenced in 2Q12

and to continue through

1Q13

2 subsea production trees, 1 manifold and associated

subsea and topside control systems

02-Mar-11 Petrobras $125 L Amer Brazil 32 To commence in 2013 Represents the remaining equipment under a 107-tree

frame agreement that was announced in 2/2010

15-Feb-11 COP $96 3-fields APAC Indonesia 12 Commenced in 2011 3-year frame agreement COP Indonesia to manufacture

and supply of subsea production equipment (immediate

$57m call-off revenue). 12 subsea production trees,

wellheads, control systems and associated offshore

tooling and services.

24-Jan-11 CNOOC $85 Liuhua 4-1 APAC China 8 Commenced in 4Q11 8 subsea trees and tie-back to the existing Liuhua 11-1

field

FTI Recently Announced Subsea Tree Awards (2011-2012)




CAM Recently Announced Subsea Tree Awards (2011-2012)



Subsea


04-Jun-12 CNOOC $100 PANYU 35-1/2 APAC China 6 To commence in 2013 6 subsea production trees, production controls, 1

manifold, associated subsea equipment, rental tooling

and service support

10-Oct-11 DET NORSKE $56 JETTE Europe Norway N/A Commenced in early

2012

Wellheads, trees, flow bases, electro-hydraulic

multiplexed controls, connections, pipeline end manifolds

and other associated subsea equipment

13-Jan-11 Petrobras $72 N/A L Amer Brazil 27 Commenced in 2011,

deliveries over following

4 years

27 subsea trees & related equipment remaining from

9/2009 138-tree frame agreement



AKSO Recently Announced Subsea Tree Awards (2011-2012)


Subsea


04-May-12 Total NOK 470 Dalia Africa Angola 7 2013-2014 7 production subsea trees, 7 wellhead systems and 7

well jumper systems, and may include some contract

options

02-May-12 Murphy Undisclosed Siakap North APAC Malaysia 13 1Q13 13 subsea trees, eight manifolds, well jumpers,

engineering for topside controls and lifecycle support

services

05-Jan-12 Marathon NOK 210 Boyla Europe Norway 4 1Q13 Engineering, procurement, construction and delivery of

4r subsea trees, 4r over-trawlable subsea structures

and control systems

29-Dec-11 Statoil NOK 400 Svalin Europe Norway 2 Final Deliveries in 3Q13 2 subsea trees, 1 four-slot integrated template structure

with process distribution manifold, subsea and topside

production control systems, wellhead systems and

remote connection systems

24-Nov-11 Statoil NOK 225 Vilje Europe Norway 1 Final Deliveries in 2Q13 1 subsea tree, satellite production flowbase and

protection structure, subsea production control system,

wellhead system, remote connection system and a 150

metre static umbilical. This contract is an extension to

the subsea production system Aker Solutions' delivered

to the Vilje field in 2006.

11-Nov-11 Lundin NOK 700 Brynhild Europe Norway 3 Final Deliveries in 2Q13 1 template-manifold structure, 1 riser base, 3 subsea

trees, 3 wellhead systems, control system, a tie-in

system, 38 kilometres of umbilicals, HP riser and rental

tooling. The contract contains several options for

additional equipment, including other field developments.

11-Aug-11 Murphy Undisclosed Kikeh APAC Malaysia Undisclosed 2013 Iincludes the delivery of deepwater oil production

equipment such as subsea trees, control modules

distribution system and manifolds that will be installed at

a water depth of 1350 meters. Aker Solutions was

responsible for the delivery of the original Kikeh scope

back in 2005. It was the first deepwater development in

Malaysia and the Asia Pacific region.

30-Mar-11 Statoil NOK 1000 Fossekall-Dompap Europe Norway 11 Final Deliveries in 2Q13 3 template-manifold structures, 11 subsea trees, a

control system and a tie-in system. The contract also

contains several options for other field developments on

the Norwegian continental shelf which Statoil may

exercise.




Announced Alliances and Frame Agreements (2011-2012)


Date Operator Type Region Country Scope of Agreement

FMC Technologies29-Mar-12 Petrobras Contract L Amer Brazil 4-year agreement with Petrobras for the supply of pre-salt subsea equipment. The total award would result in approximately $1.5Bn in

revenue to FTI if all of the subsea equipment included in the agreement is ordered. The initial call-off has an approximate value of $900m

in revenue to FTI and includes 78 subsea trees. FTI's total scope of supply could include the delivery of up to 130 subsea trees, subsea

multiplex controls and related tools and equipment. The tree systems are for use offshore Brazil in water depths up to 8,200 feet. The

equipment will be engineered at FTI's South American Technology Center and manufactured at FTI's subsea facility, both of which are

located in Rio de Janeiro, Brazil. The subsea trees will achieve 70% Brazilian local content and deliveries are scheduled to commence in

2014.

01-Dec-11 Anadarko Global Alliance

Agreement

World-wide To provide subsea systems and life-of-field services for their worldwide subsea development projects. An alliance has been in place with

Anadarko and its legacy companies since 1992 to support their Gulf of Mexico exploration and production projects. The agreement will

allow FTI to broaden its support of Anadarko's expanding E&P activities worldwide, including recent discoveries offshore the East and

West coasts of Africa.

01-Mar-11 British

Petroleum

Global Frame

Agreement

World-wide 5-year global frame agreement with BP to provide subsea production systems and life-of-field services for their worldwide subsea

development projects.

15-Feb-11 ConocoPhillips

Indonesia

Country Frame

Agreement

APAC Indonesia 3-year frame agreement with ConocoPhillips Indonesia Inc. Ltd for the manufacture and supply of subsea production equipment. The

contract includes an immediate $57 million call-off and is expected to result in approximately $96 million in total revenue to FTI if all of the

subsea equipment included in the agreement is ordered. The equipment will support 3 of ConocoPhillips Indonesia's offshore fields, which

are located in approximately 300 feet (90 meters) of water offshore Indonesia in the Natuna Sea. FTI's scope of supply includes the

manufacture of up to 12 subsea production trees, wellheads, control systems and associated offshore tooling and services. The

equipment will be engineered and manufactured at FMC's facilities in Indonesia, Singapore and Malaysia, with deliveries scheduled to

commence in 2011.

21-Dec-10 Shell Enterprise

Framework

Agreement

N Amer &

L Amer

5-year Enterprise Framework Agreement (EFA) with Shell with an option to extend the agreement for an additional 5 years. This

agreement facilitates to international projects the same mutual benefits that Shell and FTI have enjoyed through a strategic GOM

relationship that has existed over the past 17 years. Under the agreement, Shell's business units in the Americas intend to utilize FTI for

all deepwater subsea equipment projects within the scope of the agreement, unless tendering is otherwise required. Specific scope of

supply includes subsea trees, mounted controls, processing equipment, manifolds, sled components, jumpers and various other hydraulic,

chemical, electrical and control systems. This agreement for deepwater subsea equipment is also available for use by other Shell global

business units as may be allowed by local commercial and legal requirements.

Broader FTI Alliance Agreement Partners Include: Shell, BP (split w/CAM), Woodside - 5/2008, BG - 4/2010, Anadarko, Noble (for GOM) - 12/2008, Cobalt - 2/2010, LLOG (for GOM) - 4/2008 and Statoil (split w/AKSO for Norway) - 9/2007

Cameron15-Mar-11 Petrobras MOU L Amer Brazil Future technology cooperation with Petrobras & includes a $30m investment in R&D facilities at two Brazilian locations

01-Mar-11 British

Petroleum

Non-Exclusive

Global Agreement

Worldwide Engineering, Procurement, Construction and Operational Support for Subsea Production Systems. The Global Agreement recognizes that

the alignment of standards, specifications and processes and the introduction of product standardization, will optimize the use of

resources, shorten execution cycles, optimize life cycle cost and deliver superior long term value. The Agreement is aimed at developing a

long-term, collaborative, performance-based relationship between BP and Cameron, maximizing the benefits to be gained of

standardization; recognizing that this is the route to enhance quality, reliability and production availability of subsea systems.



FTI – Upgrading to Buy – Seeking Leverage to Improving Subsea Economics

We are upgrading FTI to Buy from Neutral. We see improving subsea economics

overshadowing North American-related risks to the Surface business. Although risks for

near-term quarters from lower margin subsea backlog remains, we believe the upside from

asset turns from completion of near-term deliveries and incrementally better economics

baked into backlog should outweigh near-term risks that Subsea margins may fall below

2H12 guidance of 12.5-13.5% (pg. 35). Forecasted to expand from ~55% of operating

income, we think the outlook for the continued improvement in the trajectory of Subsea

margins since 4Q11 will remain the key driver for FTI shares. Given operating leverage in

FTI’s business model from outsourcing, we see potential upward revisions to consensus

earnings estimates with growth in the Subsea business. Additionally, we see valuation

multiple expansion for the shares as the combination of growth and a favorable return

structure hits stride. We would take advantage of the current consolidation within FTI shares

as an entry point.

Raising Our Price Target & 2013 Estimate. We are raising our price target to $64 from

$46. Given our more positive outlook, we are raising our 2013E EPS to $2.70 from $2.65.

Subsea Technologies Growth to Take Lead. After gaining 600bps of market share from

2009-2011, a competitive bidding environment and lower margin backlog has forced 2012

Subsea margin guidance down to 11-12%. Improved revenue/tree in backlog and visibility

into accelerating deliveries into 2013 (pg. 35), likely improves revenue, asset turns, and

margins through 2H12. As a result, we are more confident in 2H12 Subsea margin guidance

for an uptick to 12.5-13.5%. As industry manufacturing capacity tightens and lead times

expand, we see room for improved pricing and greater standardization of tree orders, which

may propel subsea economics ahead of our current estimates.

Surface Technologies Remains a Risk, but Reflected in Estimates. Our forecast for a

2H12 decline in North American activity risks 18-20% 2012 margin guidance for the Surface

business and leads our margin numbers lower for 2013, as backlog protection fades.

Exposure to North American surface wellheads, as well as pressure pumping equipment,

rentals, and consumables, lead us to revise our estimates below current guidance (pg. 36).

Although strength in international businesses may offset downside, negative revision risk

likely remains. In our view, upside in the Subsea business will offset this drag.

-

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

1Q

10

2Q

10

3Q

10

4Q

10

1Q

11

2Q

11

3Q

11

4Q

11

1Q

12

2Q

12

3Q

12E

4Q

12E

1Q

13E

2Q

13E

3Q

13E

Segm

ent

Revenue (

$m

)

Subsea Technologies Surface Technologies Energy Infrastructure

15%

25%

35%

45%

55%

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

12E

1Q

13E

3Q

13E

1Q

14E

3Q

14E

1Q

15E

3Q

15E

Retu

rn o

n E

quity(A

nnualz

ed Q

uart

ers

)



FTI Annualized Return on Equity

FTI Segment Revenue Breakdown

Source: FactSet, Guggenheim Securities, LLC

Company Category 2008 2009 2010 2011 2012E 2013E 1Q12 2Q12 3Q12E 4Q12E 1Q13E 2Q13E 3Q13E 4Q13E

FMC Technologies EPS 2.94 2.93 3.06 1.64 2.00 2.70 0.41 0.43 0.56 0.60 0.63 0.65 0.67 0.74

Previous EPS 2.00 2.65 0.56 0.60 0.63 0.64 0.66 0.72

Consensus EPS 2.09 2.61 0.57 0.64 0.56 0.61 0.67 0.73





5.1

5.2

6.8

7.8

7.7

8.3

8.1

8.6

8.8

8.1

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

1Q

10

2Q

10

3Q

10

4Q

10

1Q

11

2Q

11

3Q

11

4Q

11

1Q

12

2Q

12

3Q

12E

4Q

12E

1Q

13E

2Q

13E

3Q

13E

4Q

13E

4

5

6

7

8

9

10

Revenue (

$m

)

Backlo

g $

/Subse

a T

ree

Subsea Backlog Subsea Backlog ($/tree)

Key Drivers of FMC Technologies Economics Paint Bullish Picture

18.4

%

16.6

%

14.2

%

12.3

%

10.2

%

10.5

%

11.5

%

7.2

%

8.4

%

10.2

%

12.8

%

13.3

%

13.5

%

13.7

%

13.9

%

14.1

%

500

600

700

800

900

1,000

1,100

1,200

1,300

1,400

1,500

1Q

10

2Q

10

3Q

10

4Q

10

1Q

11

2Q

11

3Q

11

4Q

11

1Q

12

2Q

12

3Q

12E

4Q

12E

1Q

13E

2Q

13E

3Q

13E

4Q

13E

6%

8%

10%

12%

14%

16%

18%

20%

Revenue (

$m

) EBIT

Marg

in

Subsea Tech. Revenue Subsea Tech. EBIT %

6%

8%

10%

12%

14%

16%

18%

20%

1.0

1.1

1.1

1.2

1.2

1.3

1.3

1.4

1.4

1.5

1Q10 2Q10 3Q10 4Q10 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12

EBIT

Marg

ins

Asset Turn

s

Asset Turns EBIT Margins Subsea EBIT Margin

-

20

40

60

80

100

120

140

160

180

200

1.00

1.10

1.20

1.30

1.40

1.50

1.60

1.70

1.80

1Q

06

2Q

06

3Q

06

4Q

06

1Q

07

2Q

07

3Q

07

4Q

07

1Q

08

2Q

08

3Q

08

4Q

08

1Q

09

2Q

09

3Q

09

4Q

09

1Q

10

2Q

10

3Q

10

4Q

10

1Q

11

2Q

11

3Q

11

4Q

11

1Q

12

2Q

12

Rollin

g N

TM

Subsea T

ree D

eliv

erie

s

Asset Turn

s

Asset Turns Rolling NTM Subsea Tree Deliveries

FTI Subsea margins on an

inflection pattern

Visible near-term deliveries

look set to increase revenues

and asset turns.

Both the backlog and revenue/tree track

well, indicating Subsea economics set to

improve in coming quarters.

We forecast revenue growth, but future EBIT

margins may prove conservative relative to prior

cycles, especially if our bullish outlook for the

industry materializes.

Source: Company Reports, Guggenheim Securities, LLC Source: Infield, Company Reports, Guggenheim Securities, LLC

Source: Company Reports, Guggenheim Securities, LLC Source: Infield, Company Reports, Guggenheim Securities, LLC

FTI Asset Turns & Operating Margin History FTI Asset Turns vs. NTM Subsea Tree Deliveries

FTI Subsea Revenue vs. EBIT Margin FTI Subsea Revenue vs. Backlog ($/Subsea Tree)



North American Levered Surface Business May Lag, but Factored in Estimates

19.1

%

17.6

% 18.4

%

17.5

%

17.6

%

18.2

%

19.6

% 20.4

%

20.6

%

20.3

%

19.0

%

17.5

%

16.0

%

16.0

%

16.0

%

16.0

%

15%

16%

17%

18%

19%

20%

21%

22%

1Q

10

2Q

10

3Q

10

4Q

10

1Q

11

2Q

11

3Q

11

4Q

11

1Q

12

2Q

12

3Q

12E

4Q

12E

1Q

13E

2Q

13E

3Q

13E

4Q

13E

0

50

100

150

200

250

300

350

400

450

EBIT

Marg

inRevenue (

$m

)

Surface Tech. Revenue Surface Tech. EBIT %

218

225 243 2

71 291 310 3

36

374

378

414

401

381

389

397

405

413

150

200

250

300

350

400

450

1Q

10

2Q

10

3Q

10

4Q

10

1Q

11

2Q

11

3Q

11

4Q

11

1Q

12

2Q

12

3Q

12E

4Q

12E

1Q

13E

2Q

13E

3Q

13E

4Q

13E

800

1,000

1,200

1,400

1,600

1,800

2,000

Revenue $

(m)

US L

and R

ig C

ount

Total US Land Rig Count Surface Tech. Revenue

249

256

236

316

275

452

358

404

425

366

355

337

344

351

358 385

0

100

200

300

400

500

600

700

1Q

10

2Q

10

3Q

10

4Q

10

1Q

11

2Q

11

3Q

11

4Q

11

1Q

12

2Q

12

3Q

12E

4Q

12E

1Q

13E

2Q

13E

3Q

13E

4Q

13E

200

250

300

350

400

450

500

Surf

ace B

acklo

g (

$m

)

Surfa

ce In

bound O

rders

($m

)

Surface Backlog Surface Inbound Orders




FTI Surface Tech. Revenues vs. EBIT Margin FTI Surface Tech. Backlog vs. Inbound Orders

FTI Surface Tech. Revenues vs. U.S. Land Rig Count



FMC Technologies Summary Financials


x x cIncome Statement 2011 2012E 2013E 2014E 1Q12 2Q12 3Q12E 4Q12E 1Q13E 2Q13E 3Q13E 4Q13E

Subsea Technologies 3,288.1 4,013.8 5,197.2 6,381.0 894.9 945.8 1,028.2 1,144.9 1,251.0 1,266.1 1,277.4 1,402.8

Surface Technologies 1,310.8 1,574.3 1,603.1 1,735.2 377.8 413.8 401.4 381.3 388.9 396.7 404.7 412.7

Energy Infrastructure 503.4 576.5 630.3 655.9 137.0 139.4 146.4 153.7 155.2 156.8 158.3 159.9

Intercompany eliminations (3.3) (25.4) (16.4) (16.4) (13.1) (4.1) (4.1) (4.1) (4.1) (4.1) (4.1) (4.1)

Total Revenues 5,099.0 6,139.2 7,414.2 8,755.7 1,396.6 1,494.9 1,571.8 1,675.9 1,791.0 1,815.5 1,836.3 1,971.3

Subsea Technologies 319.9 454.4 715.1 937.0 75.1 96.5 131.1 151.7 168.3 172.8 176.9 197.1

Surface Technologies 250.1 305.2 256.5 277.6 78.0 84.2 76.3 66.7 62.2 63.5 64.7 66.0

Energy Infrastructure 49.3 46.9 59.9 62.3 9.3 9.1 13.2 15.4 14.7 14.9 15.0 15.2

Corporate expense (39.4) (42.4) (53.8) (63.5) (8.5) (10.4) (11.3) (12.1) (13.0) (13.2) (13.3) (14.3)

Total EBIT 579.9 764.2 977.7 1,213.5 153.9 179.4 209.2 221.7 232.2 238.0 243.4 264.0

Interest income - 2.2 5.2 5.9 - - 1.0 1.1 1.2 1.1 1.3 1.6

Interest (expense) (8.2) (30.9) (42.0) (42.0) (3.5) (6.4) (10.5) (10.5) (10.5) (10.5) (10.5) (10.5)

Other (expense) (12.3) (77.4) (58.0) (58.0) (20.0) (28.4) (14.5) (14.5) (14.5) (14.5) (14.5) (14.5)

EBT 559.4 658.0 882.9 1,119.4 130.4 144.6 185.2 197.8 208.4 214.1 219.7 240.6

Income Tax (159.6) (170.3) (234.1) (305.7) (30.7) (40.0) (48.2) (51.4) (54.6) (56.5) (58.4) (64.5)

Minority interest (1.1) (4.8) (5.2) (5.2) (0.9) (1.3) (1.3) (1.3) (1.3) (1.3) (1.3) (1.3)

Net Income (Operating) 398.7 483.0 643.7 808.5 98.8 103.3 135.8 145.1 152.5 156.3 160.0 174.8

Other 1.9 8.6 - - - 8.6 - - - - - -

Net Income (GAAP) 400.6 491.5 643.7 808.5 98.8 111.9 135.8 145.1 152.5 156.3 160.0 174.8

EPS (GAAP)) 1.65 2.04 2.70 3.49 0.41 0.46 0.56 0.60 0.63 0.65 0.67 0.74

EPS (Operating) 1.64 2.00 2.70 3.49 0.41 0.43 0.56 0.60 0.63 0.65 0.67 0.74

Basic Shares Outstanding 241.2 240.2 237.3 230.3 240.1 240.2 240.2 240.2 239.0 237.9 236.7 235.6

Diluted Shares Outstanding 243.2 241.5 238.6 231.6 241.3 241.5 241.5 241.5 240.3 239.2 238.0 236.9

Dividend per Share - - - - - - - - - - - -

Diluted CEPS (Operating) 1.99 2.50 3.34 4.23 0.51 0.54 0.70 0.75 0.79 0.81 0.83 0.91

EBITDA 687.7 904.3 1,140.5 1,393.7 184.0 214.8 245.9 259.6 271.3 278.2 284.6 306.4

Depreciation & Amortization 107.8 140.1 162.8 180.2 30.1 35.4 36.6 38.0 39.0 40.1 41.2 42.4

Cash Flow Statement

CFO 164.8 95.7 577.5 717.0 1.7 (111.2) 104.8 100.4 99.9 181.0 188.7 108.0

CAPEX (274.0) (353.5) (296.6) (306.4) (92.0) (99.1) (78.6) (83.8) (71.6) (72.6) (73.5) (78.9)

Free Cash Flow (FCF) (109.2) (257.7) 281.0 410.6 (90.3) (210.3) 26.2 16.6 28.2 108.3 115.3 29.1

Acquisitions/Divestures/Inv. 0.3 (327.2) - - 1.0 (328.2) - - - - - -

Financing 150.0 574.8 (200.0) (400.0) 117.5 457.3 - - (50.0) (50.0) (50.0) (50.0)

Other (12.6) (15.7) - - (10.6) (5.1) - - - - - -

Increase (Decrease) in Cash 28.5 (25.8) 81.0 10.6 17.6 (86.3) 26.2 16.6 (21.8) 58.3 65.3 (20.9)

Key Balance Sheet Statistics

Total Capital 2,340.2 3,272.5 3,716.2 4,124.7 2,300.6 2,815.6 2,951.4 3,096.4 3,199.0 3,305.3 3,415.3 3,540.1

Total Debt 623.6 1,216.2 1,216.2 1,216.2 741.7 1,216.2 1,216.2 1,216.2 1,216.2 1,216.2 1,216.2 1,216.2

Net Debt 279.6 898.0 817.1 806.5 380.1 940.9 914.7 898.0 919.8 861.5 796.2 817.1

Debt/Total Capital 26.6% 37.2% 32.7% 29.5% 32.2% 43.2% 41.2% 39.3% 38.0% 36.8% 35.6% 34.4%

Net Debt/Capital 11.9% 27.4% 22.0% 19.6% 16.5% 33.4% 31.0% 29.0% 28.8% 26.1% 23.3% 23.1%

EBITDA/Interest 83.9X 29.3X 27.2X 33.2X 52.6X 33.6X 23.4X 24.7X 25.9X 26.5X 27.1X 29.2X

BVPS 5.86 7.79 9.74 11.80 6.46 6.62 7.19 7.79 8.25 8.73 9.24 9.81



Appendix: Company Subsea Data



Key Statistics: FMC Technologies

140

190

240

290

340

390

440

490

540

590

1Q

05

2Q

05

3Q

05

4Q

05

1Q

06

2Q

06

3Q

06

4Q

06

1Q

07

2Q

07

3Q

07

4Q

07

1Q

08

2Q

08

3Q

08

4Q

08

1Q

09

2Q

09

3Q

09

4Q

09

1Q

10

2Q

10

3Q

10

4Q

10

1Q

11

2Q

11

3Q

11

4Q

11

1Q

12

2Q

12

Subsea T

rees

in B

acklo

g

5.1 5.2

6.8

7.8

7.7

8.3

8.1

8.6 8.8

8.1

4

5

6

7

8

9

10

1Q

10

2Q

10

3Q

10

4Q

10

1Q

11

2Q

11

3Q

11

4Q

11

1Q

12

2Q

12

Backlo

g -

$/S

ubsea T

ree (

$m

)

0

10

20

30

40

50

60

70

80

90

100

1Q

05

2Q

05

3Q

05

4Q

05

1Q

06

2Q

06

3Q

06

4Q

06

1Q

07

2Q

07

3Q

07

4Q

07

1Q

08

2Q

08

3Q

08

4Q

08

1Q

09

2Q

09

3Q

09

4Q

09

1Q

10

2Q

10

3Q

10

4Q

10

1Q

11

2Q

11

3Q

11

4Q

11

1Q

12

2Q

12

Subsea T

rees

Ord

ere

d

-

20

40

60

80

100

120

140

160

180

200

1.00

1.10

1.20

1.30

1.40

1.50

1.60

1.70

1.80

1Q

06

2Q

06

3Q

06

4Q

06

1Q

07

2Q

07

3Q

07

4Q

07

1Q

08

2Q

08

3Q

08

4Q

08

1Q

09

2Q

09

3Q

09

4Q

09

1Q

10

2Q

10

3Q

10

4Q

10

1Q

11

2Q

11

3Q

11

4Q

11

1Q

12

2Q

12

Rollin

g N

TM

Subsea T

ree D

eliv

erie

s

Asset Turn

s


FTI Backlog FTI Backlog Calorie Count - $/Subsea Tree ($m)

FTI Subsea Tree Orders FTI Asset Turns vs. Rolling NTM Tree Deliveries


Source: Company Reports, Infield, Guggenheim Securities, LLC Source: Company Reports, Guggenheim Securities, LLC

Source: Company Reports, Infield, Guggenheim Securities, LLC



Africa, 73

Asia, 48

Australasia, 29

Europe, 78

Latin America,

205

Middle East & Caspian

Sea, 0 North America, 70

FTI Backlog Breakdown – 503 Subsea Trees Currently Ordered but Undelivered

Other, 89

Petrobras, 199

Shell, 63

Total, 56

BP, 21

Statoil, 20

ConocoPhillips, 17

ExxonMobil, 16

Anadarko, 11 Chevron,

11

Woodside, 11

EnQuest, 10

Current FTI Backlog by Operator Current FTI Backlog by Region




Key Statistics: Cameron

140

190

240

290

340

390

440

1Q

05

2Q

05

3Q

05

4Q

05

1Q

06

2Q

06

3Q

06

4Q

06

1Q

07

2Q

07

3Q

07

4Q

07

1Q

08

2Q

08

3Q

08

4Q

08

1Q

09

2Q

09

3Q

09

4Q

09

1Q

10

2Q

10

3Q

10

4Q

10

1Q

11

2Q

11

3Q

11

4Q

11

1Q

12

2Q

12

Subsea T

rees

in B

acklo

g

3.8 4.0

4.8

5.6

6.8

6.7

7.9

7.8

7.6 7.7

6.5 6.8

6.6

6.3

6.2

5.5

5.3

5.0 5

.4

4.8

5.3

6.0

0

1

2

3

4

5

6

7

8

9

1Q

07

2Q

07

3Q

07

4Q

07

1Q

08

2Q

08

3Q

08

4Q

08

1Q

09

2Q

09

3Q

09

4Q

09

1Q

10

2Q

10

3Q

10

4Q

10

1Q

11

2Q

11

3Q

11

4Q

11

1Q

12

2Q

12

Backlo

g -

$/S

ubsea T

ree (

$m

)

0

20

40

60

80

100

120

1Q

05

2Q

05

3Q

05

4Q

05

1Q

06

2Q

06

3Q

06

4Q

06

1Q

07

2Q

07

3Q

07

4Q

07

1Q

08

2Q

08

3Q

08

4Q

08

1Q

09

2Q

09

3Q

09

4Q

09

1Q

10

2Q

10

3Q

10

4Q

10

1Q

11

2Q

11

3Q

11

4Q

11

1Q

12

2Q

12

Subsea T

rees

Ord

ere

d

0

20

40

60

80

100

120

140

160

180

200

0.7

0.8

0.9

1.0

1.1

1.2

1Q

06

2Q

06

3Q

06

4Q

06

1Q

07

2Q

07

3Q

07

4Q

07

1Q

08

2Q

08

3Q

08

4Q

08

1Q

09

2Q

09

3Q

09

4Q

09

1Q

10

2Q

10

3Q

10

4Q

10

1Q

11

2Q

11

3Q

11

4Q

11

1Q

12

2Q

12

Rollin

g N

TM

Subsea T

ree D

eliv

erie

s

Asset Turn

s

Asset Turns Leading 4Q Deliveries

CAM Backlog CAM Backlog Calorie Count - $/Subsea Tree ($m)

CAM Subsea Tree Orders CAM Asset Turns vs. Rolling NTM Tree Deliveries


Source: Company Reports, Infield, Guggenheim Securities, LLC Source: Company Reports, Guggenheim Securities, LLC




Africa, 60

Asia, 27

Australasia, 11

Europe, 13

Latin America,

157

Middle East &

Caspian Sea, 11

North America,

28

CAM Backlog Breakdown – 307 Subsea Trees Currently Ordered but Undelivered

Other, 39

Petrobras, 147 Total,

27

Husky, 21

BHP Billiton,

15

BG Group EGPC

Petronas, 12

BP, 12

Chevron, 12

Noble, 12 PDVSA,

10

CNOOC, 6

Current CAM Backlog by Operator Current CAM Backlog by Region




Key Statistics: Aker Solutions

100

110

120

130

140

150

160

170

180

190

1Q

05

2Q

05

3Q

05

4Q

05

1Q

06

2Q

06

3Q

06

4Q

06

1Q

07

2Q

07

3Q

07

4Q

07

1Q

08

2Q

08

3Q

08

4Q

08

1Q

09

2Q

09

3Q

09

4Q

09

1Q

10

2Q

10

3Q

10

4Q

10

1Q

11

2Q

11

3Q

11

4Q

11

1Q

12

2Q

12

Subsea T

rees

in B

acklo

g

10.3

9.9

10.8

11.2

11.5

14.6

16.1

15.3

13.9

12.7

4

6

8

10

12

14

16

18

1Q

10

2Q

10

3Q

10

4Q

10

1Q

11

2Q

11

3Q

11

4Q

11

1Q

12

2Q

12

Backlo

g -

$/S

ubsea T

ree (

$m

)

0

5

10

15

20

25

30

35

40

45

1Q

05

2Q

05

3Q

05

4Q

05

1Q

06

2Q

06

3Q

06

4Q

06

1Q

07

2Q

07

3Q

07

4Q

07

1Q

08

2Q

08

3Q

08

4Q

08

1Q

09

2Q

09

3Q

09

4Q

09

1Q

10

2Q

10

3Q

10

4Q

10

1Q

11

2Q

11

3Q

11

4Q

11

1Q

12

2Q

12

Subsea T

rees

Ord

ere

d

25

30

35

40

0.30

0.35

0.40

0.45

0.50

0.55

0.60

0.65

0.70

0.75

0.80

1Q10 2Q10 3Q10 4Q10 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12

Rollin

g N

TM

Subsea T

ree D

eliv

erie

s

Asset Turn

s


AKSO Backlog AKSO Backlog Calorie Count - $/Subsea Tree ($m)

AKSO Subsea Tree Orders AKSO Asset Turns vs. Rolling NTM Tree Deliveries



Note: Assumed 5.8 NOK /USD exchange rate





Africa, 10

Asia, 19Australa

sia, 0

Europe, 66

Latin America,

43

Middle East &

Caspian Sea, 0

North America, 2

AKSO Backlog Breakdown – 140 Subsea Trees Currently Ordered but Undelivered

Other, -

Petrobras, 43

Statoil, 29 Eni, 24

Murphy, 18

Marathon, 9

Total, 7

Lundin, 4 Chinook Energy,

3

CNOOC, 3

Current AKSO Backlog by Operator Current AKSO Backlog by Region




Earnings Valuations & Consensus Variances

Price Gugg EPS PE Consensus EPS EPS Variance

Company Ticker Rating 9/19 Target Upside P/NAV* 3Q12E 11 12E 13E 11 12E 13E 3Q12E 12E 13E 3Q12E 12E 13E

S&P 500 SPX 1,461 14.2 12.7 103.11 115.12

Exploration & Production

Apache APA Buy 89.21 115 29% 71% 2.33 12.00 9.90 10.36 7.4 9.0 8.6 2.23 9.88 10.58 5% 0% -2%

Anadarko APC Buy 72.55 100 38% 59% 0.82 3.37 3.07 4.49 21.5 23.6 16.2 0.73 3.43 4.34 12% -10% 4%

Devon DVN Buy 60.96 83 36% 63% 0.81 6.14 3.36 5.38 9.9 18.1 11.3 0.72 3.31 4.63 12% 2% 16%

EOG EOG Neutral 113.57 104 -8% 102% 1.06 3.77 4.70 6.54 30.1 24.2 17.4 1.00 4.56 5.29 6% 3% 24%

Noble NBL Buy 93.38 118 26% 65% 1.07 5.29 4.98 7.73 17.7 18.8 12.1 1.08 4.91 6.48 -1% 1% 19%

Pioneer PXD Neutral 107.14 94 -12% 116% 0.94 4.04 3.95 5.85 26.5 27.1 18.3 0.94 4.11 5.60 0% -4% 5%

Mean 79% 18.9 20.1 14.0

Large Cap Services

Baker Hughes BHI Neutral 48.11 48 0% NA 0.80 4.20 3.53 3.25 11.5 13.6 14.8 0.88 3.71 4.29 -9% -5% -24%

Halliburton HAL Neutral 36.41 35 -4% NA 0.74 3.35 3.20 2.80 10.9 11.4 13.0 0.70 3.16 3.49 5% 1% -20%

Schlumberger SLB Buy 74.71 80 7% NA 1.08 3.63 4.21 4.65 20.6 17.7 16.1 1.09 4.29 5.11 -1% -2% -9%

Weatherford WFT Neutral 13.20 13 -2% NA 0.26 0.73 1.05 1.15 18.1 12.6 11.5 0.28 1.07 1.47 -6% -2% -22%. 11.91 11.99 11.85 12.24 14.35

Mean 15.2 13.8 13.8

Equipment / Manufacturing

Aker Solutions AKSO Buy kr 108.60 kr 135 24% NA kr 1.96 kr 3.74 kr 7.84 kr 10.00 29.0 13.9 10.9 kr 1.92 kr 7.94 kr 10.40 2% -1% -4%

Cameron CAM Buy 57.65 67 16% NA 0.86 2.09 3.27 4.25 27.6 17.6 13.6 0.88 3.23 4.35 -2% 1% -2%

Dril-Quip DRQ Neutral 72.55 68 -6% NA 0.74 2.36 2.95 3.70 30.7 24.6 19.6 0.74 2.96 3.81 0% 0% -3%

FMC Tech FTI Buy 48.41 64 32% NA 0.56 1.65 2.00 2.70 29.3 24.2 17.9 0.57 2.09 2.61 -2% -4% 3%

Nat Oil Varco NOV Buy 82.03 96 17% NA 1.39 4.77 5.70 6.35 17.2 14.4 12.9 1.51 5.97 6.84 -8% -4% -7%

Oceaneering OII Buy 55.85 68 22% NA 0.79 2.16 2.64 3.25 25.9 21.2 17.2 0.78 2.65 3.22 1% 0% 1%

Tenaris TS Buy 42.73 50 17% NA 0.75 2.26 3.20 4.05 18.9 13.4 10.6 0.78 3.06 3.46 -4% 5% 17%98% 15.29 19.76 24.30 19.94 24.29

Mean 25.5 18.5 14.7

Offshore Drilling

Atwood Oceanics* ATW Neutral 46.68 44 -6% 111% 1.26 4.16 3.95 5.05 11.2 11.8 9.2 1.20 3.90 5.08 5% 1% -1%

Diamond DO Neutral 67.37 77 14% 105% 0.85 6.92 4.11 5.24 9.7 16.4 12.9 0.99 4.46 5.33 -14% -8% -2%

Ensco plc ESV Buy 58.10 68 17% 98% 1.30 3.15 5.20 7.30 18.4 11.2 8.0 1.30 5.27 7.06 0% -1% 3%

Noble Corp NE Buy 37.94 48 27% 97% 0.61 1.31 2.63 4.45 29.0 14.4 8.5 0.55 2.52 4.54 11% 4% -2%

Pacific Drilling PACD Buy 10.28 11 7% 86% (0.01) (0.01) 0.11 0.50 -- 93.5 20.6 0.00 0.20 0.46 -391% -44% 8%

Rowan RDC Neutral 35.97 34 -5% 100% 0.51 1.21 2.13 3.60 29.7 16.9 10.0 0.52 2.10 3.53 -2% 1% 2%

Seadrill SDRL Buy 39.62 49 24% 198% 0.70 2.54 2.87 3.33 15.6 13.8 11.9 0.71 3.09 3.51 -2% -7% -5%

Transocean RIG Neutral 45.27 50 10% 89% 0.80 1.51 2.77 4.29 30.0 16.3 10.6 0.77 2.99 4.58 4% -7% -6%

Mean 111% 20.5 24.3 11.4

Land Drilling

Helm & Payne* HP Neutral 49.09 49 0% NA 1.24 3.96 5.03 3.85 12.4 9.8 12.8 1.24 5.05 4.69 0% 0% -18%

Nabors NBR Neutral 15.65 15 -4% NA 0.38 1.50 1.78 1.15 10.4 8.8 13.6 0.40 1.85 1.81 -6% -4% -36%

Patterson UTI PTEN Neutral 17.06 16 -6% NA 0.37 2.14 1.75 0.65 8.0 9.7 26.2 0.40 1.85 1.36 -7% -5% -52%

Mean 10.3 9.4 17.5

*Quarterly EPS figures for ATW and HP reflect calendar year reporting basis. NAV figures for Offshore Drilling companies are Break-Up NAVs.

Source: FactSet, Company Reports, Guggenheim Securities, LLC



EBITDA & Cash Flow Valuation

Price Mkt Net Dt 2012E FCF Gugg EBITDA EV / EBITDA Gugg CFPS P / CFPS

Company 9/19 Cap Cap FCFPS Yield 11 12E 13E 11 12E 13E 11 12E 13E 11 12E 13E

S&P 500 1,461 8.5 7.9 18.3 15.5

Exploration & Production

Apache 89.21 34,901 23% 0.21 0.2% 12,551 13,396 14,507 3.6 3.3 3.1 24.97 27.53 32.50 3.6 3.2 2.7

Anadarko 72.55 36,252 35% 2.51 3.5% 7,628 7,458 9,531 6.3 6.5 5.1 5.01 15.97 16.60 14.5 4.5 4.4

Devon 60.96 24,658 15% (2.48) -4.1% 6,138 5,452 6,856 4.8 5.3 4.3 14.94 13.08 15.38 4.1 4.7 4.0

EOG 113.57 30,666 26% (8.48) -7.5% 4,619 5,668 6,513 7.7 6.2 5.4 17.14 19.30 22.13 6.6 5.9 5.1

Noble 93.38 16,808 25% (5.95) -6.4% 2,326 2,835 3,568 8.7 7.1 5.7 12.15 13.50 16.93 7.7 6.9 5.5

Pioneer 107.14 13,183 27% (9.59) -9.0% 1,614 1,670 2,385 10.0 9.7 6.8 12.96 15.23 17.14 8.3 7.0 6.3

Mean -3.9% 6.8 6.4 5.0 7.5 5.4 4.7

Large Cap Services

Baker Hughes 48.11 21,147 18% (3.19) -6.6% 4,306 4,104 4,245 5.8 6.1 5.9 7.22 7.10 7.44 6.7 6.8 6.5

Halliburton 36.41 33,779 11% (0.75) -2.1% 6,214 6,398 6,042 5.8 5.6 5.9 4.83 5.00 4.97 7.5 7.3 7.3

Schlumberger 74.71 99,142 14% (0.09) -0.1% 10,098 11,211 12,107 10.4 9.4 8.7 6.04 6.77 7.22 12.4 11.0 10.3

Weatherford 13.20 10,027 44% (1.29) -9.8% 2,621 3,089 3,393 7.0 5.9 5.4 2.22 2.67 2.93 5.9 4.9 4.5

Mean -4.6% 7.2 6.7 6.5 8.1 7.5 7.2

Equipment / Manufacturing

Aker Solutions kr 108.60 kr 29,756 37% (4.20) -3.9% kr 2,688 kr 4,633 kr 5,713 13.6 7.9 6.4 kr 6.99 kr 12.16 kr 15.14 15.5 8.9 7.2

Cameron 57.65 14,198 11% (0.99) -1.7% 1,139 1,371 1,690 13.2 10.9 8.9 3.53 4.26 5.35 16.3 13.5 10.8

Dril-Quip 72.55 2,932 -25% (0.07) -0.1% 157 191 234 17.1 14.0 11.5 3.01 3.59 4.35 24.1 20.2 16.7

FMC Tech 48.41 11,715 33% (1.07) -2.2% 688 904 1,140 18.4 14.0 11.1 2.00 2.50 3.34 24.2 19.3 14.5

Nat Oil Varco 82.03 34,979 -19% 1.36 1.7% 3,533 4,200 4,698 9.1 7.6 6.8 6.08 7.14 7.93 13.5 11.5 10.3

Oceaneering 55.85 6,026 2% 0.98 1.8% 468 599 723 13.0 10.1 8.4 3.40 4.20 5.02 16.4 13.3 11.1

Tenaris 42.73 25,222 4% 1.29 3.0% 2,452 3,053 3,718 10.5 8.4 6.9 3.25 3.93 4.89 13.1 10.9 8.78,436 10,317 12,204 21 26 31

Mean -0.2% 13.5 10.4 8.6 17.6 14.0 11.3

Offshore Drilling

Atwood Oceanics 46.68 3,051 23% (8.19) -17.5% 372 376 536 9.7 9.6 6.8 4.82 5.03 6.92 9.7 9.3 6.7

Diamond 67.37 9,366 2% 1.70 2.5% 1,654 1,198 1,495 5.7 7.9 6.4 9.79 6.99 8.40 6.9 9.6 8.0

Ensco plc 58.10 13,479 29% 0.79 1.4% 1,241 2,043 2,716 14.6 8.9 6.7 5.33 7.72 10.10 10.9 7.5 5.8

Noble Corp 37.94 9,584 35% (1.58) -4.2% 1,128 1,722 2,512 12.2 8.0 5.5 3.90 5.68 8.09 9.7 6.7 4.7

Pacific Drilling 10.28 2,159 45% (1.01) -9.9% (19) 249 377 -- 15.1 10.0 0.04 0.71 1.29 -- 14.5 8.0

Rowan 35.97 4,467 14% (0.33) -0.9% 368 553 842 14.4 9.6 6.3 2.76 4.11 5.78 13.0 8.8 6.2

Seadrill 39.62 18,592 56% 0.66 1.7% 2,323 2,495 2,915 12.2 11.4 9.7 3.70 4.10 4.78 10.7 9.7 8.3

Transocean 45.27 16,270 31% 0.46 1.0% 2,876 3,445 3,748 8.7 7.3 6.7 6.00 6.44 7.39 7.5 7.0 6.1

Mean -3.2% 11.1 9.7 7.3 9.8 9.1 6.7

Land Drilling

Helm & Payne 49.09 5,188 -14% (0.46) -0.9% 1,008 1,253 1,081 4.6 3.7 4.3 8.70 10.17 9.00 5.6 4.8 5.5

Nabors 15.65 4,545 40% (0.54) -3.4% 1,873 2,071 1,920 4.7 4.3 4.6 4.30 5.98 5.43 3.6 2.6 2.9

Patterson UTI 17.06 2,589 16% (0.71) -4.1% 957 964 750 3.3 3.2 4.2 4.95 5.18 4.50 3.4 3.3 3.8

Mean -2.8% 4.2 3.7 4.4 4.2 3.6 4.0




OFS EPS Comp


Ticker Company Category 2012E 2013E 1Q12 2Q12 3Q12E 4Q12E 1Q13E 2Q13E 3Q13E 4Q13E

Oil Services

SLB Schlumberger EPS 4.21 4.65 0.98 1.05 1.08 1.11 -- -- -- --

Consensus EPS 4.29 5.11 1.09 1.19 1.13 1.24 1.36 1.50



HAL Halliburton EPS 3.20 2.80 0.89 0.80 0.74 0.76 -- -- -- --

Consensus EPS 3.16 3.49 0.70 0.76 0.75 0.85 0.94 1.05



BHI Baker Hughes EPS 3.53 3.25 0.86 1.00 0.80 0.86 -- -- -- --

Consensus EPS 3.71 4.29 0.88 0.97 0.99 1.02 1.13 1.26



WFT Weatherford EPS 1.05 1.15 0.25 0.23 0.26 0.31 -- -- -- --

Consensus EPS 1.07 1.47 0.28 0.33 0.32 0.34 0.42 0.47



Equipment

AKSO-NOAKSO Aker Solutions EPS 7.84 10.00 1.84 1.89 1.96 2.15 2.24 2.40 2.57 2.79

Consensus EPS 7.94 10.40 1.92 2.26 2.23 2.53 2.55 2.85



CAM Cameron International EPS 3.27 4.25 0.57 0.74 0.86 1.09 1.01 1.01 1.08 1.15

Consensus EPS 3.23 4.35 0.88 1.07 0.93 1.05 1.12 1.19



DRQ Dril-Quip EPS 2.95 3.70 0.71 0.74 0.74 0.76 0.79 0.89 0.97 1.05

Consensus EPS 2.96 3.81 0.74 0.76 0.86 0.94 1.04 1.12



FTI FMC Technologies EPS 2.00 2.70 0.41 0.43 0.56 0.60 0.63 0.65 0.67 0.74

Previous EPS 2.00 2.65 0.56 0.60 0.63 0.64 0.66 0.72

Consensus EPS 2.09 2.61 0.57 0.64 0.56 0.61 0.67 0.73



NOV National Oilwell Varco EPS 5.70 6.35 1.42 1.46 1.39 1.43 1.45 1.53 1.63 1.74

Consensus EPS 5.97 6.84 1.51 1.57 1.63 1.67 1.77 1.86



OII Oceaneering Intl. EPS 2.64 3.25 0.47 0.67 0.79 0.70 0.75 0.81 0.85 0.83

Consensus EPS 2.65 3.22 0.78 0.73 0.69 0.83 0.89 0.83



TS Tenaris EPS 3.20 4.05 0.75 0.78 0.75 0.91 -- -- -- --

Consensus EPS 3.06 3.46 0.78 0.86 0.90 0.95 1.00 1.08





OFS EPS Comp


Ticker Company Category 2012E 2013E 1Q12 2Q12 3Q12E 4Q12E 1Q13E 2Q13E 3Q13E 4Q13E

Offshore Drillers

ATW Atwood Oceanics EPS 3.95 5.05 1.00 0.90 0.79 1.26 1.16 1.21 1.35 1.33

Consensus EPS 3.90 5.08 1.20 1.09 1.28 1.36 1.44

Consensus EPS-High 3.98 5.84 1.29 1.20 1.35 1.43 1.64

Consensus EPS-Low 3.70 4.60 1.04 0.96 1.21 1.27 1.35

DO Diamond Offshore EPS 4.11 5.24 1.21 1.09 0.85 0.96 1.11 1.24 1.38 1.51

Consensus EPS 4.46 5.33 0.99 1.15 1.21 1.24 1.43 1.55



ESV Ensco EPS 5.20 7.30 1.17 1.35 1.30 1.38 1.55 1.67 1.90 2.18

Consensus EPS 5.27 7.06 1.30 1.43 1.60 1.70 1.76 1.94



NE Noble Drilling EPS 2.63 4.45 0.47 0.59 0.61 0.96 0.84 1.05 1.16 1.40

Consensus EPS 2.52 4.54 0.55 0.91 0.93 1.13 1.20 1.28



PACD Pacific Drilling EPS 0.11 0.50 0.01 0.01 (0.01) 0.10 0.09 0.08 0.12 0.21

Consensus EPS 0.20 0.46 0.00 0.10 0.09 0.08 0.09 0.16


Consensus EPS-Low (0.02) 0.09 (0.08) 0.03 0.04 0.04 0.05 0.08

RDC Rowan EPS 2.13 3.60 0.46 0.51 0.51 0.65 0.74 0.85 1.01 1.00

Consensus EPS 2.10 3.53 0.52 0.63 0.82 0.84 0.94 0.89



RIG Transocean EPS 2.77 4.29 0.53 0.73 0.80 0.72 0.76 1.01 1.22 1.30

Consensus EPS 2.99 4.58 0.77 0.87 1.01 1.17 1.23 1.11



SDRL Seadrill EPS 2.87 3.33 0.85 0.56 0.70 0.77 0.79 0.80 0.83 0.91

Consensus EPS 3.09 3.51 0.71 0.80 0.79 0.82 0.87 0.98



Land Drillers

HP Helmrich & Payne EPS 5.03 3.85 1.29 1.13 1.37 1.24 -- -- -- --

Consensus EPS 5.05 4.69 1.24 1.21 1.17 1.20 1.23

Consensus EPS-High 5.15 5.25 1.31 1.34 1.30 1.31 1.36

Consensus EPS-Low 4.85 3.85 1.17 1.12 1.09 1.07 1.07

NBR Nabors EPS 1.78 1.15 0.65 0.38 0.38 0.37 -- -- -- --

Consensus EPS 1.85 1.81 0.40 0.43 0.51 0.37 0.46 0.52



PTEN Patterson-UTI Energy EPS 1.75 0.65 0.61 0.49 0.37 0.27 -- -- -- --

Consensus EPS 1.85 1.36 0.40 0.33 0.35 0.33 0.37 0.41





P/E Methodology P/E Range

Oilfield Equipment Valuation Methodology: P/E Range Calculations

Source: FactSet, Company Reports, Guggenheim Securities, LLC Source: FactSet, Guggenheim Securities, LLC

kr135

$67 $68

$64

$96

$68

$109

$58

$73

$48

$82

$56

$-

$20

$40

$60

$80

$100

$120

$140

$160

$180

$200

AKSO-

OSL

CAM DRQ FTI NOV OII

$ per

share Implied '12E P/E to '13E P/E Range

Price Target

Last Price

FTI14%

CAM16%

DRQ27%

NOV22%

OII23%

AKSO10%

10.0x

12.0x

14.0x

16.0x

18.0x

20.0x

22.0x

24.0x

10% 12% 14% 16% 18%

Price T

arg

et Im

plie

d 2

013E P/E

Multip

le

Revenue Growth CAGR 2013E-2015E

FTI CAM DRQ NOV OII AKSO

Bubble size reflects 2Q12 EBITDA Margins



OFS Valuations & Risks


Ticker Valuation Risks

BHI BHI currently trades at approximately 14x our 2012 P/E and 6x our 2012 EV/EBITDA estimates. Our 12-month price

target of $48 is based on 14.5x our 2012 P/E and 6.0x our 2012 EV/EBITDA estimates.

BHI is in the process of eliminating redundant costs and streamlining its international operations – execution of this strategy

poses a risk. A slow dow n in NAM spending grow th is also a key risk for BHI.

HAL HAL currently trades at approximately 12x our 2012 P/E and 6x our 2012 EV/EBITDA estimates. Our 12-month price

target of $35 is based on 13x our 2012 P/E and 6.0x our 2012 EV/EBITDA estimates.

HAL's grow th has largely been driven by NAM activity and pricing improvement. Should NAM spending decelerate at a faster

rate than w e now expect, HAL shares could underperform our NEUTRAL rating.

SLB SLB currently trades at approximately 18x our 2012 P/E and 9x our 2012 EV/EBITDA estimates. Our 12-month price

target of $80 is based on 17x our 2012 P/E and 10x our 2012 EV/EBITDA estimates.

The fact that SLB is entering a period of leadership transition could w eigh on the stock. Although w e expect deepw ater to be

a safe haven, any delays or project cancellations could curb SLB's grow th prospects.

WFT WFT currently trades at approximately 13x our 2012 P/E and 6x our 2012 EV/EBITDA estimates. Our 12-month

price target of $13 is based on 13x our 2012 P/E and 6.5x our 2012 EV/EBITDA estimates.

WFT has considerable f inancial leverage, w hich can act as an accelerant to share price declines w hen cash f low grow th

falls short of expectations. Should WFT’s contract execution fail to improve, the stock could underperform our NEUTRAL

rating.

AKSO We arrive at our price target of kr135/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 20.3x multiple on our 2012 EPS estimate and a 18.2x multiple on our 2013 EPS estimate.

Our DCF valuation implies a value of $180/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.

CAM We arrive at our price target of $67/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 23.8x multiple on our 2012 EPS estimate and a 16.3x multiple on our 2013 EPS estimate. Our DCF

valuation implies a value of $67/sh, given strong grow th over the explicit forecast, reinvestment of capital, and a

normalization of returns w ithout economic rents.

Should order book grow th begin to retrench, it w ould cast doubt on our 2012/2013 estimates and likely lead to negative

revisions, a low er price target, and underperformance relative to our BUY rating. The volatile North American natural gas

market historically contributed 60% of Cameron’s domestic sales, comprised of its surface w ellhead, distributed valves, and

compression businesses. If the market becomes oversupplied, both conventional and unconventional natural gas operators

may cut their budgets, w hich w ould negatively impact Cameron’s operating performance.

DRQ We arrive at our price target of $68/sh by calibrating against our P/E valuation framew ork and our discounted cash





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.

FTI We arrive at our price target of $64/sh by calibrating against our P/E valuation framew ork and our discounted cash





As a company dependent on deepw ater development, FTI’s revenue and earnings could be materially impacted by a potential

slow dow n in offshore development—be it recession or regulatory driven—w hich w ould push subsea order f low to the right

and curtail FTI’s earnings grow th trajectory. Additionally, should the North American onshore market deteriorate more than w e

are currently modeling, the stock could underperform our BUY rating.

NOV We arrive at our price target of $96/sh by calibrating against our P/E valuation framew ork and our discounted cash





Although visibility from the offshore rig market replacement cycle gives us confidence in Rig Tech’s earnings trajectory over

our forecast period (2013), w e believe uncertain macro conditions could potentially push order f low out, causing investors to

question NOV’s grow th prospects--a potential source of near-term dow nside risk.

OII We arrive at our price target of $68/sh by calibrating against our P/E valuation framew ork and our discounted cash


range betw een a 23.4x multiple on our 2012 EPS estimate and an 22.5x multiple on our 2013 EPS estimate. Our DCF



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.

TS TS currently trades at approximately 13x our 2012 P/E and 8x our 2012 EV/EBITDA estimates. Our 12-month price

target of $50 is based on 13x our 2012 P/E and 7x our 2012 EV/EBITDA estimates.

Should global steel costs begin to rise, TS's margins w ould not expand as expected, creating a headw ind for the stock.

Additionally, should there be delays in large offshore projects, TS's pricing may not be as strong.



OFS Valuations & Risks


Ticker Valuation Risks

ATW We arrive at a price target of $44/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 (6 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 $77/sh. Our methodology w eighs our NAV - Break-Up, or liquidation value of the



asset classes.

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 $68/sh. Our methodology w eighs our NAV - Break-Up, or liquidation value of the



asset classes.

Risks include construction (6 new builds) and GOM exposure. Operational execution risk leaves the chance for 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.

NE We arrive at a price target of $48/sh. Our methodology w eighs our NAV - Break-Up, or liquidation value of the



asset classes.

Risks include construction (11 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.

PACD We arrive at a price target of $11/sh. Our methodology w eighs our NAV - Break-Up, or liquidation value of the



asset classes.

Risks include construction (3 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 $34/sh. Our methodology w eighs our NAV - Break-Up, or liquidation value of the



asset classes.

Risks include construction (3 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.

RIG We arrive at a price target of $50/sh. Our methodology w eighs our NAV - Break-Up, or liquidation value of the



asset classes.

Upside risks include a GOM or RoF demand surge, and 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 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 $49/sh. Our methodology w eighs our NAV - Break-Up, or liquidation value of the



asset classes.

Risks include construction (9 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 4x our 2012 EV/EBITDA and 5x our 2012 P/CFPS estimates. Our 12-month

price target of $49 is based on 4.5x our 2012 EV/EBITDA and 5.5x our P/CFPS estimates.

Our estimates may prove too low should E&P liquidity improve. Conversely, w ith the upstream funding gap at its w idest point

since the f inancial crisis, the rig count could contract more than our 12% forecast.

NBR NBR currently trades at approximately 4x our 2012 EV/EBITDA and 3x our 2012 P/CFPS estimates. Our 12-month


Dow nside risk has grow n in the U.S. Land segment as a result of E&P liquidity constraints, and the frac business could have

cost challenges. Should International margins recover sooner than expected, our estimates may prove too low .

PTEN PTEN currently trades at approximately 3x our 2012 EV/EBITDA and 3x our 2012 P/CFPS estimates. Our 12-month


PTEN has more relative exposure to 1-2 rig operators. Consequently, its rig count appears more vulnerable in a correction.

That said, the stock could rally should natural gas prices recover sooner than expected.



E&P Valuations & Risks


Ticker Valuation Risks1APA APA currently trades at approximately 3.3x our 2012 EV/EBITDAX and 3.2x our 2012 P/CFPS estimates. Our 12-

month price target of $115 is based on 3.5x our 2012 EV/EBITDAX, 3.5x our P/CFPS and our NAV of $125.

Key risks for APA include exploration risk, w here dry holes or disappointing appraisal w ells w ould lead to underperformance

in these grow th areas. Similarly, burdensome regulation or increased costs in the GOM w ould negatively impact offshore

returns. Given its business model, Apache also depends on steady cash flow from reinvestment in mature assets. Any

production or cost issues w ould impact margins, and have a negative impact on the stock. Apache also has heightened

geopolitical risk in Argentina and Egypt.

APC APC currently trades at approximately 6.5x our 2012 EV/EBITDAX and 4.5x our 2012 P/CFPS estimates. Our 12-


Given its exploration focus, low er exploration success rates or disappointing appraisal drilling could cause the stock to

underperform. Although w e are comfortable w ith the levels of risk outlined by management, any additional liability from the

Tronox Adversary Proceeding, Macondo or burdensome regulatory requirements in the GOM could also be detrimental.

Geopolitical tensions in the company’s international operations that result in loss of reserves or production w ould also have a

negative impact on the stock.

DVN DVN currently trades at approximately 5.3x our 2012 EV/EBITDAX and 4.7x our 2012 P/CFPS estimates. Our 12-


Given its grow th prospects in Canadian bitumen production, DVN is especially susceptible to low er oil prices as w ell as

transport constraints of either blended production to the markets or the return of diluents to the producing areas. Oil

production in the Permian and other U.S. basins w ould also be negatively impacted by sustained low er oil prices. The

company could also be negatively impacted by any environmental legislation that w ould limit the utilization or increase the cost

of its horizontal drilling and horizontal fracturing operations.

EOG EOG currently trades at approximately 6.2x our 2012 EV/EBITDAX and 5.9x our 2012 P/CFPS estimates. Our 12-


Key risks for EOG are largely around project execution, as the portfolio transformation is w holly dependent on grow th in the

shales. Given the funding gap, EOG is also more exposed to grow th curtailment in a low commodity price w orld.

NBL NBL currently trades at approximately 7.1x our 2012 EV/EBITDAX and 6.9x our 2012 P/CFPS estimates. Our 12-


Key risks for NBL include exploration risk from dry holes or suboptimal appraisal drilling. Availability of and access to

infrastructure could also have an impact on realized prices, particularly in new er plays w here infrastructure is under

construction or being expanded. Also there is geopolitical risk, particularly in West Africa, Israel, or Cyprus.

PXD PXD currently trades at approximately 9.7x our 2012 EV/EBITDAX and 7.0x our 2012 P/CFPS estimates. Our 12-


As one of the oilier names in our universe, PXD earnings are closely tied to realized oil prices, and a sustained drop in price

levels or increase in the current Brent/WTI spread w ould adversely affect the company’s absolute and relative returns in the

space. The company has purchased Midland-Cushing basis sw aps for 2H12 to mitigate spread risk betw een those tw o

pricing points. The vertical integration strategy could also prove to be less effective and/or more expensive than third-party

services, w hich w ould increase unit costs of production. During a dow nturn, the company could also incur additional costs

for idling or dismantling company-ow ned drilling and frac crew s.



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2012-09-20 Market Power Shifting to Subsea Equipment Players - D. Gacicia

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Transcript of 2012-09-20 Market Power Shifting to Subsea Equipment Players - D. Gacicia