GoM Supply_Demand - D. Gacicia

People. Ideas. Success.
Guggenheim Securities, LLC
Oilfield Services, Offshore Contract Drillers & Capital Equipment
March 14, 2014
Potential for Tight GoM Floater Balance, but Overhang of LLS/WTI Linkage
Looms
Darren Gacicia
(212) 293-3054
darren.gacicia@guggenheimpartners.com
Michael Gunther
(212) 518-9782
michael.gunther@guggenheimpartners.com
GUGGENHEIM SECURITIES, LLC See pages 88 - 90 for analyst certification and important disclosures.

GoM Floater Outlook Favorable, Nervous About LLS in a Captive Market
Gulf of Mexico Floater Market Frictions in 2014, Tighter in 2015. We expect the Gulf of Mexico (GoM) floater market may see up to three rigs roll off contract to idle
time in 2014, with a recovery and need to net add rigs through 2015 (pg. 3). The resultant rig-on-rig competition through the year may create some dayrate sloppiness, but
it should prove short-lived and already discounted by depressed offshore drillers shares. Our regional analysis of wells and upstream operator demand (pgs. 4,16) of the
Gulf floater market supports our more constructive outlook for the industry and opinion that negative consensus sentiment has created an entry point for the offshore
drillers. We see 56 floaters working in the region at the end of 2014, up from 46 contracted in 1Q14. Given only 10-12% of expected development drilling demand for 2014
and 2015 remains non-FID and exploration activity assumptions run at roughly half of levels seen since 2005, our near-term forecast remains more biased to upside versus
downside revisions. Our main concern centers around a captive North American oil market, which may weigh on WTI/LLS prices versus Brent (global benchmarks). Higher
perceived commodity price risk, with our WTI forecast at $78 for 2015 vs. an $89 strip, may lead to further project delays.
De-Bottlenecking Midstream Infrastructure Links LLS with WTI vs. Brent Over Time. Over time, we believe the North American market is positioning itself to arbitrage
WTI/LLS/Brent spreads (pg. 9) through investment in midstream infrastructure to the Gulf Coast. Without relief from exports, projected light sweet production growth
threatens to bump up against the absorption capacity of North American refineries and widen the WTI/Brent Spread, which will put pressure on LLS pricing and potentially
challenge GoM project economics. (See Roger Diwan‘s report, The Unbearable Lightness of US Crudes: Oil Super-Cycle Delivers Super-Discount in 2014 & 2015,
1/28/14). Varying timelines leave most inland transport capacity to the Gulf Coast from Cushing (WTI hub), Permian, and Bakken (pg. 12) arriving after 2014, but the stage
is set for closer linkage between WTI/LLS vs. LLS/Brent. As a result, we see the potential for LLS to trade closer to parity with WTI, rather than its traditional relationship
with Brent (pg. 9). Given our sensitivity analysis of project economics with PFC/ IHS of GoM (pg. 5), a $10 move in oil assumptions may drive a 200-400bps delta in project
IRRs. Existing development-forward project economics at $70/bbl oil assumptions suggest most projects move forward, but 20-30% of projects may prove at risk under
lower oil forecasts. Prospects for oil exports may provide a relief valve, but we still see a limited probability for policy change at this point. (See more oil export coverage
from Whitney Stanco, our energy policy analyst.)
Development Demand May Require More Floaters. Our forecast calls for continued growth in development drilling (climbing to 41 in 2014/2015), supported by attractive
development-forward returns characteristics for projects we track, limited (10-12%) risk to demand expectations from non-sanctioned projects (4-5 rigs, pg. 20), and a
limited risk from daunting CAPEX requirements across projects (pg. 22). If rigs rolling off contract are not re-signed, we see a number of upstream operators short floaters
for development work, which suggests that rigs will roll to new contracts. In a market that assumes rigs will roll off contract, without significant tender market visibility, we
continue to see development drilling growth (pg. 15), especially if rig drilling efficiency remains at recent levels (pg. 63).
Potential Upside from Conservative Exploration Forecast. Our forecast has exploration floater demand falling to nine rigs by the end of 2015, after assuming contract
roll-offs and limited demand indications from tenders. In our view, we may prove conservative, given two- and five-year averages of 23 rigs and 15 rigs (pg. 24). Roughly
67% of non-FID and 33% of FID projects in the GoM suggest full cycle IRRs below 15% at $70bbl long-term realization assumptions. With an increased focus on returns
on capital, growth, and development of existing discoveries, we assume capital budget vetting, responsible for the current ―pause‖ by upstream players, may curtail near-
term exploration activity. That said, our very conservative outlook for exploration demand may prove too low if the need to replace reserves and meet longer-term new
source production goals (pg. 30) moves closer to the front of capital budgeting debates. For operators of ~65% of the floater fleet, we continue to see 30-40% of forecasted
new source production obtained from deepwater plays.
Offshore Drillers Continue to Screen Well vs. Other Oil Service Companies. Concerns about market balances and near-term dayrates continue to drive valuation
discounts (NAV, P/TBV, Earnings Multiples). Given sentiment near bottom, stocks circling tangible book value (pg. 38), and fundamentals beyond 2014 likely better than
consensus expectations, we see the offshore drillers screening well versus other oil service companies with higher multiples and lofty growth outlooks. If our view of a
widening WTI/Brent spread comes into focus, both consensus EPS forecasts and valuation multiples may be at risk for service, equipment, and land drilling names, with
washed-out offshore driller shares screening well. We continue to favor SDRL (BUY, $33.70), ATW (BUY, $46.02), and PACD (BUY, $9.89), based on relative fleet quality
and outlook for more significant distribution strategies.
Attrition Risk More Important than Total Floater Fleet Exposure. NE (BUY, $28.98), ESV (NEUTRAL, $48.86), and ATW have the most floater exposure to the GoM as
percentage of their total floater fleets (pg. 6). Given potential idle time for GoM floaters in 2014, DO (BUY, $44.39), NE, and RIG (BUY, $39.54) have the most contract
coverage risk (pg. 39), compounded by older fleet mix in the region. As a result, we would expect these companies with the most rollover risk to trade with the greatest
sensitivity to GoM news flow.
Guggenheim Securities, LLC | 212.293.3054 | guggenheimsecurities.com
Oilfield Services, Offshore Contract Drillers, & Capital Equipment PAGE 2

Total Supply/Demand Balance 2014E 2015E
Development Demand 41 41
Exploration & Appraisal Demand 15 9
Total Demand 56 50
End of Previous Period 45 56
Rigs Rolling Off Contract (13) (7)
Assumed in Contract Renew als 10 -
New Rig Contracts Starting 14 3
Additional Rig Needed to Enter/(Leave) the Market - (2)
Total Rigs Contracted 56 50
Net Rig Additions/(Attrition) 11 (6)
Unsanctioned Development Demand at Risk
2014E 2015E 2014E 2015E
Bull Case (All FID Comes) 5 6 1 1
Base Case 4 5 - -
Bear Case (No FID Comes) - - (4) (5)
Exploration & Appraisal Demand
2014E 2015E 2014E 2015E
Bull Case (All Rigs Renew ed & All Tenders Come) 24 20 9 11
Base Case 15 9 - -
Bear Case (No Rigs Renew ed & No Tenders Come) 15 9 - -
Well/Rig Ratios
2014E 2015E 2014E 2015E
Bull Case (1x w ell/rig for UDW/DW, 2x for MW) 89 83 33 33
Base Case (2x w ell/rig for UDW/DW, 3x for MW) 56 50 - -
Bear Case (3x w ell/rig for UDW/DW, 4x for MW) 44 37 (12) (13)
Demand Projection In Demand
Exploration Potential Increase/(Decrease)
Total Potential Increase/(Decrease)
Contracted Rig Grow th: 2013-2015
5
Unsanctioned Potential Increase/(Decrease)
GoM Floater S/D & Sensitivity Analysis More Favorable than Consensus
Source: IHS Inc, Infield Systems, Company Reports, Guggenheim Securities, LLC
Between 10-12% of demand remains
at risk from non-FID projects.
Our forecast for exploration demand
remains conservative versus recent
E&A rig counts above 20.
Idle rig time in 2014 may prove
transient, especially as our
exploration forecast remains
conservative and may offer upside.
New rigs entering the region are
newer and higher spec., putting the
pieces in place for rig replacement
scenarios in the GoM.

Implied Development Drilling Demands Exceed Current Contract Coverage
GoM Projected Implied
Development Rig Demand
GoM Development
Contract Coverage
Note: contract coverage is
expressed in rig years
Implied Development
Rig Surplus/(Deficit)
Current floater demand for development drilling, as implied by our well-by-
well forecast, is not covered by current contracts over 2014-2016,
producing a deficit. If our wells per rig assumptions are correct, the deficit
must be reconciled by re-contracting of rigs coming off contract, rig
tenders, or projects being delayed or cancelled.
Company
2014
Wells
2015
Wells
2016
Wells
2014
Implied
Rigs
2015
Implied
Rigs
2016
Implied
Rigs
Shell 20 18 24 8 8 10
BP 11 16 7 5 7 3
Anadarko 14 13 18 6 6 9
Chevron 11 8 5 6 4 2
BHP 2 1 2 1 0 1
Noble Energy 7 5 8 4 3 4
Stone Energy 2 3 - 1 1 -
Apache - - 1 - - 1
Cobalt - - - - - -
Eni - 1 - - 1 -
ExxonMobil 3 6 1 2 3 1
Hess 3 2 6 1 1 2
Murphy 3 3 3 1 1 1
Statoil - - - - - -
Marathon - 1 - - 1 -
Other 20 16 12 8 6 5
Total 96 93 87 41 41 39
Company
2014
Contract
Coverage
2015
Contract
Coverage
2016
Contract
Coverage
Shell 5.9 5.0 4.8
BP 6.4 6.0 5.3
Anadarko 4.1 4.6 4.0
Chevron 3.5 4.0 4.0
BHP 0.8 1.0 1.0
Noble Energy 1.6 1.0 1.0
Stone Energy 0.6 - -
Apache 1.0 - -
Cobalt 0.2 - -
Eni 1.0 0.3 -
ExxonMobil 1.9 1.8 1.0
Hess 0.9 - -
Murphy 1.0 1.0 0.9
Statoil 1.8 1.9 0.3
Marathon 1.1 1.0 1.0
Other 6.4 8.0 7.1
Total 38 36 30
Company
2014
Surplus/
(Deficit)
2015
Surplus/
(Deficit)
2016
Surplus/
(Deficit)
Shell (1.9) (2.5) (5.4)
BP 1.1 (1.2) 2.0
Anadarko (1.6) (1.2) (4.8)
Chevron (2.0) 0.3 1.7
BHP 0.1 0.7 0.2
Noble Energy (1.9) (1.5) (2.8)
Stone Energy (0.1) (1.0) -
Apache 1.0 - (1.0)
Cobalt 0.2 - -
Eni 1.0 (0.7) -
ExxonMobil 0.4 (1.0) 0.5
Hess (0.1) (0.7) (2.0)
Murphy (0.3) (0.3) (0.1)
Statoil 1.8 1.9 0.3
Marathon 1.1 - 1.0
Other (1.6) 2.0 2.3
Total (3) (5) (8)

Field
Year
on
Stream Status Water Depth Operator
Full
Cycle
IRR %
Dev-
Forw ard
IRR %
Full
Cycle
IRR %
Dev-
Forw ard
IRR %
Full
Cycle
IRR %
Dev-
Forw ard
IRR %
CAPEX
($MM)
Mad Dog 2012 FID Midw ater BP 37% 76% 38% 76% 39% 77% 5,302$
Caesar/Tonga 2011 FID Midw ater Anadarko 21% 70% 23% 73% 26% 78% 508$
Cardamom Deep 2012 FID Midw ater Shell 59% 69% 65% 76% 76% 88% 206$
Shenzi 2007 FID Midw ater BHP Billiton 42% 61% 42% 62% 43% 62% 1,239$
Thunder Horse 2006 FID Deepw ater BP 35% 61% 35% 61% 36% 62% 1,857$
Condor 2009 FID Midw ater Deep Gulf Energy 52% 60% 54% 61% 56% 64% 171$
Atlantis North 2010 FID Deepw ater BP 24% 54% 25% 56% 26% 58% 458$
Tahiti 2007 FID Midw ater Chevron 30% 51% 31% 52% 33% 53% 2,536$
Atlantis South 2005 FID Deepw ater BP 31% 50% 31% 50% 32% 51% 1,257$
Dalmatian 2012 FID Deepw ater Murphy 34% 45% 36% 49% 41% 56% 61$
Tubular Bells 2014 FID Midw ater Hess 14% 44% 15% 49% 18% 59% 344$
Pompano 1992 FID Midw ater Stone Energy 43% 43% 43% 43% 43% 43% 381$
Julia 2014 FID Deepw ater ExxonMobil 19% 42% 21% 47% 23% 58% 163$
Mars B 2013 FID Midw ater Shell 33% 38% 38% 45% 46% 56% 1,087$
Lucius 2012 FID Deepw ater Anadarko 20% 30% 24% 35% 30% 45% 1,315$
Heidelberg 2014 FID Deepw ater Anadarko 16% 30% 19% 35% 24% 45% 897$
Big Bend 2014 FID Deepw ater Noble Energy 22% 27% 25% 31% 30% 37% 228$
Jack-St. Malo 2013 FID Deepw ater Chevron 13% 26% 16% 30% 20% 39% 1,811$
Perdido 2009 FID Ultradeepw ater Shell 14% 24% 16% 27% 19% 31% 2,524$
Big Foot 2014 FID Deepw ater Chevron 8% 23% 10% 28% 13% 37% 1,444$
Hadrian South 2012 FID Deepw ater ExxonMobil 10% 20% 10% 20% 10% 20% 134$
Gunflint 2014 FID Deepw ater Noble Energy 8% 19% 10% 22% 14% 27% 150$
Stones 2014 FID Ultradeepw ater Shell 7% 15% 10% 20% 13% 27% 1,210$
Pyrenees 2013 FID Midw ater W&T Offshore 13% 13% 14% 14% 17% 17% 83$
Holstein Subsea Tiebacks 2014 Non-FID Midw ater Plains E&P 33% 57% 39% 64% 49% 78% 216$
Marlin Subsea Tiebacks 2014 Non-FID Midw ater Plains E&P 27% 54% 31% 60% 38% 71% 144$
Vito 2016 Non-FID Midw ater Shell 10% 47% 12% 54% 15% 67% 1,061$
Horn Mountain Subsea Tiebacks 2015 Non-FID Deepw ater Plains E&P 26% 47% 31% 54% 40% 66% 309$
Kaskida 2018 Non-FID Deepw ater BP 10% 45% 12% 52% 14% 66% 2,254$
Stampede 2016 Non-FID Midw ater Hess 10% 37% 11% 43% 14% 54% 1,608$
Hadrian North 2017 Non-FID Ultradeepw ater ExxonMobil 11% 36% 13% 43% 16% 55% 1,959$
Shenandoah 2016 Non-FID Deepw ater Anadarko 23% 35% 26% 41% 31% 52% 2,367$
Who Dat 2012 Non-FID Midw ater LLOG 21% 26% 23% 28% 28% 33% 1,525$
Logan 2018 Non-FID Ultradeepw ater Statoil 11% 25% 13% 29% 16% 38% 727$
Appomattox 2016 Non-FID Deepw ater Shell 10% 24% 13% 29% 17% 38% 2,915$
Dalmatian South 2014 Non-FID Deepw ater Murphy 15% 19% 17% 23% 23% 30% 154$
Vicksburg 2016 Non-FID Deepw ater Shell 8% 19% 9% 23% 12% 30% 392$
Moccasin 2018 Non-FID Deepw ater Chevron 3% 18% 6% 23% 10% 31% 1,289$
Buckskin 2018 Non-FID Deepw ater Chevron 6% 16% 8% 20% 12% 28% 1,275$
$70/bbl $80/bbl $100/bbl
Breakdown of Project Dynamics: Vetting Economics at $70/bbl LLS
Source: IHS Inc, Guggenheim Securities, LLC
A $10 move in project oil price
assumptions can move full cycle
IRRs between 200-250bps and
development forward IRRs 400bps.
The perceived risks may put
development projects on the cusp at
risk. We suspect that most oil
companies are using closer to
$70/bbl oil in their forecast.
High up-front CAPEX
costs may overhang
projects. Although
Mad Dog economics
were attractive, the
size of the near-term
investment led to a
delay to rethink
production
infrastructure
solutions.
A number of projects see Full-
Cycle returns below 15%,
which likely challenges
exploration decisions than
development decisions, which
have better incremental return
outlooks.

0%
10%
20%
30%
40%
50%
60%
70%
80% 29 2
3
5
1
2 2 7 10
1
0%
5%
10%
15%
20%
25%
30%
35%
40% 10
8
2
2
15 1 5 6
1 1
GoM Floater Fleet & Contract Exposure by Offshore Driller
Source: IHS Inc., Guggenheim Securities, LLC.
% of Company Floater Fleet in the GoM % of Company Jackup Fleet in the GoM
Jackup Contract Coverage in the GoMFloater Contract Coverage in the GoM
Manager 2014 2015 2016
Atwood 100% 100% 100%
Diamond Offshore 42% 21% 17%
Ensco 84% 38% 16%
Maersk Drilling 100% 100% -
Noble 73% 50% 33%
Pacific Drilling 100% 100% 100%
Seadrill 95% 100% 100%
Stena 100% 63% 50%
Transocean 78% 55% 40%
Vantage Drilling 100% 100% 100%
Manager 2014 2015 2016
Diamond Offshore - - -
Ensco 50% 3% -
Gryphon Energy - - -
Hercules Offshore 42% 1% -
Nabors - - -
Noble 100% 100% 25%
Perforadora Central - - -
Rowan 39% - -
Spartan Offshore Drilling 42% - -
Well Services Ltd - - -

Breakdown of Contracted Floaters May Suggest Fleet Renewal in Place
Current Contracted Floaters in the Gulf of Mexico New Contracts Starting 2014-2016
Some of the currently contracted rigs
rolling off contract in 2014 (shown in
light blue on the left) are older, lower
spec rigs. By contrast, floaters that
are starting new contracts in the
GoM during 2014-2016 are new and
high spec.
Rig Name Manager Operator
Water
Depth (ft) Gen
Year
In Svc
Variable
Deck Load
(Tons)
Derrick
Capacity
(lbs)
Free
Quarter
1 GSF Grand Banks Transocean Husky Oil Operations 1,500 3G 1984 5,622 1,300,000 1Q14
2 Ocean Saratoga Diamond Offshore LLOG 2,200 2G 1976 2,500 1,000,000 1Q14
3 Noble Driller Noble Marubeni 5,000 4G 1976 3,400 1,576,575 2Q14
4 Ocean Victory Diamond Offshore Stone Energy 5,500 4G 1972 6,294 1,500,000 1Q14
5 Ocean Onyx Diamond Offshore Apache 6,000 5G 1973 6,173 1,600,000 1Q15
6 Noble Jim Thompson Noble Shell 6,000 4G 1999 4,000 1,500,000 1Q15
7 Noble Amos Runner Noble LLOG 8,000 4G 1999 4,000 1,500,000 4Q15
8 Development Driller III Transocean BP 7,500 6G 2009 14,881 2,000,000 4Q16
9 GSF Development Driller II Transocean BP 7,500 6G 2005 7,716 2,000,000 1Q14
10 GSF Development Driller I Transocean BHP Billiton 7,500 6G 2005 7,716 2,000,000 3Q14
11 Stena Forth Stena Hess 7,500 Drillship 2009 22,046 2,000,000 1Q15
12 West Capricorn Seadrill BP 7,500 6G 2011 7,716 2,500,000 3Q17
13 Stena IceMAX Stena Shell 7,500 Drillship 2012 19,290 2,000,000 3Q17
14 Discoverer Enterprise Transocean BP 8,000 Drillship 1999 22,046 2,100,000 1Q15
15 Deepwater Nautilus Transocean Shell 8,000 5G 2000 9,700 2,000,000 3Q17
16 ENSCO 8500 Ensco Anadarko 8,500 6G 2008 8,000 2,000,000 3Q14
17 ENSCO 8501 Ensco Noble Energy 8,500 6G 2009 8,000 2,000,000 3Q14
18 ENSCO 8502 Ensco Stone Energy 8,500 6G 2010 8,000 2,000,000 1Q15
19 ENSCO 8503 Ensco Cobalt Intl 8,500 6G 2010 8,000 2,000,000 2Q14
22 Deepwater Pathfinder Transocean Eni 10,000 Drillship 1998 22,040 2,500,000 2Q15
23 Discoverer Spirit Transocean Anadarko 10,000 Drillship 2000 22,040 2,000,000 2Q14
24 GSF C.R. Luigs Transocean BHP Billiton 10,000 Drillship 2000 28,660 2,000,000 1Q14
25 Discoverer Deep Seas Transocean Murphy 10,000 Drillship 2001 22,040 2,000,000 4Q16
26 West Sirius Seadrill BP 10,000 6G 2008 7,716 2,500,000 3Q19
27 Maersk Developer Maersk Drilling Statoil 10,000 6G 2009 14,881 2,000,000 4Q15
28 Discoverer Inspiration Transocean Chevron 10,000 Drillship 2009 22,046 2,500,000 1Q20
29 ENSCO DS-3 Ensco BP 10,000 Drillship 2010 22,046 2,000,000 2Q16
30 Discoverer India Transocean Chevron 10,000 Drillship 2010 22,046 2,500,000 4Q20
31 Deepwater Champion Transocean ExxonMobil 10,000 Drillship 2010 23,888 2,500,000 4Q15
32 ENSCO DS-5 Ensco Repsol 10,000 Drillship 2011 20,000 2,000,000 3Q16
33 Noble Bully I Noble Shell 10,000 Drillship 2011 13,558 2,204,623 2Q17
34 Pacific Santa Ana Pacific Drilling Chevron 10,000 Drillship 2011 22,046 2,000,000 2Q17
35 Atwood Condor Atwood Shell 10,000 6G 2012 8,818 2,500,000 4Q16
36 Noble Globetrotter I Noble Shell 10,000 Drillship 2012 19,842 2,403,039 2Q22
37 Atwood Advantage Atwood Noble Energy 10,000 Drillship 2013 25,353 2,500,000 1Q17
38 Noble Don Taylor Noble Shell 10,000 Drillship 2013 22,046 2,500,000 1Q19
39 West Auriga Seadrill BP 10,000 Drillship 2013 19,842 2,500,000 3Q20
40 West Vela Seadrill BP 10,000 Drillship 2013 19,842 2,500,000 4Q20
41 Noble Danny Adkins Noble Shell 12,000 6G 2009 8,000 2,500,000 3Q14
42 Discoverer Clear Leader Transocean Chevron 12,000 Drillship 2009 22,046 2,500,000 3Q18
43 Noble Jim Day Noble Shell 12,000 6G 2010 8,000 2,500,000 1Q16
Rig Name Manager Operator
Water
Depth (ft) Gen
Year
In Svc
Variable
Deck Load
(Tons)
Derrick
Capacity
(lbs)
Discoverer Americas Transocean Statoil 12,000 Drillship 2009 22,046 2,500,000
Titanium Explorer Vantage Drilling Petrobras 10,000 Drillship 2012 22,046 2,500,000
Noble Bob Douglas Noble Anadarko 10,000 Drillship 2013 22,046 2,500,000
Noble Globetrotter II Noble Shell 10,000 Drillship 2013 19,842 2,403,039
Sevan Louisiana Seadrill LLOG 10,000 6G 2013 16,535 2,000,000
Deepwater Invictus Transocean BHP Billiton 10,000 Drillship 2014 24,251 2,500,000
Maersk Valiant Maersk Drilling ConocoPhillips 10,000 Drillship 2014 22,046 2,500,000
Maersk Viking Maersk Drilling ExxonMobil 12,000 Drillship 2014 22,046 2,500,000
Noble Sam Croft Noble Freeport McMoran 10,000 Drillship 2014 22,046 2,500,000
Ocean Blackhawk Diamond Offshore Anadarko 10,000 Drillship 2014 24,300 2,500,000
Ocean Blackhornet Diamond Offshore Anadarko 10,000 Drillship 2014 24,300 2,500,000
Pacific Sharav Pacific Drilling Chevron 10,000 Drillship 2014 24,250 2,500,000
Rowan Resolute Rowan Anadarko 12,000 Drillship 2014 22,046 2,500,000
West Neptune Seadrill LLOG 10,000 Drillship 2014 5,181 2,500,000
Rowan Reliance Rowan Cobalt Intl 12,000 Drillship 2014 22,046 2,500,000
Noble Tom Madden Noble Freeport McMoran 10,000 Drillship 2014 22,046 2,500,000
ENSCO DS-9 Ensco TBA 10,000 Drillship 2014 24,250 2,500,000
Deepwater Conquerer Transocean Chevron 12,000 Drillship 2016 25,353 2,500,000

Widening WTI/Brent Spread May Impact LLS

80
85
90
95
100
105
110
$/bbl
LLS WTI Brent
95
100
105
110
115
Jan-13
Feb-13
Mar-13
Apr-13
May-13
Jun-13
Jul-13
Aug-13
Sep-13
Oct-13
Nov-13
Dec-13
Jan-14
Feb-14
Mar-14
$/bbl
Brent LLS
LLS Shows Signs of De-Linking from Brent, Moving Toward WTI
Source: Bloomberg, Guggenheim Securities, LLC.
Brent vs. LLS Crude Oil, 2013- Present
Brent, WTI, & LLS Futures Curves
Toward the end of 2013, LLS Crude
began to diverge from Brent Crude. The
direction of LLS will likely have a big
impact on operators‘ decision making in
the Gulf of Mexico.
The futures market assumes that
LLS will gravitate toward WTI vs.
Brent over time, under the
assumption that exports will not
be allowed. If WTI/Brent spreads
widen, long-term oil assumptions
of ~$70/bbl for project economic
assessments may gravitate
lower. In our view, long-term oil
price assumptions by upstream
players will follow the long end of
the futures curve.
Note: we create synthetic LLS futures by using the LLS/WTI Spread

Bearish ‗14 & ‗15 WTI Forecast, Excerpt from Roger Diwan Report 1/28/14
 As U.S. crude output continues to grow, we believe that the domestic refining industry has a limited ability to further absorb the
tsunami of light sweet crude production. PADD 3 is already close to saturation, and with production continuing to rise dramatically in 2014,
U.S. crude will more than fill the remaining pockets of spare domestic demand. Light-sweet supply will likely soon overwhelm the ability of
the U.S. crude processing infrastructure to accommodate it, resulting in further dislocation of U.S. prices from global price markers.
Exactly when this nationwide structural ―near-saturation point‖ will come to pass depends on a number of variables, but we believe it
is likely to occur before mid-2015.
 The risk of ―near-saturation‖ implies that domestic crude pricing will become increasingly discounted from global prices as the export valve
remains shut . We believe that the United States will start to see the Super-Discounts increasing on a seasonal basis before
becoming structural by 2015. For this reason, we expect WTI prices to average $86.5/b, $16/b below Brent, in 2014. This Super-
Discount is likely to grow in 2015 as the limited relief valves that still exist in 2014 are overwhelmed, and we see a risk of having WTI
prices averaging below $80/b in 2015, assuming crude exports remain off the table.
 Our Brent crude oil price forecast is now $102.50 for 2014, revised down from our forecast in October of $103.50. Softer pricing is
supported by another upward revision in supply, despite expected outages from key OPEC producers. In our base case, we see Brent prices
continuing their softening—a softening that could have been a rout had Iranian and Libyan barrels remained in the market. To this
end, the potential return of Iranian supply clearly remains the most salient and unpredictable risk on the horizon for Brent prices.
 Over the medium term, fundamentals are still eroding, with non-OPEC supply outpacing stabilizing, but still anemic global demand
both this year and next. This trend has been masked by the major supply outages of the past two years. Even if these endure, OPEC supply
will need to be trimmed again in view of the expected surge in Non -OPEC supply in 2014 and 2015, led by North America.
Source: The unbearable Lightness of U.S. Crudes: Oil Super-Cycle Delivers Super-Discount in 2014 &
2015 , Roger Diwan, 1/28/14. PFC Energy-Guggenheim, Wall Street Journal
Guggenheim Crude Oil Price Forecast
$/barrel 2012 1Q13 2Q13 3Q13 4Q13 2013 1Q14F 2Q14F 3Q14F 4Q14F 2014F 2015F
Brent $111.69 $112.93 $103.35 $110.05 $109.35 $108.74 $103.00 $102.00 $105.00 $100.00 $102.50 $96.00
Forecast on
10/24/2013 $108.00 $108.82 $107.00 $101.00 $105.00 $101.00 $103.50 $98.00
Futures on
3/7/2014 - - - - 108.5 107.2 105.6 107.1 102.4
WTI $95.66 $94.32 $94.17 $105.81 $97.56 $98.01 $86.00 $88.00 $92.33 $79.67 $86.50 $78.00
Forecast on
10/24/2013 $101.00 $97.62 $99.00 $94.00 $100.00 $95.00 $97.00 $89.00
Futures on
3/7/2014 - - - - 101.8 99.1 96.2 99.0 90.3

Infrastructure Constraints Lead to Regional Crude Price Differentials
Source: PFC Energy–Guggenheim, Bloomberg
$/bbl Price, 3/7
WCS 80.73$
$/bbl Price, 3/7
Bakken 96.08$
$/bbl Price, 3/7
Maya 92.68$
$/bbl Price, 3/7
Midland 94.33$
$/bbl Price, 3/7
WTI 102.58$
$/bbl Price, 3/7
LLS 106.93$
$/bbl Price, 3/7
Landed Brent 108.58$

Planned Infrastructure Brings More Crude to Gulf Over Time: WTI/LLS Arbitrage
ENB/ETP Trunkline
420mbd
TRP Keystone 700mbd
ETP Permian Express 200mbd &
West Coast Gulf ~100mbd.
MMP/OXY BridgeTex 278mbd
and MMP Longhorn 225mbd
ENB/ETP
Seaway 450mbd
Source: PFC Energy–Guggenheim, Bloomberg

Gulf of Mexico Floater Market Dynamics

28 29
32
34
32
31
32 32
29
27
28
31
33
28
26
25
27
25
27
31
37
38
39
56
50
48
57
55
20
25
30
35
40
45
50
55
60
1Q05
1Q06
1Q07
1Q08
1Q09
1Q10
1Q11
1Q12
1Q13
1Q14E
1Q15E
1Q16E
1Q17E
1Q18E
RigQuarters
Total Rig Demand History & Forecast
Working Floaters in the GoM, History, and Projections
We see an
increase in
working floaters in
the GoM in 2014,
with a leveling off
over the next
several years.

22
19
14
16
20
21
25
20
14
18 18
16
17
19
13
2
4
11
9
14
17
19
20
23
24
20
15
9 9 9
-
5
10
15
20
25
1Q05
1Q06
1Q07
1Q08
1Q09
1Q10
1Q11
1Q12
1Q13
1Q14E
1Q15E
1Q16E
1Q17E
1Q18E
NumberofRigQuarters
61
55
59
63
41
58
62 62
91
96
93
87
107
98
40
50
60
70
80
90
100
110
DevelopmentWellCount
GoM Floater Mix: Development Drilling Emphasized, Exploration Decelerates
GoM Development Well Count History and Projections Floaters Working in E&A in the GoM,
History and Projections
Source: IHS Inc., Guggenheim Securities, LLC
Note: well count excludes shallow water
Recession-driven
drop-off
Macondo- driven
decline
Production and
reserve
replacement
needs may make
our outlook
conservative.
Move to develop recent GoM
discoveries.
19
32
26
37
28 28
24
19
25
17
5 5
12 11
0
5
10
15
20
25
30
35
40
Discoveries
GoM Discoveries
Emphasis on
developing the
number of
discoveries made
over the last
decade.

GoM Demand Projections Imply Deficits that Call for Contract Renewals
Company
2014E 2015E 2016E 2014E 2015E 2016E 2014E 2015E 2016E
Shell 8 8 10 5.9 5.0 4.8 (1.9) (2.5) (5.4)
BP 5 7 3 6.4 6.0 5.3 1.1 (1.2) 2.0
Anadarko 6 6 9 4.1 4.6 4.0 (1.6) (1.2) (4.8)
Chevron 6 4 2 3.5 4.0 4.0 (2.0) 0.3 1.7
BHP 1 0 1 0.8 1.0 1.0 0.1 0.7 0.2
Noble Energy 4 3 4 1.6 1.0 1.0 (1.9) (1.5) (2.8)
Stone Energy 1 1 - 0.6 - - (0.1) (1.0) -
Apache - - 1 1.0 - - 1.0 - (1.0)
Cobalt - - - 0.2 - - 0.2 - -
Eni - 1 - 1.0 0.3 - 1.0 (0.7) -
ExxonMobil 2 3 1 1.9 1.8 1.0 0.4 (1.0) 0.5
Hess 1 1 2 0.9 - - (0.1) (0.7) (2.0)
Murphy 1 1 1 1.0 1.0 0.9 (0.3) (0.3) (0.1)
Statoil - - - 1.8 1.9 0.3 1.8 1.9 0.3
Marathon - 1 - 1.1 1.0 1.0 1.1 - 1.0
Other 8 6 5 6.4 8.0 7.1 (1.6) 2.0 2.3
Total 41 41 39 38 36 30 (3) (5) (8)
Company
2014E 2015E 2016E 2014E 2015E 2016E 2014E 2015E 2016E
Shell 3 1 1 3.6 3.0 2.0 0.6 2.0 1.0
BP 2 2 2 1.6 1.0 1.0 (0.4) (1.0) (1.0)
Anadarko 1 - - 0.5 - - (0.5) - -
Chevron 4 4 4 1.0 1.0 0.7 (3.0) (3.0) (3.3)
BHP - - - 0.2 - - 0.2 - -
Noble Energy - - - 0.6 - - 0.6 - -
Stone Energy - - - 0.1 - - 0.1 - -
Apache - - - - - - - - -
Cobalt - - - - 0.9 1.0 - 0.9 1.0
Eni 2 - - - - - (2.0) - -
ExxonMobil - - - - - - - - -
Hess - 1 1 - - - - (1.0) (1.0)
Murphy 1 - - - - - (1.0) - -
Statoil 1 1 1 - - - (1.0) (1.0) (1.0)
Marathon - - - - - - - - -
Other 1 - - - - - (1.0) - -
Total 15 9 9 8 6 5 (7) (3) (4)
E&A Rig Contract Coverage
Development Rig Demand Development Rig Contract Coverage Development Rig Surplus/(Deficit)
E&A Demand E&A Rig Surplus/(Deficit)

56
50 48
57
1 11 13
4
57
61 61 61
0
10
20
30
40
50
60
70
YE2014 YE2015 YE2016 YE2017
RigQuarters
Forecast Total Potential
34 36 38 38 38 38 38 37
9 6
6 6 4 3 3 3
3
1
46
43 44 44
42 41 41 40
0
5
10
15
20
25
30
35
40
45
50
1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15
ContractedRigQuarters
Ultradeepwater Deepwater Midwater
46
43 44 44
42 41 41 40
1
2
2 2
2
2 3
3
1
1
1
25
30
35
40
45
50
1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15
RigQuarters
Contracted Adjusted Tenders Raw Tenders
Probable Contract Renewals Leave Forecast Conservative, Upside from Tenders
Note: all data are estimates by Guggenheim Securities, LLC
Future Contracted Floaters in the GoM Potential Incremental Demand from Tenders
Note: tenders are cumulative; i.e. if a new tender is for one
year, it will appear as one rig throughout that year
Potential Total Demand from Contract Renewals &
New Contract Starts
Potential Contracts with Renewals vs. Our Floater Forecast
41 41 38
43 40 40 41 40
5 2
6
1
2 1
7
12
13
16
17 19 21
48
50
56 57 58 58
60 61
0
10
20
30
40
50
60
1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15
RigQuarters
Existing Contracts New Contracts Cumulative Roll Offs

Shell and BP Dominate the Gulf, with Contracted Visibility Strong Through 2015
Current and Future Contracted Floaters in the Gulf of Mexico by Operator
Grey, bolded cells
indicate potential upside
from tenders, if they
translate into actual rig
demand
Quarter Operator Status
Rig
Years
2Q14 Statoil Tender 4.0
1Q14 Eni Probable 0.3
3Q15 Hess Probable 0.6
1Q16 Hess Probable 4.0
1Q14 Marathon Possible 1.9
Tender Demand
Operator
Current
Contracted 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15
Shell 9 9 9 9 8 8 8 8 8
BP 8 8 7 7 7 6 6 6 6
Anadarko 4 4 4 5 5 5 5 5 4
Chevron 4 4 4 5 5 5 5 5 5
BHP Billiton 2 2 1 1 1 1 1 1 1
LLOG 2 2 2 2 3 3 3 3 3
Noble Energy 2 3 3 2 1 1 1 1 1
Stone Energy 2 2 1 1 - - - - -
Apache 1 1 1 1 1 1 - - -
Cobalt Intl 1 1 - - - 1 1 1 1
Eni 1 1 1 1 1 1 1 - -
ExxonMobil 1 2 2 2 2 2 2 2 2
Hess 1 1 1 1 1 - - - -
Husky Oil Operations 1 - - - - - - - -
Marubeni 1 1 1 1 - - - - -
Murphy 1 1 1 1 1 1 1 1 1
Repsol 1 1 1 - - - - - -
Statoil 1 1 1 1 2 2 2 2 2
ConocoPhillips - - - - 1 1 - - 1
Marathon - 1 2 1 1 - 1 1 1
Operator Tba - - - 1 1 - - 1 -
Petrobras - 1 1 1 2 2 2 2 2
PXP - - - 1 1 2 2 2 2
Total 43 46 43 44 44 42 41 41 40
Roll-Offs 2 5 5 1 3 1 2 2
Cumulative Roll-Offs 2 7 12 13 16 17 19 21
Potential Contracted W/ Rolls 48 50 56 57 58 58 60 61

GoM Development Well Forecast Leaves Non-FID Risk 3-5 Rigs in 2014-15
Source: Infield Systems, IHS Inc, Guggenheim Securities, LLC
The well count projections from PFC are already ―risked‖ based on the likelihood
that projects reach FID (Final Investment Decision). For Infield well counts, we
use our own conservative probability weights in order to arrive at a reasonable
projection for well count growth. As we get further toward 2018, the differential
between raw and adjusted Infield data becomes greater, as more projects are
marked ―probable‖ and ―possible.‖
Development Well Count & Rig Count Projections
Probability Weights Assigned to Infield Wells
Apply
probability
weights
Apply
well/rig
ratios
Development Well Count & Rig Count Projections
Status 2014E 2015E 2016E 2017E 2018E
Firm 100% 100% 100% 100% 100%
Probable 0% 50% 75% 75% 75%
Possible 0% 25% 30% 30% 30%
Note: FID = Final Investment Decision
Water Depth 2014E 2015E 2016E 2017E 2018E
Ultradeepwater 7 10 9 21 18
Deepwater 46 46 46 44 58
Midwater 46 40 33 49 39
Total 99 96 88 114 115
Deepwater 44 45 46 43 55
Midwater 45 38 32 48 31
Total 96 93 87 107 98
Deepwater 22 23 23 22 28
Midwater 15 13 11 16 10
Total 41 41 39 47 45
Implied Rig Demand
Raw Data
Risk-Weighted Data
(2.0x Well/Rig for UDW/DW, 3.0x for MW)
Status 2014E 2015E 2016E 2017E 2018E
Base 35 35 18 15 13
FID 52 49 44 56 27
Non-FID 12 12 26 43 75
Total 99 96 88 114 115
Status 2014E 2015E 2016E 2017E 2018E
Base 35 35 18 15 13
FID 52 49 44 56 27
Non-FID 9 9 25 36 58
Total 96 93 87 107 98
Raw Data
Risk-Weighted Data
At an implied
well-to-rig
ratio of 2-3
per year, 9
Non-FID
wells in 2014-
2015 could
translate into
3-5 rigs at
risk.

Much of the ―Deficit‖ Hinges on Projects Reaching Final Investment Decision
GoM Projected Implied Development Rig Demand, Non-FID Only
A meaningful portion of our
rig demand forecast is
contingent upon projects
being sanctioned.
Company
2014
Wells
2015
Wells
2016
Wells
2014
Implied
Rigs
2015
Implied
Rigs
2016
Implied
Rigs
Shell - 1 9 - - 3
BP - - - - - -
Anadarko - 1 3 - 1 2
Chevron - - - - - -
BHP - - - - - -
Noble Energy - - - - - -
Stone Energy - - - - - -
Apache - - 1 - - 1
Cobalt - - - - - -
Eni - - - - - -
ExxonMobil - - - - - -
Hess 1 - 5 1 - 2
Murphy 2 1 - 1 1 -
Statoil - - - - - -
Marathon - - - - - -
Other 6 6 7 2 3 3
Non-FID 9 9 25 4 5 11
Total 41 41 39
% Non-FID 10% 12% 28%

0%
5%
10%
15%
20%
25%
30%
35%
40%
45%
50%
55%
60%
10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80%
AvgofFullCycleIRR(%)
Avg of Dev Fwd IRR (%)
Sanctioned
Unsanctioned
Incremental Returns Favor Development, Full Cycle Returns Promote Vetting
Unsanctioned projects gravitate toward both lower IRRs. Projects below a ~15-20% IRR may become
more variant if operators see a risk to oil prices or require a bigger cushion with regard to project
returns. Larger NPVs may prove more attractive as project management constraints at the operator
level push for larger projects to best leverage internal resources.
Note: Project economics run
at $70/bbl oil prices.
Note: Projects with negative
NPVs or IRRs are omitted
from the chart.
Lower full cycle economics on project lists
leaves investors calling for project reviews
for upstream players.
The economics of incremental
capital decisions, illustrated in
development forward IRRs,
suggest that most projects that
have reached the development
phase should move forward.

0%
10%
20%
30%
40%
50%
60%
70%
$- $500 $1,000 $1,500 $2,000 $2,500 $3,000
AvgofFullCycleIRR(%)
Avg of Total CAPEX($mm)
Sanctioned
Unsanctioned
Large Infrastructure CAPEX May Prove a ―Gating‖ Factor in the GoM
The cost of production infrastructure may prove a gating factor
for new projects. Thus, the ability to tie back to existing
infrastructure or find lower-cost production solutions may
determine the fate of projects. We look to recent project delays
due to infrastructure cost concerns as an example of this issue
playing out in the market.

Ultra/Deepwater E&A Tenders Calls for Decline in Exploration Activity
2014E 2015E
Current Number of Floaters Working in E&A 18
Raw Demand
"Tender" Demand 1 1
"Pre-Tender" Demand - -
"Probable" Demand 1 1
"Possible" Demand 1 1
Total Un-risked Demand 3 3
Add Probability-Weighted Demand
Adjusted "Tender" Demand (100%) 1 1
Adjusted "Pre-Tender" Demand (100%) - -
Adjusted "Probable" Demand (20-45%) - -
Adjusted "Possible" Demand (5-35%) - -
Total Probability Weighted Demand 1 1
Subtract Available Rigs
Subtract: Ultradeepwater Available Rigs 2 4
Subtract: Deepwater Available Rigs 2 2
Subtract: Total UDW/DW Rigs Coming Available 4 6
Beginning of Period Demand 18 15
Add: Total Probability Weighted Demand 1 1
Subtract: Total UDW/DW Rigs Coming Available (4) (6)
Total Exploration Demand: Ultra/Deepwater 15 11
E&A Tender Demand Calculation- UDW/DW Current UDW/DW Rigs Working in E&A in the GoM
Discoverer Spirit, GSF Development Driller I, Noble Danny
Adkins, & Ocean Victory become available in 2014.
Deepwater Pathfinder & ENSCO 8506 become available in
2015. Our forecast conservatively assumes that these are
not re-contracted in the Gulf of Mexico.
In Midwater, the
Ocean Saratoga
& Noble Driller
are currently
working but
coming off
contract this year.
2014E 2015E
Ultra/Deepwater Exploration Demand 15 11
Midwater Exploration Demand - (2)
Total Exploration Demand 15 9
E&A Tender Demand Calculation- Total Floater
# Rig Name Market Category Manager Operator
1 Deepwater Pathfinder Drillship >7500 Transocean Eni
2 Discoverer Clear Leader Drillship >7500 Transocean Chevron
3 Discoverer Deep Seas Drillship >7500 Transocean Murphy
4 Discoverer India Drillship >7500 Transocean Chevron
5 Discoverer Inspiration Drillship >7500 Transocean Chevron
6 Discoverer Spirit Drillship >7500 Transocean Anadarko
7 ENSCO 8500 Semi >7500 Ensco Anadarko
8 ENSCO 8501 Semi >7500 Ensco Noble Energy
9 ENSCO 8506 Semi >7500 Ensco Anadarko
10 ENSCO DS-5 Drillship >7500 Ensco Repsol
11 GSF Development Driller I Semi 5001-7500 Transocean BHP Billiton
12 Noble Danny Adkins Semi >7500 Noble Shell
13 Noble Globetrotter I Drillship >7500 Noble Shell
14 Noble Jim Day Semi >7500 Noble Shell
15 Ocean Victory Semi 5001-7500 Diamond Offshore Stone Energy
16 Pacific Santa Ana Drillship >7500 Pacific Drilling Chevron
17 West Sirius Semi >7500 Seadrill BP
18 West Vela Drillship >7500 Seadrill BP

E&A History Supports Possibility of Contract Renewals
Floaters Working in Exploration & Appraisal in the GoM
Note: data in the above table is counted in rig quarters, and then rounded
Our current forecast calls for 15 rigs working in E&A in the GoM in 2014 and 9 in 2015.
Given how many rigs operators have employed in recent history, we see potential
demand upside given the likelihood that some contracts get renewed or extended.
Operator 1Q09 2Q09 3Q09 4Q09 1Q10 2Q10 3Q10 4Q10 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 2014E 2015E 2016E
Average
2009-2013
Average
2012-2013
Anadarko 3.5 2.9 1.7 2.2 2.4 1.5 - 0.7 0.2 - - 1.9 2.0 1.1 1.2 3.2 4.5 3.8 4.1 3.6 1 - - 2 4
Apache - - - - - - - - - - - 0.4 - 0.4 0.4 - 0.1 0.6 0.3 1.0 - - - 0 1
BHP Billiton 0.2 1.5 1.0 0.0 1.5 0.9 - 0.4 1.8 1.0 1.0 2.0 1.4 1.2 1.4 0.8 0.1 1.3 1.5 0.2 - - - 1 1
BP 1.2 2.0 1.5 2.7 2.0 0.5 - - - - - 0.9 2.0 2.7 3.6 3.4 3.2 2.3 1.7 2.2 2 2 2 2 2
Chevron 1.0 1.0 1.1 0.6 0.2 0.7 - - 0.2 2.0 2.3 2.2 3.0 3.3 2.6 3.0 3.5 3.4 3.6 4.0 4 4 4 2 4
Cobalt Intl - - 0.9 1.0 0.4 - - - - - - 0.0 1.0 1.0 0.9 1.0 0.9 1.0 0.9 1.0 - - - 1 1
Eni 1.0 1.1 1.5 1.1 1.0 0.9 - - 0.7 1.0 2.0 1.0 0.8 0.5 0.8 1.1 1.8 1.0 1.3 1.4 2 - - 1 1
ExxonMobil - - - 1.0 0.7 - - - 0.1 0.5 1.0 - - 0.2 1.5 0.8 0.4 - 1.0 0.0 - - - 0 0
Hess - - - - 0.5 0.8 - - - - - - - 0.1 0.1 0.9 1.0 1.0 0.2 - - 1 1 0 1
Marathon - 0.4 - 0.3 1.1 1.2 - - - - - - - - 0.3 0.5 - - 0.1 1.0 - - - 0 0
Murphy 0.7 1.0 0.6 0.1 0.7 0.5 - - - - - - - - 0.5 0.3 - - - 0.2 1 - - 0 0
Noble Energy 0.9 0.1 - 1.1 1.0 0.8 - - - 0.7 - 1.0 0.7 1.0 0.9 0.8 0.8 0.9 1.0 1.0 - - - 1 1
Shell 0.2 1.2 2.2 2.8 2.7 1.1 - - 0.6 3.4 1.4 2.4 2.2 3.1 2.7 4.4 4.9 4.8 6.8 3.4 3 1 1 3 5
Statoil - - 0.2 1.5 2.0 1.8 - - - 1.5 0.6 0.3 1.0 1.5 1.0 1.0 0.5 0.5 0.6 - 1 1 1 1 0
Stone Energy - - - - - - - - - - - - - - - - - - - 0.6 - - - 0 0
Other 5.3 6.3 5.5 2.9 2.9 2.6 0.2 0.8 0.3 1.0 1.2 1.9 2.7 2.6 2.4 2.3 1.2 2.5 1.1 0.3 1 - - 2 1
Total 14 18 16 17 19 13 0 2 4 11 9 14 17 19 20 24 23 23 24 20 15 9 9 15 23

Well/Rig Sensitivity Analysis Implies Bullish Bias
Contracted Floater Forecast in the GoM Well/Rig Ratio Sensitivity Analysis
For our global rig supply/demand model, we assume a well/rig ratio of 2:1
for ultra-deepwater and deepwater, and 3:1 for midwater development
wells.
In order to account for potential variation across regions, we
ran a sensitivity analysis to measure the impact of changes
in the well/rig ratio input. Currently, the implied well/rig ratio
is close to 3.0x.
56 1.00 1.25 1.50 1.75 2.00 2.25 2.50 2.75 3.00 3.25 3.50 3.75 4.00 4.25 4.50 4.75 5.00
1.00 111 101 94 89 86 83 81 79 77 76 75 74 73 72 72 71 70
1.25 102 92 85 80 77 74 72 70 68 67 66 65 64 63 63 62 61
1.50 96 86 79 74 71 68 66 64 62 61 60 59 58 57 57 56 55
1.75 92 82 75 70 66 64 61 60 58 57 56 55 54 53 52 52 51
2.00 89 79 72 67 63 60 58 56 55 53 52 51 51 50 49 48 48
2.25 86 76 69 64 61 58 56 54 52 51 50 49 48 47 47 46 45
2.50 84 74 67 62 59 56 54 52 50 49 48 47 46 45 45 44 43
2.75 83 72 66 61 57 54 52 50 49 47 46 45 44 44 43 42 42
3.00 81 71 64 59 56 53 51 49 47 46 45 44 43 42 42 41 40
3.25 80 70 63 58 55 52 49 48 46 45 44 43 42 41 40 40 39
3.50 79 69 62 57 54 51 49 47 45 44 43 42 41 40 39 39 38
3.75 78 68 61 56 53 50 48 46 44 43 42 41 40 39 39 38 37
4.00 78 67 61 56 52 49 47 45 44 42 41 40 39 39 38 37 37
4.25 77 67 60 55 51 49 46 44 43 42 40 39 39 38 37 37 36
4.50 76 66 59 54 51 48 46 44 42 41 40 39 38 37 37 36 35
4.75 76 66 59 54 50 47 45 43 42 40 39 38 37 37 36 35 35
5.00 75 65 58 53 50 47 45 43 41 40 39 38 37 36 36 35 34
Ultra/Deepwater Well/Rig Ratio
MidwaterWell/RigRatio
2014E 2015E 2016E 2017E 2018E
Ultra/Deepwater Wells 51 55 55 59 67
Divided by: U/DW Well/Rig Ratio 2.0 2.0 2.0 2.0 2.0
Equals: Ultra/Deepwater Rigs 26 28 28 30 34
Midwater Wells 45 38 32 48 31
Divided by: MW Well/Rig Ratio 3.0 3.0 3.0 3.0 3.0
Equals: Midwater Rigs 15 13 11 17 11
Ultra/Deepwater Rigs 26 28 28 30 34
Midwater Rigs 15 13 11 17 11
Total Development Rigs 41 41 39 47 45
E&A Rigs 15 9 9 9 9
Development Rigs 41 41 39 47 45
Total Rigs 56 50 48 57 55

Offshore Rig Market Balances (1/22/14 Report)

Sensitivity Analysis Points Toward a More Favorable Supply/Demand Balance
Note: the rig attrition number is cumulative
We assume 92% utilization to
account for frictional downtime
and shipyard time. Historically,
utilization has run closer to 80-
85%. Our conservative estimate
lends a bias toward a tighter
floater market. (pg. 12)
Our model incorporates no rig
attrition into the supply/demand
balance. We see the potential for
43 floaters to retire by 2015 as
contract expirations of these
older, lower spec rigs may be
catalysts for retirement. There is
no bear case in this scenario
because rigs will not return to the
market.
There is a strong relationship between
crude oil prices and E&A floater demand,
so activity may move with oil price
outlooks. At the same time, our forecast
for a North American slowdown may free
up capital for offshore exploration work.
We have already heavily
probability-weighted down
unsanctioned project
development demand, but if
conditions turned more bearish,
there is a risk that the remaining
unsanctionedd demand would
never reach FID.
Utilization
2014E 2015E 2014E 2015E
Bull Case (80%) 252 276 (38) (41)
Base Case (92%) 290 318 - -
Bear Case (95%) 299 328 9 10
Rig Attrition
2014E 2015E 2014E 2015E
Bull Case 263 275 (27) (43)
Base Case (no attrition) 290 318 - -
Bear Case (no attrition) 290 318 - -
Exploration & Appraisal Rig Demand Relative to Oil Price
2014E 2015E 2014E 2015E
Bull Case (Recent Peak -110 rigs) 110 110 17 12
Base Case 93 98
Bear Case (Recent Low - 80 rigs) 80 80 (13) (18)
Unsanctioned Development Demand at Risk
2014E 2015E 2014E 2015E
Bull Case (+10% to all probabilities) 36 50 - 3
Base Case 36 47 - -
Bear Case (Unsanctioned Projects Lapse) - - (36) (47)
Unsanctioned Demand Projection
In Overall Supply
In Overall Supply
In Overall Demand
In Overall Demand
Potential Increase/(Decrease)
Overall Supply Projection
Overall Supply Projection
Exploration Demand Projection

Project Push Favors Long-Term Market Balances vs. Near-Term Tightness
Note: All estimates are by Guggenheim Securities, LLC.
Source: IHS Inc., Infield Systems, Guggenheim Securities, LLC
Probability-weighted, field-
by-field data analyzed
across regions, based on
project likelihood
for sanctioned and non-
sanctioned projects.
Exploration rig demand
focuses on probability-
weighted tender activity in
the near term. Post 2015,
estimates based on
exploration requirements
needed to meet longer-term
offshore production forecast.
The market balance
incorporates the demand in
concert with total rig supply,
adjusted for cold stacked
and other non-marketed
rigs, newbuilds, but without
the assumption of rig
attrition.
Near term, the floater
market remains fairly
balanced, but the wave of
expected development
drilling sees the rig deficit
expanding, even after
―risking‖ future project
probabilities. Thus, the
probability of FIDs for future
demand becomes the key
debate.
Development Floater Demand 2014E 2015E 2016E 2017E 2018E
Development Well Count - Ultra/Deepwater 256 275 287 318 359
Divided By: Well-to-Rig Ratio 2.0 2.0 2.0 2.0 2.0
Equals: Development Floater Demand - Ultra/Deepwater 128 138 143 159 179
Development Well Count - Midwater 196 209 222 221 200
Divided By: Well-to-Rig Ratio 3.0 3.0 3.0 3.0 3.0
Equals: Development Floater Demand - Midwater 65 70 74 74 67
Add: Development Floater Demand - Ultra/Deepwater 128 138 143 159 179
Add: Development Floater Demand - Midwater 65 70 74 74 67
TOTAL DEVELOPMENT FLOATER DEMAND 193 207 218 233 246
Exploration Floater Demand 2014E 2015E 2016E 2017E 2018E
Add: Exploration Rig Demand - Ultra/Deepwater 65 71 74 78 82
Add: Exploration Rig Demand - Midwater 28 28 29 31 32
Equals: TOTAL EXPLORATION FLOATER DEMAND 93 98 103 108 114
Total Floater Demand 2014E 2015E 2016E 2017E 2018E
Add: Ultra/Deepwater Floater Demand 194 209 218 237 261
Add: Midwater Floater Demand 94 98 104 105 100
Equals: TOTAL FLOATER DEMAND 288 307 322 342 361
Total Floater Demand Growth 12.5% 6.6% 4.9% 6.2% 5.6%
Floater Market Balance 2014E 2015E 2016E 2017E 2018E
Add: Ultradeepwater Floater Supply 120 143 156 166 172
Add: Deepwater Floater Supply 63 64 67 69 69
Less: Ultra/Deepwater Floater Demand (194) (209) (218) (237) (261)
Less: Carried Ultra/Deepwater Floater Demand - (12) (14) (8) (11)
Equals: Ultradeepwater Suplus/(Deficit) (12) (14) (8) (11) (31)
Add: Midwater Floater Supply 108 111 114 115 115
Less: Midwater Floater Demand (94) (98) (104) (105) (100)
Less: Carried Midwater Floater Demand - - - - -
Equals: Midwater Suplus/(Deficit) 14 13 10 10 15
Add: Ultradeepwater Suplus/(Deficit) (12) (14) (8) (11) (31)
Add: Midwater Suplus/(Deficit) 14 13 10 10 15
Equals: Total Floater Suplus/(Deficit) 2 (1) 2 (1) (16)
Previous Total Floater Surplus (Deficit) from 11/1/13 (1) (3) (1) (27) (45)

Unsanctioned Projected Demand at Risk Creates Significant Variance Potential
We assign little probability
for unsanctioned projects in
2014, outside of the PFC
forecast. We assign a lower
probability to a larger
inventory of longer dated
projects labeled either
―Probable‖ or ―Possible.‖
A negative outcome to near-
term unsanctioned project
risk could prove meaningful,
but risks to longer-dated
development projects may
impact up to ~40% of
forecasted rig demand.
Lack of clarity on the timing
for final investment
decisions will weigh on the
market, as typical tendering
activity only provides
visibility for projects two to
three years into the future.
More conservative
assumptions yield lower
deficits and highlight the
impact of probability
weights.
Source: IHS Inc., Infield Systems, Guggenheim Securities, LLC
A 1% increase in unsanctioned
demand at risk accounts for ~3
floaters, showing the high impact
of project FIDs on our forecasts.
Unsanctioned Development Rig Demand at Risk
2014E 2015E 2016E 2017E 2018E
Probable (75% Probability) - 2 3 5 5
Possible (25-30% Probability) - 0 2 5 7
Ultra-Deepwater Wells- Infield - 2 5 9 11
Deepwater Wells- Infield - 10 10 30 53
Midwater Wells- Infield - 30 45 81 143
Deepwater - PFC Energy 71 61 110 142 146
Total Unsanctioned Wells at Risk 71 102 170 262 354
Ultra/Deepwater Well-to-Rig Ratio 2 2 2 2 2
Midwater Well-to-Rig Ratio 3 3 3 3 3
Ultra/Deepwater Unsanctioned Floater Demand at Risk 36 37 63 91 106
Total Ultra/Deepwater Floater Demand 194 209 218 237 261
% of Demand at Risk 19% 18% 29% 38% 41%
Midwater Unsanctioned Floater Demand at Risk - 10 16 28 48
Total Midwater Floater Demand 94 98 104 105 100
% of Demand at Risk 0% 10% 15% 27% 48%
Total Unsanctioned Floater Demand at Risk 36 47 79 119 154
Total Floater Demand 288 307 322 342 361
% of Demand at Risk 13% 15% 25% 35% 43%
Previous% of Demand at Risk from 11/1/13 15% 19% 27% 36% 43%

Deepwater Projects Represent ~40% of New Source Production
Source: IHS Inc., Guggenheim Securities, LLC. Note: Subset of companies consists of APA, BG.-LN,
BHP,BP, CVX, COP, E, XOM, HES, LKOH-MZ, MRO, MUR,
NBL, OMV-VI, PBR, REP-MC, RDSA, STO, TLM, TLW-LN,
TOT
Forecast Cumulative New Source Oil Production by Asset Type, Global Majors
Deepwater Contribution to Forecast Cumulative New Source Oil Production
Deepwater production
remains the largest
contributor to new source
production in the forecast for
our sample set of
companies, representing
~5mbd or ~40% of new
source production by 2020.
Deepwater production
represents more than 2X the
production to come on from
other sources. Thus, we
anticipate that deepwater
development and
exploration drilling will
remain central to production
goals across the group.
-
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
5,000
2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E
ThousandsofBarrelsofOil/Day
Conventional Onshore Conventional Shallow Deepwater Oil Sands Unconventional
29% 31%
33%
37%
38%
40%
42%
44%
0%
5%
10%
15%
20%
25%
30%
35%
40%
45%
50%
2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E
%ofProjectedCumulativeNew
SourceProduction

Dayrate Forecasts Call for Normalization
Guggenheim Offshore Rig Dayrate Forecasts ($kpd)
Rig Type 1Q14E 2Q14E 3Q14E 4Q14E 1Q15E 2Q15E 3Q15E 4Q15E 1Q16E 2Q16E 3Q16E 4Q16E 1Q17E 2Q17E 3Q17E 4Q17E
Prem UDW DS 590 590 580 580 570 570 560 560 550 550 540 540 540 540 540 530
Prem UDW SS 530 530 520 520 510 510 500 500 490 490 480 480 470 470 460 450
Standard UDW DS 520 520 510 510 500 500 490 490 480 480 470 470 450 420 400 380
Standard UDW SS 510 510 500 500 490 490 480 480 470 470 460 460 430 410 380 360
Prem DW DS 430 430 420 420 410 410 400 400 390 390 380 380 330 270 220 170
Prem DW SS 430 430 420 420 410 410 400 400 390 390 380 380 360 340 330 310
Standard DW DS 240 240 240 230 230 220 220 210 210 200 200 190 200 200 200 200
Standard DW SS 430 430 420 420 410 410 400 400 390 390 380 380 350 310 280 240
HDHE MW DS 180 180 170 170 160 160 150 150 140 140 130 130 140 140 150 150
HDHE MW SS 500 500 490 490 480 480 470 470 460 460 450 450 410 370 330 280
MW DS 190 190 180 180 170 170 160 160 150 150 140 140 140 140 140 140
MW SS 360 360 350 350 340 340 330 330 320 320 310 310 280 250 220 200
HDHE JU 270 270 260 260 250 250 240 240 230 230 220 220 220 210 210 200
Prem JU 210 210 200 200 190 190 180 180 170 170 160 160 160 160 170 170
High End JU 170 170 170 160 160 150 150 140 140 130 130 120 120 120 120 120
Standard JU 140 140 140 130 130 120 120 110 110 100 100 90 90 90 80 80
Sub-Standard JU 100 100 100 90 90 80 80 70 70 60 60 50 60 60 60 70
Commodity JU 80 80 80 70 70 60 60 50 50 40 40 30 40 40 50 50
Legacy JU 70 70 70 60 60 50 50 40 40 30 30 20 30 40 50 60

9
6
-
3 5 3
-
3 3 3 1 3
1 5
4
5 3
2
3
9
1 2
1
3
1
6
10
15
18
20
23
32
33
35
36
39
-
5
10
15
20
25
30
35
40
45
1Q14
2Q14
3Q14
4Q14
1Q15
2Q15
3Q15
4Q15
1Q16
2Q16
3Q16
4Q16
NumberofRigs
Contracted Uncontracted Cumulative Uncontracted
4 4 2 1 3 - 1 - - 2 1 1
11
5 6 7
14
5
18 17 15
4 5 1
11
16
22
29
43
48
66
83
98
102
107 108
-
20
40
60
80
100
1Q14
2Q14
3Q14
4Q14
1Q15
2Q15
3Q15
4Q15
1Q16
2Q16
3Q16
4Q16
NumberofRigs
Contracted Uncontracted Cumulative Uncontracted
108 110 114 115 115
63 64 67 69 69
120
143
156 166 172
290
317
338
350 356
-
50
100
150
200
250
300
350
400
2014E 2015E 2016E 2017E 2018E
ProjectedTotalRigSupply
Midwater Deepwater Ultradeepwater
86 88 89 89 89
164 169 170 171 171
158
184
210 218 219
44
55
66 72 73
453
497
535
550 552
-
100
200
300
400
500
600
2014E 2015E 2016E 2017E 2018E
ProjectedTotalRigSupply
Commodity Standard Premium Harsh Environment
Fleet Growth
Source: ODS Petrodata, Infield Systems, PFC Energy-Guggenheim
Jackup Newbuild ProjectionsFloater Newbuild Projections
Floater Fleet Growth Projections Jackup Fleet Growth Projections

Offshore Driller Equity Overview

v
v
Stocks Likely Bifurcate on Asset Quality & Capital Budgeting Strategies
Favored to Benefit Capital Budgeting Strategies
SDRL – BUY – PT $50 : Delivery of newbuilds &
accretive financing from SDLP (NC, $30.80) offers
upside leverage to distributions and yield-based
valuations. The recent SDLP unit offering below a 6%
yield and North American IPO of NADL on the horizon
remain positive indicators.
ATW – BUY – PT $58: Attractive growth profile, solid
execution, and potential for future payout-friendly bias.
PACD – BUY – PT $14: Good management, pure-play
ultra-deepwater assets, recent favorable refinancing,
and longer-term dividend bias offer meaningful upside
potential.
DO – BUY – PT $65: Overly slighted for its older fleet,
we like DO‘s high payout strategy. We see potential for
significant upside to our target with a possible dividend
increase in 2014 as a catalyst. Current negative
sentiment surrounding DO‘s older fleet has created an
attractive entry point.
Special Situations – Transaction/Catalyst Driven
NE – BUY – PT $42: Potential for further upside on
spin-off of older asset and yield re-rate of premium
assets. The potential transaction on the horizon
provides a catalyst.
ORIG – BUY – PT $28: The need for cash and ORIG
shares as a source of funding at DRYS should prompt
a dividend strategy from ORIG and efforts to re-rate the
shares on yield-based metrics.
RIG – BUY – PT $55: Meaningful discount to NAV
leaves hope that activist involvement and reformulated
Board of Directors, with renewed dividend policy and
MLP plans, will lead shares to mean-revert.
Trapped in Multiple Compression
ESV – NEUTRAL – PT $60: Discount to NAV
screens well, with an opportunity for upside with
better communication of distribution policy.
RDC – NEUTRAL – PT $36: Trading closer to NAV,
we see potential for continued multiple compression
as investors infer higher capital budgeting risk on
companies without clear payout strategies or belief
in a transition from growth investment to higher
payouts.
HERO – NEUTRAL – PT $5: Peak-cycle
economics and stretched balance sheet create a
challenging risk/reward, despite a good
management team.
RIG: We see alpha in pot. strategic change,
but needs clarity around direction of
payout/plowback
ATW & PACD: Attractive fleets and
cash flow profiles may need a
dividend catalyst in the near term
versus medium term inferred by both
managements.
Reasons to Be More/Less Bullish
NE: Re-emphasis on growth vs. distributions
ORIG: Concerns about unconventional
ownership and corporate structure may
challenge the story for the shares.
RIG: We see alpha in pot. strategic change,
but needs clarity around direction of
payout/plowback

Large Cap
Services 7.3 x
Large Cap
Equipment 9.0 x
Small/Mid Cap
Svcs & Equipment
8.9 x
Offshore Drilling
6.4 xOnshore Drilling
5.7 x
Engineering &
Construction, 7.8x
5.5 x
6.0 x
6.5 x
7.0 x
7.5 x
8.0 x
8.5 x
9.0 x
9.5 x
5% 10% 15% 20% 25% 30%
EV/EBITDA'14E EBITDA Growth, '14E vs. '13E
Large Cap
Services 7.3 x
Large Cap
Equipment 9.0 x
Small/Mid Cap
Svcs &Equipment
8.9 x
Offshore Drilling
6.4 x
Onshore Drilling
5.7 x
Engineering &
Construction 7.8 x
5.5 x
6.0 x
6.5 x
7.0 x
7.5 x
8.0 x
8.5 x
9.0 x
9.5 x
8.0 x 13.0 x 18.0 x 23.0 x 28.0 x
EV/EBITDA'14E
Price/Earnings '14E
Offshore Drillers Screen as a ―Good Property in a Tough Neighborhood‖
Source: Thomson Reuters., Guggenheim Securities, LLC.
2014E P/E vs. 2014E EV/EBITDA- Sub Sectors ‘14E Y/Y EBITDA Growth vs. 2014E EV/EBITDA- Sub Sectors
The mix of low valuations, high
cash flow, and overblown
negative sentiment about rig
supply/demand balances leave
offshore drillers screening
attractively within the group.
We see a potential for rotation out of high
multiple/high growth expectation stocks
with North American leverage into lower
multiple stocks with more visible earnings
growth that screen more attractively, like
the offshore drillers.

ATW
DO
ESV
NE
PACD
RDC
RIG
SDRL
HERO
ORIG
4.00
4.50
5.00
5.50
6.00
6.50
7.00
7.50
8.00
8.50
9.00
9.50
12% 14% 16% 18% 20%
2014EEV/EBITDA
2015E EBITDA/Gross Fleet Value
ATW
DO
ESV
NE
PACD
RDC
RIG
SDRL
HERO
ORIG
4.00
4.50
5.00
5.50
6.00
6.50
7.00
7.50
8.00
8.50
9.00
9.50
0 10 20 30 40
2014EEV/EBITDA
Average Fleet Age (years)
Investors continue to
reward smaller cap
names with clearly
defined growth
strategies, a bias
toward a higher payout
model in the medium to
long term, and newer
fleets.
ATW
DO
ESV
NE
PACD
RDC
RIG
SDRL
HERO
ORIG
4.00
5.00
6.00
7.00
8.00
9.00
0.00 0.50 1.00 1.50 2.00 2.50
2014EEV/EBITDA
Change in FCF ($B) FY13E-FY15E
ATW
DO
ESV
NE
PACD
RDCRIG
SDRL
HERO
ORIG
4.00
4.50
5.00
5.50
6.00
6.50
7.00
7.50
8.00
8.50
9.00
9.50
10% 20% 30% 40% 50% 60%
2014EEV/EBITDA
Net Debt/Gross Fleet Value
Multiple Compression Reflects Capital Budgeting & Fleet Age Concerns
Net Debt ‗15/Gross Fleet Value vs. EV/EBITDA FCF Growth vs. EV/EBITDA
SDRL helped by leverage, full payout, and
pot. benefits from SDLP financing.
The inverse relationship
between free cash flow (FCF)
growth and multiples suggests
concerns about the dilution of
return structures and risks to
incremental growth investment.
Source: Thomson Reuters, Guggenheim Securities, LLC
‗15 EBITDA/Gross Fleet Value vs. EV/EBITDAFleet Age vs. EV/EBITDA

Company Rating PX Target PX
Rtn to
Target TGT TGT
Current
Px
Current
Px
EV/EBITDA
'14
EV/EBITDA
'15
3/13 '14 PE '15 PE 14 PE 15 PE 2014E 2015E 2014E 2015E 2014E 2015E 2014E 2015E
ORIG Buy 17.09$ 28$ 64% 15.5x 10.0x 9.5x 6.1x 6.5x 5.4x 26$ 31$ 66% 55% 28$ 32$ 61% 53%
SDRL Buy 33.70$ 50$ 48% 15.1x 12.4x 10.2x 8.3x 8.6x 7.2x 28$ 31$ 120% 109% 28$ 31$ 120% 109%
DO Buy 44.39$ 65$ 46% 11.8x 8.6x 8.1x 5.8x 4.3x 3.2x 60$ 68$ 74% 65% 67$ 74$ 66% 60%
NE Buy 28.98$ 42$ 45% 10.5x 7.5x 7.2x 5.2x 5.2x 4.2x 42$ 46$ 69% 63% 42$ 46$ 69% 63%
PACD Buy 9.89$ 14$ 42% 14.0x 8.8x 9.9x 6.2x 7.9x 5.4x 14$ 16$ 71% 62% 14$ 16$ 71% 62%
RIG Buy 39.54$ 55$ 39% 11.0x 9.2x 7.9x 6.6x 5.6x 5.0x 55$ 62$ 72% 64% 55$ 62$ 72% 64%
ATW Buy 46.02$ 58$ 26% 10.7x 7.4x 8.5x 5.9x 7.5x 5.4x 58$ 66$ 79% 70% 66$ 74$ 70% 62%
ESV Neutral 48.86$ 60$ 23% 9.1x 7.5x 7.4x 6.1x 6.4x 5.3x 60$ 67$ 81% 73% 60$ 67$ 81% 73%
RDC Neutral 31.72$ 36$ 13% 12.6x 7.2x 11.1x 6.3x 6.2x 4.2x 36$ 41$ 88% 77% 44$ 49$ 72% 65%
HERO Neutral 4.55$ 5$ 10% 11.2x 91.4x 10.2x 83.2x 4.1x 5.2x 5$ 5$ 91% 95% 5$ 5$ 91% 95%
AVERAGE 36% 12.2x 17.0x 9.0x 14.0x 6.2x 5.1x 81% 73% 77% 71%
NAV-B/U P/NAV-B/U NAV-R P/NAV-R
NAV Comparison of Offshore Drillers Sees Shares Screen Attractively
Offshore drillers trade at a significant discount to NAV, suggesting a favorable
risk/reward
Gross Fleet Value Breakdown Estimated EBITDA Breakdown, 2014-2016
Most of our Gross Fleet Value and
EBITDA estimates are derived from
jackups, drillships, and 6G
semisubmersibles, but 20-30% of
these values comes from 2G, 3G, 4G,
& 5G semisubmersibles, leaving our
estimates at risk.
Ticker Jackups
2G
Semis
3G
Semis
4G
Semis
5G
Semis
6G
Semis Drillships Other
ATW 15% 0% 4% 8% 0% 37% 35% 0%
DO 4% 7% 6% 19% 21% 11% 32% 0%
ESV 28% 1% 1% 8% 26% 0% 36% 1%
HERO 78% 0% 0% 0% 0% 0% 0% 22%
NE 34% 0% 2% 26% 0% 0% 38% 0%
ORIG 0% 0% 0% 0% 14% 0% 86% 0%
PACD 0% 0% 0% 0% 0% 0% 100% 0%
RDC 63% 0% 0% 0% 0% 0% 37% 0%
RIG 8% 2% 8% 8% 11% 4% 58% 0%
SDRL 21% 0% 0% 1% 1% 38% 37% 1%
TOTAL 20% 1% 3% 8% 9% 12% 46% 1%
Ticker Jackups
2G
Semis
3G
Semis
4G
Semis
5G
Semis
6G
Semis Drillships Other
ATW 15% 0% 8% 17% 0% 40% 20% 0%
DO 4% 14% 12% 30% 17% 7% 16% 0%
ESV 29% 2% 2% 10% 23% 0% 28% 6%
HERO 78% 0% 0% 0% 0% 0% 0% 22%
NE 33% 0% 6% 31% 0% 0% 30% 0%
ORIG 0% 0% 0% 0% 19% 0% 81% 0%
PACD 0% 0% 0% 0% 0% 0% 100% 0%
RDC 72% 0% 0% 0% 0% 0% 28% 0%
RIG 4% 3% 16% 14% 12% 4% 48% 0%
SDRL 22% 0% 0% 3% 2% 39% 33% 1%
TOTAL 21% 2% 6% 13% 9% 11% 38% 1%

60
65
70
75
80
85
90
95
100
105
110
1.0X
1.2X
1.4X
1.6X
1.8X
2.0X
2.2X
Jan-09 Jan-10 Jan-11 Jan-12 Jan-13 Jan-14 DayrateIndex
Price/TangibleBookValue
P/TBV Average P/TBV Dayrate Index
Without Massive Dayrate Dive, Historical Relationships Support a Share Rally
Source: IHS Inc., Thomson Reuters., Guggenheim Securities, LLC.
Average Offshore Driller P/TBV vs. Dayrate Index
We see the ~40% decline
in dayrates in ‘09-‘10 as
unlikely to repeat.
Note: P/TBV for ATW, DO, ESV, HERO, NE, ORIG, PACD,
RDC, RIG, SDRL are averaged and then indexed.
The solid green line
represents the average
P/TBV over the specified
time period, and the
dotted green lines show
+/- 1 standard deviation
Current Price/Tangible Book Value
2.7X
1.4X 1.3X
1.2X
1.1X
1.0X 1.0X
0.8X 0.8X 0.8X
0.0X
0.5X
1.0X
1.5X
2.0X
2.5X
3.0X
SDRL DO ATW ESV RIG NE PACD RDC ORIG HERO
Price/TangibleBookValue

Global Contract Coverage Leaves Earnings Potential Secure in 2014
14%
23%
36%
29%
44%
49%
51%
48%
75%
40%
46%
52%
41%
66%
66%
68%
73%
86%
76%
78%
78%
86%
89%
92%
95%
100%
100%
0% 20% 40% 60% 80% 100%
DO
RIG
ESV
PACD
NE
ATW
SDRL
ORIG
RDC
2014E 2015E 2016E
Floaters 2014E-2016E Jackups 2014E-2016E
Source: Company Reports, Guggenheim Securities, LLC
8%
10%
21%
19%
12%
0%
12%
34%
13%
24%
42%
32%
34%
44%
38%
60%
37%
60%
65%
73%
74%
78%
80%
82%
0% 20% 40% 60% 80% 100%
HERO
DO
RIG
RDC
ESV
ATW
NE
SDRL
2014E 2015E 2016E

Clear Relationship Between Yield & Payout Ratios
Yield vs. DPS/CEPS
Source: Thomson Reuters, Company Reports, Guggenheim Securities, LLC
Full payouts should
migrate yields toward
each company‘s cost of
equity, under the
assumption that higher
payouts signify lower
future distribution
growth.
Lower yields are contingent upon perceived
future distribution growth. Theoretically,
lower payout ratios produce lower yields, as
assumed reinvestment should produce
dividend growth in the future.
DO 7.9%
ESV 6.1%
NE 3.5%
NADL 10.9%
SDLP 5.6%
HAL 0.9%
AKSO 3.9%
RIG 5.7%
CLB 3.9%
CRR 1.4%
OII 1.0%
0.0%
1.0%
2.0%
3.0%
4.0%
5.0%
6.0%
7.0%
8.0%
9.0%
10.0%
11.0%
12.0%
0% 20% 40% 60% 80%
DividendYield(LatestQuarter
Annualized)
DPS/CEPS 2013E

Appendix: Development Drilling Well Count Detail

Summation of Development Drilling Demand: Base/Infield
Continued on next page…
Field
Year on
Stream Water Depth Operator
Full
Cycle
IRR
%
Dev-
Forw ard
IRR %
CAPEX
$MM 2014E 2015E 2016E 2017E 2018E
Appaloosa- Mississippi Canyon 460-459 2011 Midw ater Eni n/a n/a n/a - 1 - - 1
Atlantis- Green Canyon 698-700 & 742-744 2007 Deepw ater BP n/a n/a n/a 4 4 3 - -
Atlantis North 2010 Deepw ater BP 24% 54% 458$ - 2 - 1 1
Atlantis South 2005 Deepw ater BP 31% 50% 1,257$ - 1 - 2 -
Callisto (AVP)- Mississippi Canyon 876 2011 Ultradeepw ater Anadarko n/a n/a n/a - 1 - - -
Clipper Corridor- Green Canyon 299-300 2013 Midw ater ATP n/a n/a n/a - - - 1 -
Deimos- Mississippi Canyon 806 2007 Midw ater Shell n/a n/a n/a 1 - - - -
Dorado- Viosca Knoll 915 2009 Midw ater Freeport-McMoRan n/a n/a n/a 1 - - - -
Europa- Mississippi Canyon 934-935 & 890 2000 Midw ater Shell n/a n/a n/a 1 - - - 1
Front Runner South- Green Canyon 339 2005 Midw ater Murphy n/a n/a n/a - - 2 1 -
Genghis Khan- Green Canyon 652 2007 Midw ater BHP Billiton n/a n/a n/a - 1 - - -
Gilder- Green Canyon 248 2004 Midw ater Shell n/a n/a n/a 1 - - - -
Gladden- Mississippi Canyon 800 2011 Midw ater New field Exploration n/a n/a n/a - 1 - - -
Hadrian South- Keathley Canyon 964 2013 Deepw ater ExxonMobil n/a n/a n/a 1 2 - - -
Isabela (Galapagos)- Mississippi Canyon 562 2012 Deepw ater BP n/a n/a n/a 1 - - - -
King- Mississippi Canyon 085-084 2002 Deepw ater Freeport-McMoRan n/a n/a n/a 1 - - - -
Llano- Garden Banks 385-386 2004 Midw ater Shell n/a n/a n/a 1 - - - -
Mad Dog 2012 Midw ater BP 37% 76% 5,302$ - 5 1 2 1
Mad Dog- Green Canyon 782 & 738 2005 Midw ater BP n/a n/a n/a 1 - - - -
Mandy- Mississippi Canyon 199 2012 Midw ater LLOG n/a n/a n/a - 1 - - -
Number of Wells

Summation of Development Drilling Demand: Base/Infield cont.
Field
Year on
Stream Water Depth Operator
Full
Cycle
IRR
%
Dev-
Forw ard
IRR %
CAPEX
$MM 2014E 2015E 2016E 2017E 2018E
Medusa- Mississippi Canyon 582 & 538 2003 Midw ater Murphy n/a n/a n/a 1 1 1 1 -
Neptune- Atw ater Valley 573-575 & 617-618 2008 Deepw ater BHP Billiton n/a n/a n/a - - 1 - -
Ozona- Garden Banks 515 2012 Midw ater Marathon Oil n/a n/a n/a - 1 - - -
Perdido 2009 Ultradeepw ater Shell 14% 24% 2,524$ 3 3 2 4 1
Phoenix (Phase 2)- Green Canyon 237-236 2010 Midw ater ERT n/a n/a n/a 1 - - - -
Pompano 1992 Midw ater Stone Energy 43% 43% 381$ - - - - 1
Pompano II - Mississippi Canyon 028 & 072 1996 Midw ater Stone Energy n/a n/a n/a - 1 - - -
Raton (Gemini North)- Mississippi Canyon 248 2008 Midw ater Noble Energy n/a n/a n/a - - 1 - -
Shenzi 2007 Midw ater BHP Billiton 42% 61% 1,239$ 2 - 1 - 1
Silvertip (Tobago North)- Alaminos Canyon 815 2011 Ultradeepw ater Shell n/a n/a n/a 1 1 1 1 -
South Diana- Alaminos Canyon 065 2004 Midw ater ExxonMobil n/a n/a n/a - 1 - - -
Tahiti 2007 Midw ater Chevron 30% 51% 2,536$ - - 1 - -
Tahiti- Green Canyon 640-641 & 596 2009 Midw ater Chevron n/a n/a n/a - 2 - - -
Thunder Horse 2006 Deepw ater BP 35% 61% 1,857$ 1 1 2 - 1
Thunder Horse- Mississippi Canyon 778 & 822 2008 Deepw ater BP n/a n/a n/a 4 1 1 1 4
Thunder Horse North- Mississippi Canyon 776 2009 Deepw ater BP n/a n/a n/a - 2 - - 1
Tobago- Alaminos Canyon 859 & 815 2011 Ultradeepw ater Shell n/a n/a n/a 1 1 1 1 -
Tonga- Green Canyon 727 2012 Midw ater Anadarko n/a n/a n/a 1 - - - -
West Tonga- Green Canyon 726 & 770 2013 Midw ater Anadarko n/a n/a n/a 4 - - - -
Who Dat- Mississippi Canyon 503-503 & 546-5472011 Midw ater LLOG n/a n/a n/a 3 1 - - -
Total 35 35 18 15 13
Number of Wells

Summation of Development Drilling Demand: New Source FID
at $70/bbl oil prices.Source: IHS Inc, Guggenheim Securities, LLC
Field
Year on
Full
Cycle
IRR
%
Dev-
Forw ard
IRR %
CAPEX
$MM 2014E 2015E 2016E 2017E 2018E
Big Bend 2014 FID Deepw ater Noble Energy 22% 27% 228$ 2 1 2 1 1
Big Bend (Rio Grande)- Mississippi Canyon 698 2017 FID Deepw ater Noble Energy n/a n/a n/a - - 2 2 1
Big Foot 2014 FID Deepw ater Chevron 8% 23% 1,444$ 3 3 2 - 2
Caesar/Tonga 2011 FID Midw ater Anadarko 21% 70% 508$ 3 4 1 3 1
Cardamom Deep 2012 FID Midw ater Shell 59% 69% 206$ 2 2 2 - 1
Cardona (Phase 2)- Mississippi Canyon 029 2015 FID Midw ater Stone Energy n/a n/a n/a 2 2 - - -
Condor 2009 FID Midw ater Deep Gulf Energy 52% 60% 171$ 1 - - - -
Dalmatian 2012 FID Deepw ater Murphy 34% 45% 61$ - 1 - - -
Gotcha (Great White West)- Alaminos Canyon 8562016 FID Ultradeepw ater Shell n/a n/a n/a 1 3 2 1 -
Gunflint 2014 FID Deepw ater Noble Energy 8% 19% 150$ 3 1 1 1 1
Gunflint- Mississippi Canyon 948 & 992 2017 FID Deepw ater Noble Energy n/a n/a n/a 2 3 2 2 1
Hadrian South 2012 FID Deepw ater ExxonMobil 10% 20% 134$ 1 2 - - -
Heidelberg 2014 FID Deepw ater Anadarko 16% 30% 897$ 3 1 4 3 2
Heidelberg- Green Canyon 859-860 & 903-4 2016 FID Deepw ater Anadarko n/a n/a n/a - 3 8 5 -
Jack- Walker Ridge 758-759 2019 FID Deepw ater Chevron n/a n/a n/a 4 - - - 4
Jack-St. Malo 2013 FID Deepw ater Chevron 13% 26% 1,811$ 4 3 2 2 2
Julia 2014 FID Deepw ater ExxonMobil 19% 42% 163$ 1 1 1 1 1
Kodiak- Mississippi Canyon 771 2015 FID Midw ater Deep Gulf Energy n/a n/a n/a 1 2 2 1 -
Lucius 2012 FID Deepw ater Anadarko 20% 30% 1,315$ 3 3 2 1 2
Marmalard (Delta House)- Mississippi Canyon 3002019 FID Deepw ater LLOG n/a n/a n/a 2 3 1 1 1
Mars B 2013 FID Midw ater Shell 33% 38% 1,087$ 7 5 3 3 2
Pyrenees 2013 FID Midw ater W&T Offshore 13% 13% 83$ 1 - - - 1
Son of Bluto II- Mississippi Canyon 431 2015 FID Deepw ater LLOG n/a n/a n/a 2 2 2 1 -
Stampede- Green Canyon 468 & 512 2018 FID Midw ater Hess n/a n/a n/a - - - 14 -
Stones 2014 FID Ultradeepw ater Shell 7% 15% 1,210$ 1 1 3 2 1
Tubular Bells 2014 FID Midw ater Hess 14% 44% 344$ 2 2 1 1 1
Tubular Bells- Mississippi Canyon 726-25 & 683 2018 FID Midw ater Hess n/a n/a n/a 1 - - 11 2
West Boreas- Mississippi Canyon 762 2016 FID Midw ater Shell n/a n/a n/a - 1 1 - -
Total 52 49 44 56 27
Number of Wells

Summation of Development Drilling Demand: New Source Non-FID and Totals
Field
Year on
Full
Cycle
IRR
%
Dev-
Forw ard
IRR %
CAPEX
$MM 2014E 2015E 2016E 2017E 2018E
Appomattox 2016 Non-FID Deepw ater Shell 10% 24% 2,915$ - - 3 4 3
Appomattox- Mississippi Canyon 391-392 & 348 2019 Non-FID Deepw ater Shell n/a n/a n/a - - - 4 10
Buckskin 2018 Non-FID Deepw ater Chevron 6% 16% 1,275$ - - - - 3
Conquest- Green Canyon 767 2016 Non-FID Deepw ater Anadarko n/a n/a n/a - 1 - - -
Dalmatian South 2014 Non-FID Deepw ater Murphy 15% 19% 154$ 1 1 - 1 1
Devils Island- Garden Banks 344 No 4 2019 Non-FID Midw ater New field Exploration n/a n/a n/a - - - - 2
Hadrian North 2017 Non-FID Ultradeepw ater ExxonMobil 11% 36% 1,959$ - - - 3 2
Holstein Subsea Tiebacks 2014 Non-FID Midw ater Plains E&P 33% 57% 216$ 3 2 2 2 1
Horn Mountain Subsea Tiebacks 2015 Non-FID Deepw ater Plains E&P 26% 47% 309$ 1 3 2 2 1
Kaskida 2018 Non-FID Deepw ater BP 10% 45% 2,254$ - - - - 3
Logan 2018 Non-FID Ultradeepw ater Statoil 11% 25% 727$ - - - - 3
Logan- Walker Ridge 969 & 929 2018 Non-FID Ultradeepw ater Statoil n/a n/a n/a - - - 3 4
Magellan- East Breaks 424 2017 Non-FID Midw ater Apache n/a n/a n/a - - 1 - -
Marlin Subsea Tiebacks 2014 Non-FID Midw ater Plains E&P 27% 54% 144$ 3 - 2 1 1
Mission Deep- Green Canyon 955 2019 Non-FID Deepw ater Anadarko n/a n/a n/a - - - - 2
Moccasin 2018 Non-FID Deepw ater Chevron 3% 18% 1,289$ - - - - 3
North Platte- Garden Banks 959 2019 Non-FID Midw ater Cobalt International n/a n/a n/a - - - - 2
Oudinot/Dionysis- Viosca Knoll 864 2015 Non-FID Midw ater W&T Offshore n/a n/a n/a - 1 - - -
Phobos- Sigsbee Escarpment 039 2018 Non-FID Ultradeepw ater Anadarko n/a n/a n/a - - - 4 2
Salsa West/Kung Pao- Garden Banks 171 2015 Non-FID Midw ater Hess n/a n/a n/a 1 - - - -
Shenandoah 2016 Non-FID Deepw ater Anadarko 23% 35% 2,367$ - - 3 7 7
Southw est Perseus- Visoca Knoll 830 2019 Non-FID Midw ater Chevron n/a n/a n/a - - - - 1
Stampede 2016 Non-FID Midw ater Hess 10% 37% 1,608$ - - 5 3 4
Sturgis- Atw ater Valley 182-183 2019 Non-FID Midw ater Chevron n/a n/a n/a - - - - 3
Thunder Bird- Mississippi Canyon 819 2015 Non-FID Deepw ater Murphy n/a n/a n/a 2 1 - - -
Tiger/Brontosaurus- Alaminos Canyon 775-774 2019 Non-FID Ultradeepw ater Chevron n/a n/a n/a - - - - 3
Trident- Alaminos Canyon 903-904 & 947 2018 Non-FID Ultradeepw ater Rocksource n/a n/a n/a - - - 2 2
Venus- Mississippi Canyon 2016 Non-FID Midw ater Shell n/a n/a n/a - 1 1 - -
Vicksburg 2016 Non-FID Deepw ater Shell 8% 19% 392$ - - 2 2 -
Vito 2016 Non-FID Midw ater Shell 10% 47% 1,061$ - - 4 2 2
Vito- Mississippi Canyon 984 & 940 2019 Non-FID Midw ater Shell n/a n/a n/a - - - 3 10
Who Dat 2012 Non-FID Midw ater LLOG 21% 26% 1,525$ 1 1 1 - -
Winter- Garden Banks 605 2016 Non-FID Midw ater New field Exploration n/a n/a n/a - 1 - - -
Total 12 12 26 43 75
Number of Wells

Appendix: Operator Breakdown

Shell: Estimated Development Demand & Expl./Dev. Contract Coverage
Shell‘s Current/Upcoming Development Projects
Shell‘s Current/Upcoming Rig Contracts
In recent presentations,
Shell emphasized the
importance of the Mars-B
and Cardamom projects,
with the former currently
preparing for start-up, and
the latter expected to start
up in the second half of
2014
Shell has no
outstanding tenders
in the GoM at this
time.
Rig Name Rig Type Well Name Well Type
Contract
Start Contract End
2014
Contract
Coverage
2015
Contract
Coverage
2016
Contract
Coverage
Atwood Condor UDW Europa- Miss Canyon Blk 934 #A8 Development/Unknown Aug-13 Nov-16 1.0 1.0 0.8
Deepwater Nautilus UDW Gilder- Green Canyon Blk 248 #GL8 Development Aug-12 Aug-17 1.0 1.0 1.0
Noble Bully I UDW West Boreas- Miss Canyon Blk 762>805 #WB1 Exploration/Development Mar-12 Apr-17 1.0 1.0 1.0
Noble Danny Adkins UDW Miss Canyon Blk 812 #1 Exploration Oct-09 Aug-14 0.6 - -
Noble Don Taylor UDW Princess- Miss Canyon Blk 809>810 #PI1ST1 Development Aug-13 Feb-19 1.0 1.0 1.0
Noble Globetrotter I UDW DeSoto Canyon Blk 843 #1, Miss Canyon Blk 525 #1 Exploration Apr-12 May-22 1.0 1.0 1.0
Noble Globetrotter II UDW USA Unknown Sep-13 Sep-23 1.0 1.0 1.0
Noble Jim Day UDW Walker Ridge Blk 508 #4 Exploration Jan-13 Jan-16 1.0 1.0 0.0
Noble Jim Thompson DW Cardamom- Garden Banks Blk 427 #DC2, #DC4 Development Mar-11 Dec-14 0.9 - -
Stena IceMAX DW Yucatan- Walker Ridge Blk 95>96 #1, #2 Exploration/ Appraisal Apr-12 Jul-17 1.0 1.0 1.0
Dev/Unknown 5.9 5.0 4.8
E&A 3.6 3.0 2.0
Total 9.5 8.0 6.9
Note: company totals
for rigs are rounded
up
Project
Water
Depth Sanctioned?
Year on
Stream
2014
Wells
2015
Wells
2016
Wells
2014
Implied
Rigs
2015
Implied
Rigs
2016
Implied
Rigs
Deimos- Mississippi Canyon 806 MW Base 2007 1 - - 0 - -
Europa- Mississippi Canyon 934-935 & 890 MW Base 2000 1 - - 0 - -
Gilder- Green Canyon 248 MW Base 2004 1 - - 0 - -
Llano- Garden Banks 385-386 MW Base 2004 1 - - 0 - -
Perdido UDW Base 2009 3 3 2 2 2 1
Silvertip (Tobago North)- Alaminos Canyon 815 UDW Base 2011 1 1 1 1 1 1
Tobago- Alaminos Canyon 859 & 815 UDW Base 2011 1 1 1 1 1 1
Cardamom Deep MW FID 2012 2 2 2 1 1 1
Gotcha (Great White West)- Alaminos Canyon 856 UDW FID 2016 1 3 2 1 2 1
Mars B MW FID 2013 7 5 3 2 2 1
Stones UDW FID 2014 1 1 3 1 1 2
West Boreas- Mississippi Canyon 762 MW FID 2016 - 1 1 - 0 0
Appomattox DW Non-FID 2016 - - 2 - - 1
Appomattox- Mississippi Canyon 391-392 & 348 DW Non-FID 2019 - - - - - -
Venus- Mississippi Canyon MW Non-FID 2016 - 1 1 - 0 0
Vicksburg DW Non-FID 2016 - - 2 - - 1
Vito MW Non-FID 2016 - - 4 - - 1
Vito- Mississippi Canyon 984 & 940 MW Non-FID 2019 - - - - - -
Base 9 5 4 4 3 2
FID 11 12 11 4 5 5
Non-FID - 1 9 - - 3
Total 20 18 24 8 8 10

BP: Estimated Development Demand & Expl./Dev. Contract Coverage
BP‘s Current/Upcoming Rig Contracts
All of the projects
listed were highlighted
in recent BP
presentations. On
Thunder Horse, BP
plans to have five rigs
operating in the field in
2014.
BP‘s Current/Upcoming Development Projects
BP has no
outstanding tenders
in the GoM at this
time.
Rig Name
Rig
Type Well Name Well Type
Contract
Start Contract End
2014
Contract
Coverage
2015
Contract
Coverage
2016
Contract
Coverage
Development Driller III DW Atlantis- Green Canyon Blk 743>699 #DC322BP2 Development Nov-09 Nov-16 1.0 1.0 0.9
Discoverer Enterprise UDW Thunderhorse- Miss Canyon Blk 777 #TB3 Development Jan-13 Oct-14 0.8 - -
ENSCO DS-3 UDW Ariel- Miss Canyon Blk 429- #A5 Development Aug-10 Jun-16 1.0 1.0 0.4
GSF Development Driller II DW Atlantis- Green Canyon Blk 743 # DC121ST1 Development Nov-08 Feb-14 0.1 - -
West Auriga UDW Thunderhorse- Miss Canyon Blk 777 #7 Development Apr-13 Aug-20 1.0 1.0 1.0
West Capricorn DW Keathley Canyon Blk 93 #1BP1/Green Canyon Blk 83 Exploration/Development May-12 Aug-17 1.0 1.0 1.0
West Sirius UDW Tiber- Keathley Canyon Blk 57 #1 Appraisal/Exploration Jul-12 Jul-14 0.6 - -
West Sirius UDW USA Unknown Jul-14 Jul-19 0.4 1.0 1.0
West Vela UDW Miss Canyon Blk 522 #F3 Exploration/Unknown Dec-13 Dec-20 1.0 1.0 1.0
E&A 0.6 - -
Total 7.0 6.0 5.3
Note: company totals
for rigs are rounded
up
Project
Water
Depth Sanctioned?
Year on
Stream
2014
Wells
2015
Wells
2016
Wells
2014
Implied
Rigs
2015
Implied
Rigs
2016
Implied
Rigs
Atlantis- Green Canyon 698-700 & 742-744 DW Base 2007 4 4 3 2 2 2
Atlantis North DW Base 2010 - 2 - - 1 -
Atlantis South DW Base 2005 - 1 - - 1 -
Isabela (Galapagos)- Mississippi Canyon 562 DW Base 2012 1 - - 1 - -
Mad Dog MW Base 2012 - 5 1 - 2 0
Mad Dog- Green Canyon 782 & 738 MW Base 2005 1 - - 0 - -
Thunder Horse DW Base 2006 1 1 2 1 1 1
Thunder Horse- Mississippi Canyon 778 & 822 DW Base 2008 4 1 1 2 1 1
Thunder Horse North- Mississippi Canyon 776 DW Base 2009 - 2 - - 1 -
Kaskida DW Non-FID 2018 - - - - - -
Base 11 16 7 5 7 3
FID - - - - - -
Non-FID - - - - - -
Total 11 16 7 5 7 3

Anadarko: Estimated Development Demand & Expl./Dev. Contract Coverage
Anadarko‘s Current/Upcoming Rig Contracts
Caesar/Tonga, Heidelberg, Lucius, and
Shenandoah seem to be high priority to
Anadarko, as implied by recent presentations. In
Caesar/Tonga, the 5th development well is
expected to be drilled in 2014. In Heidelberg, the
first development well is expected to be drilled in
2014, with first oil expected in mid-2016. Lucius is
on track to achieve first oil in 2H14.
Anadarko‘s Current/Upcoming Development Projects
Anadarko has no
outstanding tenders
in the GoM at this
time.
Rig Name
Rig
Contract
Start Contract End
2014
Contract
Coverage
2015
Contract
Coverage
2016
Contract
Coverage
Discoverer Spirit UDW Green Canyon Blk 683 > 727 #SS2BP2/Lloyd Bridge Blk 317 Exploration Aug-12 Jun-14 0.5 - -
ENSCO 8500 UDW Nansen- East Breaks Blk 646 #11 Exploration/Unknown Sep-13 Sep-14 0.7 - -
ENSCO 8505 UDW Caesar/Tonga- Green Canyon Blk 683 #SS1ST2 Development Jan-14 Feb-14 0.1 - -
ENSCO 8506 UDW Nansen- East Breaks Blk 645 #SS1 Exploration/Unknown Jan-13 Jul-15 1.0 0.6 -
Noble Bob Douglas UDW USA Unknown Nov-13 Dec-16 1.0 1.0 1.0
Ocean BlackHawk UDW USA Unknown May-14 May-19 0.6 1.0 1.0
Ocean BlackHornet UDW USA Unknown Jul-14 Jul-19 0.4 1.0 1.0
Rowan Resolute UDW USA Unknown Sep-14 Sep-17 0.3 1.0 1.0
E&A 0.5 - -
Total 4.6 4.6 4.0
Note: company
totals for rigs are
rounded up
Project
Water
Depth Sanctioned?
Year on
Stream
2014
Wells
2015
Wells
2016
Wells
2014
Implied
Rigs
2015
Implied
Rigs
2016
Implied
Rigs
Callisto (AVP)- Mississippi Canyon 876 UDW Base 2011 - 1 - - 1 -
Tonga- Green Canyon 727 MW Base 2012 1 - - 0 - -
West Tonga- Green Canyon 726 & 770 MW Base 2013 4 - - 1 - -
Caesar/Tonga MW FID 2011 3 4 1 1 1 0
Heidelberg DW FID 2014 3 1 4 2 1 2
Heidelberg- Green Canyon 859-860 & 903-4 DW FID 2016 - 3 8 - 2 4
Lucius DW FID 2012 3 3 2 2 2 1
Conquest- Green Canyon 767 DW Non-FID 2016 - 1 - - 1 -
Mission Deep- Green Canyon 955 DW Non-FID 2019 - - - - - -
Phobos- Sigsbee Escarpment 039 UDW Non-FID 2018 - - - - - -
Shenandoah DW Non-FID 2016 - - 3 - - 2
Base 5 1 - 2 1 -
FID 9 11 15 4 4 7
Non-FID - 1 3 - 1 2
Total 14 13 18 6 6 9

Chevron: Estimated Development Demand & Expl./Dev. Contract Coverage
Chevron‘s Current/Upcoming Rig Contracts
Chevron
emphasized the
Jack/St. Malo, Big
Foot, and Tubular
Bells projects
recently.
Chevron‘s Current/Upcoming Development Projects
Chevron has
no outstanding
tenders in the
GoM at this
time.
Rig Name
Rig
Contract
Start Contract End
2014
Contract
Coverage
2015
Contract
Coverage
2016
Contract
Coverage
Deepwater Conqueror UDW USA Unknown Dec-16 Dec-21 - - 0.0
Discoverer Clear Leader UDW Buckskin- Keathley Canyon Blk 829 #1BP3 Exploration/Unknown Jul-09 Aug-18 1.0 1.0 1.0
Discoverer India UDW Coronado- Walker Ridge Blk 143 #3 Exploration/Appraisal Jul-13 Sep-16 1.0 1.0 0.7
Discoverer Inspiration UDW Tahiti- Green Canyon Blk 640 #IS4 Exploration/Unknown Mar-10 Mar-20 1.0 1.0 1.0
Pacific Santa Ana UDW Garden Banks Blk 973 #1 Exploration/Unknown Mar-12 Apr-17 1.0 1.0 1.0
Pacific Sharav UDW USA Unknown Jul-14 Jun-19 0.5 1.0 1.0
E&A 1.0 1.0 0.7
Total 4.5 5.0 4.8
Note: company
totals for rigs are
rounded up
Project
Water
Depth Sanctioned?
Year on
Stream
2014
Wells
2015
Wells
2016
Wells
2014
Implied
Rigs
2015
Implied
Rigs
2016
Implied
Rigs
Tahiti MW Base 2007 - - 1 - - 0
Tahiti- Green Canyon 640-641 & 596 MW Base 2009 - 2 - - 1 -
Big Foot DW FID 2014 3 3 2 2 2 1
Jack- Walker Ridge 758-759 DW FID 2019 4 - - 2 - -
Jack-St. Malo DW FID 2013 4 3 2 2 2 1
Buckskin DW Non-FID 2018 - - - - - -
Moccasin DW Non-FID 2018 - - - - - -
Southwest Perseus- Visoca Knoll 830 MW Non-FID 2019 - - - - - -
Sturgis- Atwater Valley 182-183 MW Non-FID 2019 - - - - - -
Tiger/Brontosaurus- Alaminos Canyon 775-774 UDW Non-FID 2019 - - - - - -
Base - 2 1 - 1 1
FID 11 6 4 6 3 1
Non-FID - - - - - -
Total 11 8 5 6 4 2

BHP: Estimated Development Demand & Expl./Dev. Contract Coverage
BHP‘s Current/Upcoming Rig Contracts
BHP is planning two new
infill wells in Shenzi in
2014, according to a
recent presentation.
Neptune was highlighted
as well.
BHP‘s Current/Upcoming Development Projects
BHP has no
outstanding
tenders in the
GoM at this
time.
Rig Name
Rig
Contract
Start Contract End
2014
Contract
Coverage
2015
Contract
Coverage
2016
Contract
Coverage
Deepwater Invictus UDW USA Unknown Jun-14 Mar-17 0.6 1.0 1.0
GSF C.R. Luigs UDW Shenzi- Green Canyon Blk 653 #SB103 Development Sep-09 Apr-14 0.2 - -
GSF Development Driller I DW Neptune- Atwater Valley Blk 575 #SD1 Exploration Oct-12 Feb-14 0.2 - -
E&A 0.2 - -
Total 1.0 1.0 1.0
Note: company
totals for rigs are
rounded up
Project
Water
Depth Sanctioned?
Year on
Stream
2014
Wells
2015
Wells
2016
Wells
2014
Implied
Rigs
2015
Implied
Rigs
2016
Implied
Rigs
Genghis Khan- Green Canyon 652 MW Base 2007 - 1 - - 0 -
Neptune- Atwater Valley 573-575 & 617-618 DW Base 2008 - - 1 - - 1
Shenzi MW Base 2007 2 - 1 1 - 0
Base 2 1 2 1 - 1
FID - - - - - -
Non-FID - - - - - -
Total 2 1 2 1 0 1

Noble Energy: Estimated Development Demand & Expl./Dev. Contract Coverage
Noble Energy‘s Current/Upcoming Rig Contracts
Big Bend and Gunflint,
both FID, were
highlighted in Noble‘s
recent investor
presentations, with the
former expecting first
oil in late 2015.
Noble Energy‘s Current/Upcoming Development Projects
Noble Energy has
no outstanding
tenders in the GoM
at this time.
Project
Water
Depth Sanctioned?
Year on
Stream
2014
Wells
2015
Wells
2016
Wells
2014
Implied
Rigs
2015
Implied
Rigs
2016
Implied
Rigs
Raton (Gemini North)- Mississippi Canyon 248 MW Base 2008 - - 1 - - 0
Big Bend DW FID 2014 2 1 2 1 1 1
Big Bend (Rio Grande)- Mississippi Canyon 698 DW FID 2017 - - 2 - - 1
Gunflint DW FID 2014 3 1 1 2 1 1
Gunflint- Mississippi Canyon 948 & 992 DW FID 2017 2 3 2 1 2 1
Base - - 1 - - -
FID 7 5 7 4 3 4
Non-FID - - - - - -
Total 7 5 8 4 3 4
Rig Name
Rig
Contract
Start Contract End
2014
Contract
Coverage
2015
Contract
Coverage
2016
Contract
Coverage
Atwood Advantage UDW Europa- Miss Canyon Blk 934 Development/Unknown Dec-13 Mar-17 1.0 1.0 1.0
ENSCO 8501 UDW West Boreas- Miss Canyon Blk 762>805 #WB1 Exploration Aug-13 Aug-14 0.6 - -
ENSCO 8505 UDW Miss Canyon Blk 812 #1 Unknown Feb-14 Jul-14 0.6 - -
E&A 0.6 - -
Total 2.1 1.0 1.0
Note:
company
totals for
rigs are
rounded up

Stone Energy: Estimated Development Demand & Expl./Dev. Contract Coverage
Stone Energy‘s Current/Upcoming Rig Contracts
Pompano and
Cardona
appeared as
major projects in
Stone‘s recent
presentations,
with the former
expected to
reach first
production in
1Q15.
Stone Energy‘s Current/Upcoming Development Projects
Stone Energy has
no outstanding
tenders in the GoM
at this time.
Project Water Depth Sanctioned?
Year on
Stream
2014
Wells
2015
Wells
2016
Wells
2014
Implied
Rigs
2015
Implied
Rigs
2016
Implied
Rigs
Pompano MW Base 1992 - - - - - -
Pompano II - Mississippi Canyon 028 & 072 MW Base 1996 - 1 - - 0 -
Cardona (Phase 2)- Mississippi Canyon 029 MW FID 2015 2 2 - 1 1 -
Base - 1 - - - -
FID 2 2 - 1 1 -
Non-FID - - - - - -
Total 2 3 - 1 1 -
Rig Name
Rig
Contract
Start Contract End
2014
Contract
Coverage
2015
Contract
Coverage
2016
Contract
Coverage
ENSCO 8502 UDW Cardona- Miss Canyon Blk 29 #4 Development Jan-14 Jul-14 0.6 - -
Ocean Victory DW Miss Canyon Blk 26 #1 Exploration Nov-13 Feb-14 0.1 - -
Dev/Unknown 0.6 - -
E&A 0.1 - -
Total 0.7 - -
Note:
company
totals for
rigs are
rounded up

Apache: Estimated Development Demand & Expl./Dev. Contract Coverage
Apache‘s Current/Upcoming Rig Contracts
Apache‘s Current/Upcoming Development Projects
Apache has no
outstanding tenders
in the GoM at this
time.
Project Water Depth Sanctioned?
Year on
Stream
2014
Wells
2015
Wells
2016
Wells
2014
Implied
Rigs
2015
Implied
Rigs
2016
Implied
Rigs
Magellan- East Breaks 424 MW Non-FID 2017 - - 1 - - 1
Base - - - - - -
FID - - - - - -
Non-FID - - 1 - - 1
Total - - 1 - - 1
Rig Name
Rig
Contract
Start Contract End
2014
Contract
Coverage
2015
Contract
Coverage
2016
Contract
Coverage
ENSCO 8505 UDW Miss Canyon Blk 983 #1 Exploration Sep-13 Jan-14 0.0 - -
Ocean Onyx DW East Breaks Blk 424/Garden Banks Blk 169 > 213 #1 Unknown Jan-14 Jan-15 1.0 0.0 -
Dev/Unknown 1.0 0.0 -
E&A 0.0 - -
Total 1.0 0.0 -
Note:
company
totals for
rigs are
rounded up

Cobalt: Estimated Development Demand & Expl./Dev. Contract Coverage
Cobalt‘s Current/Upcoming Rig Contracts
In North Platte (60%
Cobalt ownership),
processing of
appraisal/exploration
permitting is under
way.
Cobalt‘s Current/Upcoming Development Projects
Cobalt has no
outstanding tenders
in the GoM at this
time.
Project
Water
Depth Sanctioned?
Year on
Stream
2014
Wells
2015
Wells
2016
Wells
2014
Implied
Rigs
2015
Implied
Rigs
2016
Implied
Rigs
North Platte- Garden Banks 959 MW Non-FID 2019 - - - - - -
Contract
Start Contract End
2014
Contract
Coverage
2015
Contract
Coverage
2016
Contract
Coverage
ENSCO 8503 UDW Keathley Canyon Blk 163 #1 Exploration/Unknown Dec-11 Apr-14 0.2 - -
Rowan Reliance UDW North Platte- Garden Banks Blk 959 Exploration/Appraisal Jan-15 Jan-18 - 0.9 1.0
Dev/Unknown 0.2 - -
E&A - 0.9 1.0
Total 0.2 0.9 1.0

Eni: Estimated Development Demand & Expl./Dev. Contract Coverage
Eni‘s Current/Upcoming Rig Contracts
Eni has submitted a tender
for a floater in Walker Ridge
Block 719 for exploration
work; IHS currently
considers the demand
―probable‖
Eni‘s Current/Upcoming Development Projects
Project
Water
Depth Sanctioned?
Year on
Stream
2014
Wells
2015
Wells
2016
Wells
2014
Implied
Rigs
2015
Implied
Rigs
2016
Implied
Rigs
Appaloosa- Mississippi Canyon 460-459 MW Base 2011 - 1 - - 1 -
Base - 1 - - 1 -
FID - - - - - -
Non-FID - - - - - -
Total - 1 - - 1 -
Contract
Start
Contract
End
2014
Contract
Coverage
2015
Contract
Coverage
2016
Contract
Coverage
Deepwater Pathfinder UDW King Kong- Green Canyon Blk 473/Longhorn- Miss Canyon Blk 546 Exploration/Unknown Mar-10 Apr-15 1.0 0.3 -
Note:
company
totals for
rigs are
rounded up

ExxonMobil: Estimated Development Demand & Expl./Dev. Contract Coverage
ExxonMobil‘s Current/Upcoming Rig Contracts
Exxon emphasized the
importance of the
Hadrian South and
Julia projects at its
recent analyst day.
ExxonMobil‘s Current/Upcoming Development Projects
ExxonMobil has no
outstanding tenders
in the GoM at this
time.
Project
Water
Depth Sanctioned?
Year on
Stream
2014
Wells
2015
Wells
2016
Wells
2014
Implied
Rigs
2015
Implied
Rigs
2016
Implied
Rigs
Hadrian South- Keathley Canyon 964 DW Base 2013 1 2 - 1 1 -
South Diana- Alaminos Canyon 065 MW Base 2004 - 1 - - 0 -
Hadrian South DW FID 2012 1 2 - 1 1 -
Julia DW FID 2014 1 1 1 1 1 1
Base 1 3 - 1 1 -
FID 2 3 1 1 2 1
Non-FID - - - - - -
Total 3 6 1 2 3 1
Rig Name
Rig
Contract
Start Contract End
2014
Contract
Coverage
2015
Contract
Coverage
2016
Contract
Coverage
Deepwater Champion UDW Hadrian South- Keathley Canyon Blk 964 #3/Julia-Walker Ridge Development May-11 Nov-15 1.0 0.8 -
Maersk Viking UDW USA Exploration/Unknown Feb-14 May-17 0.9 1.0 1.0
E&A - - -
Total 1.9 1.8 1.0
Note:
company
totals for
rigs are
rounded up

Hess: Estimated Development Demand & Expl./Dev. Contract Coverage
Hess‘s Current/Upcoming Rig Contracts
Hess expects to have a sanction
decision on Stampede in the
second half of 2014; Tubular Bells
is a very high priority asset,
according to recent presentations.
If Stampede does reach FID, it
could provide meaningful upside to
Hess‘s rig demand.
In addition to the above contract, Hess has submitted two
tenders, one for 3Q15 (exploration), with a max duration of 0.6
rig years, in Green Canyon Block 287, and one for 1Q16
(development), with a max duration of 4 rig years, in Green
Canyon Blocks 468 and 512 (Stampede). These indications of
interest are marked ―probable‖ by IHS.
Hess‘ s Current/Upcoming Development Projects
Rig Name
Rig
Contract
Start Contract End
2014
Contract
Coverage
2015
Contract
Coverage
2016
Contract
Coverage
Stena Forth DW Tubular Bells- Miss Canyon Blk 725>724 #1ST1BP1 Development/Unknown Feb-12 Nov-14 0.9 - -
Dev/Unknown 0.9 - -
E&A - - -
Total 0.9 - -
Note:
company
totals for
rigs are
rounded up
Project
Water
Depth Sanctioned?
Year on
Stream
2014
Wells
2015
Wells
2016
Wells
2014
Implied
Rigs
2015
Implied
Rigs
2016
Implied
Rigs
Stampede- Green Canyon 468 & 512 MW FID 2018 - - - - - -
Tubular Bells MW FID 2014 2 2 1 1 1 0
Tubular Bells- Mississippi Canyon 726-25 & 683 MW FID 2018 1 - - 0 - -
Salsa West/Kung Pao- Garden Banks 171 MW Non-FID 2015 - - - - - -
Stampede MW Non-FID 2016 - - 5 - - 2
Base - - - - - -
FID 3 2 1 1 1 -
Non-FID - - 5 - - 2
Total 3 2 6 1 1 2

Murphy: Estimated Development Demand & Expl./Dev. Contract Coverage
Murphy‘s Current/Upcoming Rig Contracts
Tie-ins are
ongoing in
Dalmatian.
Murphy‘s Current/Upcoming Development Projects
Murphy has no
outstanding tenders
in the GoM at this
time.
Rig Name
Rig
Contract
Start Contract End
2014
Contract
Coverage
2015
Contract
Coverage
2016
Contract
Coverage
Discoverer Deep Seas UDW Dalmatian- DeSoto Blk 4 #1, 47>48 Exploration/Unknown Dec-13 Nov-16 1.0 1.0 0.9
E&A - - -
Total 1.0 1.0 0.9
Note:
company
totals for
rigs are
rounded up
Project
Water
Depth Sanctioned?
Year on
Stream
2014
Wells
2015
Wells
2016
Wells
2014
Implied
Rigs
2015
Implied
Rigs
2016
Implied
Rigs
Front Runner South- Green Canyon 339 MW Base 2005 - - 2 - - 1
Medusa- Mississippi Canyon 582 & 538 MW Base 2003 1 1 1 0 0 0
Dalmatian DW FID 2012 - 1 - - 1 -
Dalmatian South DW Non-FID 2014 1 - - 1 - -
Thunder Bird- Mississippi Canyon 819 DW Non-FID 2015 1 1 - 1 1 -
Base 1 1 3 - - 1
FID - 1 - - - -
Non-FID 2 1 - 1 1 -
Total 3 3 3 1 1 1

Statoil: Estimated Development Demand & Expl./Dev. Contract Coverage
Statoil‘s Current/Upcoming Rig Contracts
In addition to the below contracts, Statoil has a firm tender in
place, with a 2Q14 start date, for up to 4 rig years in the Gulf of
Mexico, for exploration work.
Statoil‘s Current/Upcoming Development Projects
Rig Name
Rig
Contract
Start Contract End
2014
Contract
Coverage
2015
Contract
Coverage
2016
Contract
Coverage
Discoverer Americas UDW USA Unknown Mar-14 May-16 0.8 1.0 0.3
Maersk Developer UDW DeSoto Canyon Blk 231 #1/Miss Canyon Blk 718 #1 Exploration/Unknown Nov-13 Nov-15 1.0 0.9 -
E&A - - -
Total 1.8 1.9 0.3
Project
Water
Depth Sanctioned?
Year on
Stream
2014
Wells
2015
Wells
2016
Wells
2014
Implied
Rigs
2015
Implied
Rigs
2016
Implied
Rigs
Logan UDW Non-FID 2018 - - - - - -
Logan- Walker Ridge 969 & 929 UDW Non-FID 2018 - - - - - -
Note:
company
totals for
rigs are
rounded up

Marathon: Estimated Development Demand & Expl./Dev. Contract Coverage
Marathon‘s Current/Upcoming Rig Contracts
In addition to the below contracts, Marathon has a tender,
starting in 2Q14 (exploration), in Walker Ridge 578/579, with a
max duration of 1.9 rig years. It is currently marked as ―possible‖
in the IHS Database
Marathon‘s Current/Upcoming Development Projects
Project
Water
Depth Sanctioned?
Year on
Stream
2014
Wells
2015
Wells
2016
Wells
2014
Implied
Rigs
2015
Implied
Rigs
2016
Implied
Rigs
Ozona- Garden Banks 515 MW Base 2012 - 1 - - 1 -
Base - 1 - - 1 -
FID - - - - - -
Non-FID - - - - - -
Total - 1 - - 1 -
Rig Name
Rig
Contract
Start Contract End
2014
Contract
Coverage
2015
Contract
Coverage
2016
Contract
Coverage
ENSCO 8503 UDW USA Unknown Apr-14 May-14 0.4 - -
Maersk Valiant UDW USA Exploration/Unknown Apr-14 Dec-16 0.7 1.0 1.0
E&A - - -
Total 1.1 1.0 1.0
Note:
company
totals for
rigs are
rounded up

Appendix: Gulf of Mexico Regional Detail

Efficiency Gains Impact Well/Rig Ratio
Note: well count excludes shallow water
Implied Development Well/Rig Ratio, GoM Floaters
2.8 x
3.0 x
3.0 x
3.3 x
1.9 x
1.8 x
2.2 x
2.0 x
3.0 x
26
22
21
23
24
32
29
33
31
1.5 x
1.7 x
1.9 x
2.1 x
2.3 x
2.5 x
2.7 x
2.9 x
3.1 x
3.3 x
3.5 x
20
25
30
35
2005 2006 2007 2008 2009 2010 2011 2012 2013
ImpliedWell/RigRatio
Rigs(Development+Unknown)
Well/Rig Ratio Development Rigs
We take historical annual well counts, and then divide that number
by the quarterly average number of floaters working on
development (or unknown) wells, to arrive at the well/rig ratio.
Historically, the majority of unknown well types have turned out to
be development wells. Therefore, we include them in our analysis
of development well/rig ratios.

Contract Coverage Strong Through 2014, with Some Changes in Composition
Contract Starts and Contract Roll-Offs
Contract Starts Contract Ends
Maersk Viking Ocean Saratoga
Sevan Louisiana GSF Grand Banks
Maersk Valiant
Discoverer Americas
Titanium Explorer
Ocean Blackhawk GSF Development Driller I
Deepwater Invictus GSF Development Driller II
Ocean Victory
Noble Driller
Noble Danny Adkins
Pacific Sharav GSF C.R. Luigs
Ocean Blackhornet Discoverer Spirit
Noble Sam Croft ENSCO 8503
Rowan Resolute ENSCO 8501
Noble Bob Douglas ENSCO 8505
West Neptune
Noble Globetrotter II ENSCO 8500
4Q14
1Q14
2Q14
3Q14
# Rig Name Operator
1 Atwood Advantage Noble Energy
2 Atwood Condor Shell
3 Deepwater Champion ExxonMobil
4 Deepwater Nautilus Shell
5 Deepwater Pathfinder Eni
6 Development Driller III BP
7 Discoverer Clear Leader Chevron
8 Discoverer Deep Seas Murphy
9 Discoverer Enterprise BP
10 Discoverer India Chevron
11 Discoverer Inspiration Chevron
12 Discoverer Spirit Anadarko
13 ENSCO 8500 Anadarko
14 ENSCO 8501 Noble Energy
15 ENSCO 8502 Stone Energy
16 ENSCO 8503 Cobalt Intl
19 ENSCO DS-3 BP
20 ENSCO DS-5 Repsol
21 GSF C.R. Luigs BHP Billiton
22 GSF Development Driller I BHP Billiton
23 GSF Development Driller II BP
24 GSF Grand Banks Husky Oil Operations
25 Maersk Developer Statoil
26 Noble Amos Runner LLOG
27 Noble Bully I Shell
28 Noble Danny Adkins Shell
29 Noble Don Taylor Shell
30 Noble Driller Marubeni
31 Noble Globetrotter I Shell
32 Noble Jim Day Shell
33 Noble Jim Thompson Shell
34 Ocean Onyx Apache
35 Ocean Saratoga LLOG
36 Ocean Victory Stone Energy
37 Pacific Santa Ana Chevron
38 Stena Forth Hess
39 Stena IceMAX Shell
40 West Auriga BP
41 West Capricorn BP
42 West Sirius BP
43 West Vela BP
Currently Contracted
# Rig Name Operator
4 Deepwater Invictus BHP Billiton
8 Discoverer Americas Statoil
16 ENSCO DS-3 BP
19 Maersk Valiant Marathon
20 Maersk Viking ExxonMobil
22 Noble Bob Douglas Anadarko
26 Noble Globetrotter II Shell
29 Noble Sam Croft Freeport McMoran
30 Ocean BlackHawk Anadarko
31 Ocean BlackHornet Anadarko
34 Pacific Sharav Chevron
35 Rowan Resolute Anadarko
36 Sevan Louisiana LLOG
37 Stena Forth Hess
39 Titanium Explorer Ophir Energy
40 West Auriga BP
42 West Neptune LLOG
43 West Sirius BP
44 West Vela BP
Contracted at End of 2014

Tenders Offer Potential Upside to Rig Demand, Pending More Visibility
GoM Floater Projections
GoM Jackup Projections
Numerous mentions of
demand not represented by
direct negotiations, may add
to current tender market
demand.
Source: IHS Inc, Infield Systems, Guggenheim Securities, LLC
Quarter Operator Status Workmode
Rig
Years Location
2Q14 Statoil Tender Exploration 4.0
1Q14 Eni Probable Exploration 0.3 Walker Ridge Block 719
3Q15 Hess Probable Exploration 0.6 Green Canyon Block 287
1Q16 Hess Probable Development 4.0 Green Canyon Blocks 468, 512
1Q14 Marathon Possible Exploration 1.9 Walker Ridge 578/579
3Q15 Walter Oil & GasPossible Development 0.2 Ewing Bank Block 790
Quarter Operator Status Workmode
Rig
Years Location
1Q14 Rooster EnergyProbable Development 0.1 South Timbalier Block 112
1Q14 Contango Oil & GasProbable Exploration 0.1 Eugene Island Block 23
1Q14 Contango Oil & GasProbable Exploration 0.1 Ship Shoal Blocks 52/59
1Q14 GoMex EnergyProbable Development 0.5 Vermilion Block 282/East Cam Block 272
1Q14 Talos EnergyProbable Exploration 0.2 ST 196, EI 192, EI 209
1Q14 AnaTexas Possible Workover 0.1 Brazos Block 446L
1Q14 Saratoga ResourcesPossible Development 0.2 various

# Rig Name Operator 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 Beyond
1 GSF C.R. Luigs BHP Billiton
2 Ocean Victory Stone Energy
3 Ocean Saratoga LLOG
4 GSF Development Driller II BP
5 ENSCO 8503 Cobalt Intl
6 Discoverer Spirit Anadarko
7 Noble Driller Marubeni
9 ENSCO 8501 Noble Energy
10 Noble Danny Adkins Shell
11 GSF Development Driller I BHP Billiton
17 Stena Forth Hess
20 GSF Grand Banks Husky Oil Operations
25 ENSCO DS-3 BP
38 West Sirius BP
40 West Auriga BP
42 West Vela BP
Rig Attrition: GoM Floaters Rolling Off Contract
Note: grey, italicized font indicates that we
believe the rig has a higher probability to retire by
2015 because of its age and specifications.
.
Out of the 22 floaters rolling off contract by 2015,
we see 1 deepwater rig and 2 midwater rigs as
ripe for retirement.

Recent GoM Fixtures Remain within Recent Ranges
300,000
350,000
400,000
450,000
500,000
550,000
600,000
650,000
Jan-12 Apr-12 Jul-12 Oct-12 Feb-13 May-13 Aug-13 Dec-13
$/Day
UDW Dayrate DW Dayrate
ENSCO 8500, 2008, 6G (1 year)
Noble Amos Runner, 1999, 4G (2 years)
ENSCO 8501, 2009, 6G (1 year)
Sevan Louisiana, 2013, 6G (3 years)
ENSCO 8502, 2010, 6G (7 mo.)
Ocean Victory, 1972, 4G (3 mo.)
Ocean Victory, 1972, 4G (2 mo.)
Noble Sam Croft, 2014, DS (3 years)
Noble Tom Madden, 2014, DS (3 years)
West Neptune, 2014, DS (3 years)
Atwood Condor, 2012,, 6G (11 mo.)
ENSCO 8502, 2010, 6G (4 mo.)
Discoverer Clear Leader, 2009,
DS (4 years)
Discoverer Inspiration, 2009, DS (5 years)
Discoverer Enterprise, 1999, DS (9 mo.)
Deepwater Conquerer, 2016, DS (5 years)
GSF C.R. Luigs, 2000, DS (2 mo.)
ENSCO 8503, 2010, 6G (2 mo.)
ENSCO DS-9, 2014, DS (3 years)
Discoverer India, 2010, DS (3 years)
ENSCO 8502, 2010, 6G (2 mo.)
Notation: Rig Name, Year Built, Rig Type, Contract Duration

10
10
9
7
4 4
6
4
5
12
8
12
11
8
3 3
4
6 6
7
8
7
10
12
11
15
40
50
60
70
80
90
100
110
120
130
140
-
2
4
6
8
10
12
14
16
4Q06
1Q07
2Q07
3Q07
4Q07
1Q08
2Q08
3Q08
4Q08
1Q09
2Q09
3Q09
4Q09
1Q10
2Q10
3Q10
4Q10
1Q11
2Q11
3Q11
4Q11
1Q12
2Q12
3Q12
4Q12
1Q13
2Q13
3Q13
4Q13
WTICrudePrice($/bbl)
NumberofRigQuarters
Development LLS Crude
History of Development & Exploration Activity vs. LLS
Note: If a rig is working on an exploration well for a full quarter,
it counts as 1 rig quarter; if it is working for half the quarter, it
counts as 0.5 rig quarters, etc.
Floaters Working in Development in the GoM Floaters Working in E&A in the GoM
21
22 23
21
22
25
23
20 20
14
16
17
13
0
2 4
11
14
17
20
24
23
24
20
40
50
60
70
80
90
100
110
120
130
140
-
5
10
15
20
25
4Q06
1Q07
2Q07
3Q07
4Q07
1Q08
2Q08
3Q08
4Q08
1Q09
2Q09
3Q09
4Q09
1Q10
2Q10
3Q10
4Q10
1Q11
2Q11
3Q11
4Q11
1Q12
2Q12
3Q12
4Q12
1Q13
2Q13
3Q13
4Q13
WTICrudePrice($/bbl)
NumberofRigQuarters
E&A LLS Crude

91%
76%
59%
66%
75%
82%
83%
86%
92%
91%
80%
79%
74%
67%
73%
81%
64%
41%
67%
72%
65%
74%
67%
76%
72%
88%
80%
40%
50%
60%
70%
80%
90%
Marketed Util % Average 2001-2013 Our Assumption (92%)
86%
90%
92%
79%
75%
84%
78%
87%
84%
75%
86%
88%
81%
88%
86%
91%
88%
79%
68%
77%
83%
73%
87%
69%
20%
30%
52%
68%
77%
66%
84%
83%
80%
15%
25%
35%
45%
55%
65%
75%
85%
95%
Marketed Util % Average 2001-2013 Our Assumption (92%)
Utilization: Historical Floater Utilization Makes Our Forecast Very Conservative
GoM Working Utilization- Floaters
Note:―Working‖ utilization includes only time drilling, so it dips
when there is rig downtime
In the aftermath of the Macondo
incident, many rigs remained under
contract but were not working because
of the drilling moratorium, thus creating
a big difference between ―contracted‖
and ―working‖ utilization.
The 8% downtime
assumption we use in
our rig supply/demand
model remains
generous compared to
historical numbers.
GoM Working Utilization- Jackups

77%
65%
49%
54%
64%
61%
70%
64%
73%
67%
51%
64%
58%
58%
42%
1%
7%
16%
34%
54%
63% 63%
60%
64%
51%
0%
10%
20%
30%
40%
50%
60%
70%
80%
1Q05
2Q05
3Q05
4Q05
1Q06
2Q06
3Q06
4Q06
1Q07
2Q07
3Q07
4Q07
1Q08
2Q08
3Q08
4Q08
1Q09
2Q09
3Q09
4Q09
1Q10
2Q10
3Q10
4Q10
1Q11
2Q11
3Q11
4Q11
1Q12
2Q12
3Q12
4Q12
1Q13
2Q13
3Q13
4Q13
%ofRigsWorkinginE&A
Exploration Rig Growth Dependent on Rise in Overall Active Fleet
Note: If a rig is working on an exploration well for a full
quarter, it counts as 1 rig quarter; if it is working for half
the quarter, it counts as 0.5 rig quarters, etc.
Note: ―active‖ status is either acceptance testing, hot
stacked, warm stacked, in port, accommodation, moving
to location, yard, standby, drilling, support, or en route.
History of Floaters Working in Exploration & Appraisal vs. Total Working Fleet, GoM
E&A contribution to the working total in
GoM unlikely to see post-Macondo
lows again.

GoM Contracted Rig Snapshot
Transocean,
14, 32%
Noble, 8,
19%
Ensco, 8,
19%
Seadrill, 4,
9%
Diamond
Offshore, 3,
7%
Stena, 2, 5%
Atwood, 2,
5%
Pacific
Drilling, 1, 2%
Maersk
Drilling, 1, 2%
GoM Contracted Floater Snapshot by Manager
Hercules
Offshore, 16,
49%
Ensco, 8,
24%
Rowan, 4,
12%
Spartan
Offshore
Drilling, 3, 9%
Noble, 1, 3% Diamond
Offshore, 1,
3%
GoM Contracted Jackup Snapshot by Manager
EPL Oil &
Gas Inc, 5,
15% Fieldwood
Energy, 4,
12%
Chevron, 4,
12%
Arena
Energy, 3,
9%
Energy
XXI, 3, 9%
Walter Oil &
Gas, 2, 6%
Tana
Exploration,
2, 6%
EnVen
Energy
Ventures, 2,
6%
Other, 8, 25%
GoM Contracted Jackup Snapshot by Operator
Shell, 9, 21%
BP, 8, 18%
Anadarko,
4, 9%
Chevron,
4, 9%
LLOG,
2, 5%
Stone
Energy,
2, 5%
Noble
Energy, 2,
5%
BHP Billiton,
2, 5%
Other, 10,
23%
GoM Contracted Floater Snapshot by Operator
―Other‖ includes
Apache, Cobalt,
Eni, ExxonMobil,
Hess, Husky,
Marubeni,
Murphy, Repsol
and Statoil.
―Other‖ includes
ANKOR, Apache,
Contango,
Freeport, GoMex,
PEMEX, Stone,
and Talos

Diamond
Offshore
34%
Ensco
29%
Seadrill
16%
Other
21%
Chevron
15%
Anadarko
14%
Eni
13%
BHP
Billiton
7%
Petrobras
6%
Nexen
5%
Noble Energy
5%
Hess
5%
Other
30%
-
5
10
15
20
25
4Q06
1Q07
2Q07
3Q07
4Q07
1Q08
2Q08
3Q08
4Q08
1Q09
2Q09
3Q09
4Q09
1Q10
2Q10
3Q10
4Q10
1Q11
2Q11
3Q11
4Q11
1Q12
2Q12
3Q12
4Q12
1Q13
2Q13
3Q13
4Q13
NumberofRigQuarters
Other BP Shell
Unknown Well Types Likely Lean Toward Development
Unknown Floater Well Type by Operator
Unknown Floater Well Type by Manager
Breakdown of ―Other Managers‖
Breakdown of ―Other Operators‖
-
5
10
15
20
25
4Q06
1Q07
2Q07
3Q07
4Q07
1Q08
2Q08
3Q08
4Q08
1Q09
2Q09
3Q09
4Q09
1Q10
2Q10
3Q10
4Q10
1Q11
2Q11
3Q11
4Q11
1Q12
2Q12
3Q12
4Q12
1Q13
2Q13
3Q13
4Q13
NumberofRigQuarters
Transocean Other Noble
Macondo -
driven
uncertainty
Macondo -
driven
uncertainty

Gulf of Mexico Jackup Market

Floaters vs. Jackups in the Gulf of Mexico
Floaters vs. Jackups in the GoM Jackups by Class in the GoM
-
5
10
15
20
25
30
35
4Q06
1Q07
2Q07
3Q07
4Q07
1Q08
2Q08
3Q08
4Q08
1Q09
2Q09
3Q09
4Q09
1Q10
2Q10
3Q10
4Q10
1Q11
2Q11
3Q11
4Q11
1Q12
2Q12
3Q12
4Q12
1Q13
2Q13
3Q13
4Q13
NumberofRigQuarters
Commodity Standard Premium
31 32 32 32 32 32 32
29 28 27 28
31
33
28
26
25
27
25 26 27
31
37 38 38 38 38
39
62
61
54
53
46
50
58 59
53
37
26
16
22
31
37
30 29 30
34
29
32
35 34
30 29
32 34 35 33
10
20
30
40
50
60
4Q06
1Q07
2Q07
3Q07
4Q07
1Q08
2Q08
3Q08
4Q08
1Q09
2Q09
3Q09
4Q09
1Q10
2Q10
3Q10
4Q10
1Q11
2Q11
3Q11
4Q11
1Q12
2Q12
3Q12
4Q12
1Q13
2Q13
3Q13
4Q13
NumberofRigQuarters
Floater Total Jackup Total

35
24
17
8
1
1
1
-
3
4
1
-
5
10
15
20
25
30
35
40
45
1Q14 2Q14 3Q14 4Q14RigQuarters
Total Adjusted Tenders Raw Tenders
Jackup Market Offers Less Visibility, Dominated by Lower Spec. Rigs
Future Contracted Jackups in the GoM Potential Incremental Jackup Tender Demand
Tenders for rigs represent potential upside on top of currently contracted
demand. For demand marked ―probable‖ or ―possible,‖ we probability-
weight the numbers to account for risks of project delays or cancellations.
The light orange portion of the bars show the implied total rig demand if all
tenders converted into demand as scheduled.
21 21
15
9
3
5 5
3
3
1
7 9
6
5
4
33
35
24
17
8
0
5
10
15
20
25
30
35
40
Current 1Q14 2Q14 3Q14 4Q14
ContractedRigQuarters
<300 ft 300 ft Premium
Note: tenders are cumulative; i.e., if a new tender is for 1 year,
it will appear as 1 rig throughout that year

Rig Attrition: Jackup Contract Rolls Challenge Rigs
Note: grey font indicates that
we believe the rig is likely to
retire by 2015 because of its
age and specifications.
.
# Rig Name
Build
Year
Drilling
Depth
(ft) Market Category Manager Operator 1Q14 2Q14 3Q14 4Q14 1Q15
1 Hercules 150 1979 20,000 JU <250-IC Hercules Offshore EPL Oil & Gas Inc
2 Hercules 209 1981 20,000 JU 200-MC Hercules Offshore EnVen Energy Ventures
3 ENSCO 75 1999 30,000 JU 361-400-IC Ensco Fieldwood Energy
4 Hercules 214 1982 20,000 JU 200-MC Hercules Offshore Apache
5 ENSCO 90 1982 20,000 JU 250-IC Ensco ANKOR Energy
6 Spartan 202 1969 20,000 JU <250-MS Spartan Offshore Drilling Contango Oil & Gas
7 Ocean King 1973 25,000 JU 300-IC Diamond Offshore Energy XXI
8 Hercules 200 1979 20,000 JU 200-MC Hercules Offshore Walter Oil & Gas
9 Rowan Louisiana 1975 25,000 JU >300-IS Rowan Northstar Offshore
10 Rowan Gorilla IV 1986 35,000 JU >400-IC Rowan Walter Oil & Gas
11 Spartan 303 1974 25,000 JU 250-MS Spartan Offshore Drilling EPL Oil & Gas Inc
12 Hercules 253 1982 20,000 JU 250-MS Hercules Offshore Tana Exploration
13 Hercules 212 1982 20,000 JU 200-MC Hercules Offshore Talos Energy
14 ENSCO 86 1981 30,000 JU 250-IC Ensco Fieldwood Energy
15 Hercules 251 1978 20,000 JU 250-MS Hercules Offshore Arena Energy
16 Hercules 201 1982 20,000 JU 200-MC Hercules Offshore EPL Oil & Gas Inc
18 Hercules 204 1981 20,000 JU 200-MC Hercules Offshore Chevron
19 ENSCO 99 1985 30,000 JU 250-IC Ensco Energy XXI
20 Rowan EXL III 2010 40,000 JU 301-360-IC Rowan Freeport-McMoRan Oil & Gas
21 Cecil Provine 1982 30,000 JU 300-IC Rowan Fieldwood Energy
23 ENSCO 82 1979 30,000 JU 300-IC Ensco Energy XXI
24 Hercules 205 1979 20,000 JU 200-MC Hercules Offshore Black Elk
25 Hercules 264 1976 25,000 JU 250-MC Hercules Offshore Castex
26 Hercules 263 1982 20,000 JU 250-MC Hercules Offshore Tana Exploration
27 Hercules 300 1974 25,000 JU 300-MC Hercules Offshore Arena Energy
28 Hercules 120 1958 18,000 JU <200-MC Hercules Offshore Chevron
29 Hercules 173 1971 15,000 JU <200-MC Hercules Offshore Chevron
30 ENSCO 68 1976 30,000 JU 361-400-IC Ensco Chevron
31 ENSCO 87 1982 25,000 JU 301-360-IC Ensco Fieldwood Energy
32 ENSCO 81 1979 25,000 JU 301-360-IC Ensco Stone Energy
33 Hercules 350 1982 25,000 JU 301-360-IC Hercules Offshore Arena Energy

Valuation & EPS Comp Sheets

Yield-Based Values Above NAV Offer Arbitrage Between Equity & Yield Capital Markets
Yield vs. P/NAV relationship
DO 74%
ESV 81%
NE 69%
SDRL 120%
RIG 72%
0.0%
1.0%
2.0%
3.0%
4.0%
5.0%
6.0%
7.0%
8.0%
9.0%
10.0%
11.0%
12.0%
60% 80% 100% 120% 140%
DividendYield(LatestQuarter
Annualized)
P/NAV - Break-up 2014E

OFS Earnings Metrics
Price Gugg EPS PE Consensus EPS EPS Variance
Company Ticker Rating 3/13 Target Upside P/NAV* 1Q14E 13E 14E 15E 13E 14E 15E 1Q14E 14E 15E 1Q14E 14E 15E
S&P 500 SPX 1,846 17.0 15.7 14.4 117.40 128.58
Large Cap Services
Baker Hughes BHI Sell 61.58 45 -27% NA 0.83 2.69 3.55 3.45 22.9 17.3 17.8 0.82 4.04 5.01 1% -12% -31%
Halliburton HAL Neutral 55.25 50 -10% NA 0.73 3.15 3.70 4.00 17.5 14.9 13.8 0.75 3.96 5.01 -3% -6% -20%
Schlumberger SLB Buy 90.27 102 13% NA 1.24 4.79 5.35 6.05 18.8 16.9 14.9 1.23 5.73 6.76 1% -7% -10%
Weatherford WFT Neutral 16.28 15 -8% NA 0.12 0.60 1.05 1.45 27.1 15.5 11.2 0.14 1.04 1.57 -13% 1% -7%8.54
Mean 21.6 16.2 14.5
Large Cap Equipment
Cameron CAM Buy 61.69 70 13% NA 0.73 3.28 3.80 4.90 18.8 16.2 12.6 0.72 3.80 4.76 2% 0% 3%
FMC Tech FTI Buy 50.65 60 18% NA 0.50 2.11 2.70 3.15 24.0 18.8 16.1 0.50 2.66 3.27 0% 2% -4%
Nat Oil Varco NOV Buy 75.18 95 26% NA 1.32 5.52 6.00 6.55 13.6 12.5 11.5 1.39 6.13 6.97 -5% -2% -6%
Tenaris TS Neutral 41.23 42 2% NA 0.62 2.62 2.60 3.00 15.7 15.9 13.7 0.67 2.76 3.08 -7% -6% -3%
Mean 18.0 15.8 13.5
SMid Cap Svcs & Equipment
Aker Solutions AKSO Buy kr 93.65 kr 125 33% NA kr 1.75 kr 5.25 kr 7.90 kr 9.40 17.8 11.9 10.0 1.65 kr 7.81 kr 9.47 6% 1% -1%
C&J Energy Svcs CJES Sell 25.81 18 -30% NA 0.18 1.21 0.90 0.90 21.3 28.7 28.7 0.18 1.11 1.72 2% -19% -48%
Core Laboratories CLB Neutral 193.48 180 -7% NA 1.45 5.32 5.90 6.10 36.4 32.8 31.7 1.45 6.23 7.16 0% -5% -15%
Carbo Ceramics CRR Sell 118.87 95 -20% NA 1.11 3.70 4.40 4.50 32.1 27.0 26.4 1.00 4.62 5.69 11% -5% -21%
Dresser-Rand DRC Neutral 54.59 62 14% NA - 3.00 2.85 3.35 18.2 19.2 16.3 0.35 2.88 3.44 - -1% -3%
Dril-Quip DRQ Neutral 99.64 120 20% NA 1.20 4.23 5.20 6.10 23.6 19.2 16.3 1.20 5.38 6.38 0% -3% -4%
Forum Energy Tech FET Neutral 26.70 28 5% NA 0.39 1.47 1.68 1.90 - 15.0 14.1 0.39 1.78 2.18 1% -5% -13%
Frank's International FI Neutral 23.17 27 17% NA 0.28 1.98 1.30 1.45 11.7 17.8 16.0 0.31 1.34 1.50 -8% -3% -3%
Oceaneering OII Neutral 69.58 80 15% NA 0.80 3.40 4.00 5.00 20.5 17.4 13.9 0.80 4.04 4.73 1% -1% 6%
Oil States Int'l OIS Neutral 94.67 96 1% NA 1.30 6.18 5.20 5.50 15.3 18.2 17.2 1.39 5.67 6.54 -6% -8% -16%
Superior Energy Svcs SPN Neutral 28.15 32 14% NA 0.21 1.56 1.30 2.25 18.0 17.1 12.5 0.22 1.65 2.40 -6% -21% -6%
U.S. Silica Holdings SLCA NC 34.96 NC - NA - - - - 23.8 18.8 14.0 0.35 1.86 2.50 - - -63% 39.92
Mean 21.7 20.3 18.1
Offshore Drilling
Atwood Oceanics* ATW Buy 46.02 58 26% 79% 0.73 5.32 5.40 7.85 8.7 8.5 5.9 - 5.61 7.60 - -4% 3%
Diamond DO Buy 44.39 65 46% 74% 0.61 4.77 5.50 7.60 9.3 8.1 5.8 0.61 4.19 5.91 0.00 31% 29%
Ensco plc ESV Neutral 48.86 60 23% 81% 1.32 6.16 6.60 8.00 7.9 7.4 6.1 1.30 6.38 7.13 0.02 3% 12%
Hercules Offshore HERO Neutral 4.55 5 10% 91% 0.15 0.24 0.45 0.05 19.0 10.1 91.0 0.13 0.60 0.73 0.14 -25% -93%
Noble Corp NE Buy 28.98 42 45% 69% 0.69 2.89 4.00 5.60 10.0 7.2 5.2 0.71 3.45 4.42 (0.03) 16% 27%
Ocean Rig UDW ORIG Buy 17.09 28 64% 66% 0.05 0.77 1.80 2.80 22.2 9.5 6.1 0.06 1.64 2.30 (0.18) 10% 22%
Pacific Drilling PACD Buy 9.89 14 42% 71% 0.17 0.42 1.00 1.60 23.5 9.9 6.2 0.15 0.80 1.35 0.17 25% 19%
Rowan RDC Neutral 31.72 36 13% 88% 0.17 1.98 2.85 5.00 16.0 11.1 6.3 0.24 2.76 4.56 (0.28) 3% 10%
Transocean RIG Buy 39.54 55 39% 72% 0.89 4.12 5.00 6.00 9.6 7.9 6.6 1.04 4.82 5.01 (0.14) 4% 20%
Seadrill SDRL Buy 33.70 50 48% 120% 0.70 3.02 3.30 4.05 11.2 10.2 8.3 0.69 3.34 3.93 0.01 -1% 3%
Mean 81% 11.5 8.8 16.9
Onshore Drilling
Helm & Payne* HP Neutral 96.51 87 -10% NA 1.39 5.67 5.76 4.95 17.0 16.8 19.5 1.47 6.18 6.74 -5% -7% -27%
Nabors NBR Neutral 21.81 20 -8% NA 0.20 1.02 1.10 1.15 21.4 19.8 19.0 0.21 1.14 1.71 -2% -4% -33%
Precision Drilling PDS NC 10.52 NC - NA - - - - 17.2 11.8 9.7 0.36 0.90 1.09 - - -
Patterson UTI PTEN Sell 28.77 20 -30% NA 0.31 1.16 1.15 0.50 24.8 25.0 57.5 0.30 1.38 1.65 4% -16% -70%
Mean 20.1 18.3 26.4
*Quarterly EPS figures for ATW and HP reflect calendar year reporting basis. NAV figures for Offshore Drilling companies are Break-Up NAVs. PDS estimates in CAD. All units in $m except per share data.

OFS EBITDA & Cash Flow Valuation
Price Mkt Net Dt 2013E FCF EBITDA EV / EBITDA CFPS P / CFPS
Company 3/13 Cap Cap FCFPS Yield 13E 14E 15E 13E 14E 15E 13E 14E 15E 13E 14E 15E
S&P 500 1,846 9.0 8.9 9.0
Large Cap Services
Baker Hughes 61.58 26,860 13% 1.61 2.6% 3,871 4,339 4,330 7.7 6.9 6.9 6.51 7.51 7.54 9.5 8.2 8.2
Halliburton 55.25 47,010 25% 2.32 4.2% 6,185 6,978 7,510 8.5 7.5 7.0 5.26 6.16 6.67 10.5 9.0 8.3
Schlumberger 90.27 117,932 9% 2.57 2.8% 12,346 13,246 14,441 9.9 9.3 8.5 7.54 8.22 8.95 12.0 11.0 10.1
Weatherford 16.28 12,555 49% 0.56 3.4% 2,659 3,171 3,575 7.8 6.6 5.8 2.41 2.84 3.24 6.8 5.7 5.0
Mean 3.3% 8.5 7.6 7.1 9.7 8.5 7.9
Large Cap Equipment
Cameron 61.69 13,373 10% 1.81 2.9% 1,460 1,647 1,983 9.9 8.7 7.3 4.57 5.41 6.56 13.5 11.4 9.4
FMC Tech 50.65 11,954 26% 2.33 4.6% 938 1,178 1,376 13.8 11.0 9.4 2.99 3.69 4.20 16.9 13.7 12.1
Nat Oil Varco 75.18 32,217 -1% 5.48 7.3% 4,216 4,604 4,987 7.6 6.9 6.4 7.26 7.86 8.53 10.4 9.6 8.8
Tenaris 41.23 24,337 -7% 1.86 4.5% 2,796 2,814 3,108 8.4 8.3 7.5 3.62 3.56 3.98 11.4 11.6 10.4
Mean 4.8% 9.9 8.7 7.6 13.0 11.6 10.2
SMid Cap Svcs & Equipment
Aker Solutions kr 93.65 kr 25,660 36% 0.24 0.3% kr 3,951 kr 4,880 kr 5,473 8.8 7.1 6.3 kr 10.64 kr 13.54 kr 15.56 8.8 6.9 6.0
C&J Energy Svcs 25.81 1,430 17% 1.22 4.7% 190 189 194 8.3 8.4 8.2 2.56 2.63 2.72 10.1 9.8 9.5
Core Laboratories 193.48 8,679 56% 5.86 3.0% 362 386 393 24.7 23.1 22.7 5.87 6.52 6.79 33.0 29.7 28.5
Carbo Ceramics 118.87 2,746 -12% 2.07 1.7% 172 203 210 15.4 13.1 12.6 5.77 6.70 7.01 20.6 17.7 17.0
Dresser-Rand 54.59 4,165 49% (2.54) -4.7% 472 480 544 11.6 11.4 10.1 4.14 4.03 4.58 13.2 13.5 11.9
Dril-Quip 99.64 4,053 -31% 2.95 3.0% 260 316 369 14.1 11.6 9.9 4.95 6.03 7.04 20.1 16.5 14.2
Forum Energy Tech 26.70 2,481 26% 1.63 6.1% 279 330 361 10.6 9.0 8.2 2.11 2.43 2.66 12.7 11.0 10.0
Frank's International 23.17 3,557 -30% (0.52) -2.2% 451 455 502 7.0 6.9 6.3 2.47 1.72 1.88 9.4 13.5 12.3
Oceaneering 69.58 7,528 -4% 2.48 3.6% 746 857 1,046 10.0 8.7 7.1 5.27 6.08 7.46 13.2 11.4 9.3
Oil States Int'l 94.67 5,050 10% 2.66 2.8% 822 744 769 6.6 7.3 7.0 11.18 10.22 10.56 8.5 9.3 9.0
Superior Energy Svcs 28.15 4,465 25% 1.79 6.3% 1,105 1,101 1,363 5.4 5.4 4.4 5.46 5.67 7.22 5.2 5.0 3.9
U.S. Silica Holdings 34.96 1,872 33% 0.48 1.4% 160 192 244 13.1 10.9 8.6 1.57 2.71 3.55 22.3 12.9 9.816,921 18,729 20,937 76 83 94
Mean 2.2% 11.3 10.2 9.3 14.7 13.1 11.8
Offshore Drilling
Atwood Oceanics* 46.02 2,955 38% (4.88) -10.6% 547 602 844 8.1 7.3 5.2 7.10 7.70 10.83 6.5 6.0 4.2
Diamond 44.39 6,172 6% 0.87 2.0% 1,302 1,588 2,142 5.0 4.1 3.1 7.56 8.77 11.36 5.9 5.1 3.9
Ensco plc 48.86 11,412 26% 0.86 1.8% 2,409 2,552 3,077 6.6 6.3 5.2 8.81 9.51 11.19 5.5 5.1 4.4
Hercules Offshore 4.55 727 50% (2.27) -49.8% 299 392 305 5.8 4.4 5.7 1.22 1.63 1.26 3.7 2.8 3.6
Noble Corp 28.98 7,365 39% (3.09) -10.7% 1,952 2,605 3,246 6.6 4.9 3.9 6.35 8.08 9.87 4.6 3.6 2.9
Ocean Rig UDW 17.09 2,254 49% (4.25) -24.9% 540 827 992 10.4 6.8 5.7 2.52 3.93 5.11 6.8 4.3 3.3
Pacific Drilling 9.89 2,077 50% (3.07) -31.1% 360 562 824 12.0 7.7 5.2 1.11 1.97 3.04 8.9 5.0 3.3
Rowan 31.72 3,941 13% 0.20 0.6% 597 799 1,170 8.1 6.1 4.2 4.16 5.40 7.92 7.6 5.9 4.0
Transocean 39.54 14,275 27% (0.88) -2.2% 3,522 3,908 4,343 6.1 5.5 5.0 7.18 8.13 9.14 5.5 4.9 4.3
Seadrill 33.70 15,814 58% (5.45) -16.2% 2,748 3,393 4,033 10.6 8.6 7.2 4.46 5.08 6.07 7.6 6.6 5.6
Mean -14.1% 7.9 6.2 5.0 6.3 4.9 4.0
Onshore Drilling
Helm & Payne 96.51 10,378 -15% 1.36 1.4% 1,401 1,475 1,413 6.9 6.6 6.8 10.27 10.71 10.59 9.4 9.0 9.1
Nabors 21.81 6,467 34% 1.20 5.5% 1,664 1,801 1,851 5.9 5.5 5.3 5.33 5.01 5.09 4.1 4.4 4.3
Precision Drilling 10.52 3,073 33% (0.47) -4.5% 631 767 864 6.8 5.6 5.0 1.63 2.25 2.50 6.4 4.7 4.2
Patterson UTI 28.77 4,150 13% 0.72 2.5% 919 878 778 5.0 5.2 5.9 4.99 5.34 4.96 5.8 5.4 5.8
Mean 1.2% 6.2 5.7 5.8 6.4 5.9 5.9
*PDS estimates in CAD. All units in $m except per share data.

OFS EPS Comp
Ticker Company Category 2013E 2014E 2015E 1Q13 2Q13 3Q13 4Q13E 1Q14E 2Q14E 3Q14E 4Q14E
Large Cap Services
SLB Schlumberger EPS 4.79 5.35 6.05 1.01 1.15 1.29 1.35 1.24 1.30 1.39 1.43
Consensus EPS 5.73 6.76 1.23 1.37 1.51 1.61
Consensus EPS-High 6.46 7.45 1.30 1.47 1.61 1.78
Consensus EPS-Low 5.35 6.00 1.12 1.30 1.38 1.43
HAL Halliburton EPS 3.15 3.70 4.00 0.67 0.73 0.83 0.93 0.73 0.86 1.00 1.10
Consensus EPS 3.96 5.01 0.75 0.92 1.09 1.21
BHI Baker Hughes EPS 2.69 3.55 3.45 0.65 0.61 0.81 0.62 0.83 0.82 0.94 0.95
Consensus EPS 4.04 5.01 0.82 0.89 1.11 1.22
WFT Weatherford EPS 0.60 1.05 1.45 0.15 0.15 0.23 0.07 0.12 0.19 0.34 0.40
Consensus EPS 1.05 1.57 0.14 0.19 0.33 0.40
Large Cap Equipment
CAM Cameron International EPS 3.28 3.80 4.90 0.70 0.79 0.81 1.00 0.73 0.83 1.01 1.23
Consensus EPS 3.80 4.76 0.72 0.88 1.02 1.20
FTI FMC Technologies EPS 2.11 2.70 3.15 0.43 0.48 0.53 0.69 0.50 0.66 0.73 0.82
Consensus EPS 2.66 3.27 0.50 0.63 0.71 0.82
NOV National Oilwell Varco EPS 5.52 6.00 6.55 1.29 1.33 1.34 1.56 1.32 1.44 1.57 1.68
Consensus EPS 6.13 6.97 1.39 1.47 1.57 1.70
TS Tenaris EPS 2.62 2.60 3.00 0.72 0.72 0.51 0.69 0.62 0.62 0.64 0.73
Consensus EPS 2.76 3.08 0.67 0.69 0.67 0.75

OFS EPS Comp
SMid Cap Services & Equipment
AKSO-NOAKSO Aker Solutions EPS kr 5.25 kr 7.90 kr 9.40 kr 0.99 kr 1.40 kr 1.46 kr 1.40 kr 1.75 kr 1.84 kr 2.19 kr 2.13
Consensus EPS kr 7.81 kr 9.47 kr 1.65 kr 1.91 kr 1.91 kr 2.06
Consensus EPS-High kr 9.25 kr 12.09 kr 2.03 kr 2.35 kr 2.38 kr 2.49
Consensus EPS-Low kr 6.23 kr 7.97 kr 1.30 kr 1.55 kr 1.51 kr 1.82
CJES C&J Energy Services EPS 1.21 0.90 0.90 0.46 0.39 0.24 0.13 0.18 0.21 0.27 0.24
Consensus EPS 1.11 1.72 0.18 0.25 0.34 0.34
CLB Core Laboratories EPS 5.32 5.90 6.10 1.22 1.32 1.36 1.43 1.45 1.48 1.48 1.48
Consensus EPS 6.23 7.16 1.45 1.53 1.60 1.65
CRR Carbo Ceramics EPS 3.70 4.40 4.50 0.76 0.71 1.31 0.90 1.11 1.15 1.10 1.04
Consensus EPS 4.63 5.67 1.00 1.00 1.28 1.25
DRC Dresser-Rand EPS 3.00 2.85 3.35 0.43 0.69 0.64 1.23 -- -- -- --
Consensus EPS 3.06 3.10 3.86 1.31 0.47 0.66 0.76 1.22
Consensus EPS-High 3.38 3.75 4.50 1.60 0.65 0.82 0.90 1.45
Consensus EPS-Low 2.88 2.78 3.30 1.12 0.33 0.54 0.54 0.92
DRQ Dril-Quip EPS 4.23 5.20 6.10 0.85 1.05 1.12 1.20 1.20 1.28 1.34 1.38
Consensus EPS 5.41 6.37 1.20 1.30 1.40 1.48
FET Forum Energy EPS 1.47 1.68 1.90 0.33 0.72 0.44 0.39 0.39 0.42 0.43 0.44
Consensus EPS 1.77 2.19 0.39 0.42 0.47 0.50
FI Frank's Intl. EPS 1.98 1.30 1.45 0.60 0.85 0.34 0.37 0.28 0.31 0.34 0.36
Consensus EPS 1.34 1.50 0.30 0.33 0.35 0.36
OII Oceaneering Intl. EPS 3.40 4.00 5.00 0.69 0.91 0.96 0.86 0.80 1.02 1.08 1.10
Consensus EPS 4.04 4.73 0.80 1.04 1.14 1.06
OIS Oil States Intl. EPS 6.18 5.20 5.50 1.80 1.50 1.42 1.47 1.30 1.15 1.31 1.44
Consensus EPS 5.67 6.54 1.39 1.27 1.44 1.58
SPN Superior Energy EPS 1.56 1.30 2.25 0.40 0.72 0.43 0.30 0.21 0.30 0.37 0.43
Consensus EPS 1.67 2.41 0.23 0.41 0.52 0.50

OFS EPS Comp
Offshore Drillers
ATW Atwood Oceanics EPS 5.32 5.40 7.85 1.10 1.28 1.37 1.57 1.28 0.73 1.62 1.77
Consensus EPS 5.61 7.60 0.96 1.47 1.91
Consensus EPS-High 6.23 8.78 1.27 1.86 2.26
Consensus EPS-Low 5.03 6.11 0.71 1.10 1.67
DO Diamond Offshore EPS 4.77 5.50 7.60 1.26 1.33 1.22 0.96 0.61 1.03 1.86 2.00
Consensus EPS 4.22 5.94 0.61 0.75 1.37 1.59
ESV Ensco EPS 6.16 6.60 8.00 1.36 1.55 1.69 1.56 1.32 1.67 1.83 1.79
Consensus EPS 6.39 7.15 1.30 1.57 1.65 1.88
HERO Hercules Offshore EPS 0.24 0.45 0.05 (0.02) 0.01 0.11 0.14 0.15 0.05 0.15 0.11
Consensus EPS 0.60 0.73 0.13 0.08 0.16 0.21
NE Noble Drilling EPS 2.89 4.00 5.60 0.59 0.63 0.85 0.82 0.69 0.78 1.12 1.41
Consensus EPS 3.44 4.45 0.71 0.73 0.98 1.09
ORIG Ocean Rig UDW EPS 0.77 1.80 2.80 0.04 0.10 0.30 0.30 0.05 0.45 0.67 0.63
Consensus EPS 1.63 2.27 0.08 0.44 0.58 0.54
Consensus EPS-Low 1.00 1.50 (0.08) 0.33 0.38 0.36
PACD Pacific Drilling EPS 0.42 1.00 1.60 0.07 0.10 0.14 0.12 0.17 0.20 0.25 0.38
Consensus EPS 0.80 1.35 0.15 0.15 0.21 0.29
RDC Rowan EPS 1.98 2.85 5.00 0.55 0.57 0.42 0.42 0.17 0.51 0.88 1.29
Consensus EPS 2.77 4.56 0.24 0.58 0.79 1.14
RIG Transocean EPS 4.12 5.00 6.00 0.93 1.08 1.37 0.73 0.89 1.19 1.36 1.56
Consensus EPS 4.83 5.06 1.04 1.23 1.24 1.23
SDRL Seadrill EPS 3.02 3.30 4.05 0.69 0.96 0.60 0.79 0.70 0.82 0.86 0.92
Consensus EPS 3.38 3.96 0.71 0.84 0.87 0.94
Land Drillers
HP Helmrich & Payne EPS 5.67 5.76 4.95 1.40 1.36 1.44 1.47 1.56 1.39 1.41 1.40
Consensus EPS 6.17 6.73 1.46 1.47 1.55 1.62
NBR Nabors EPS 1.02 1.10 1.15 0.46 0.10 0.20 0.26 0.20 0.18 0.33 0.39
Consensus EPS 1.14 1.71 0.21 0.23 0.33 0.39
PTEN Patterson-UTI Energy EPS 1.16 1.15 0.50 0.38 0.28 0.23 0.27 0.31 0.26 0.29 0.29
Consensus EPS 1.38 1.65 0.30 0.30 0.38 0.40

OFS Valuations & Risks
Ticker Valuation Risks
BHI BHI currently trades at approximately 17x our 2014 EPS and 7x our 2014 EBITDA estimates. Our 12-month
price target of $45 is based on 13.0x our forw ard 4 quarter EPS and 5.5x our forw ard 4 quarter EBITDA
estimates.
In addition to the macro environment being more robust than w e currently expect, BHI could outperform should its asset turnover
improve, w hich in turn w ould push operating margins higher. In 2013, BHI‘s PPE turnover w as 2.6x, vs. 2.7x for HAL and 3.0x for
SLB. How ever, given BHI‘s higher mix of product sales (i.e., manufacturing vs. services), w e believe it should have higher PPE
turnover than its peers. Should BHI execute on its current ―self-help‖ initiatives and deliver peer-leading turnover, our estimates
w ould likely prove too conservative.
HAL HAL currently trades at approximately 15x our 2014 EPS and 8x our 2014 EBITDA estimates. Our 12-month
estimates.
HAL‘s U.S. onshore execution has been excellent, and should the company be able to demonstrate higher EPS grow th into 2015,
our estimates w ould prove to be too low . Admittedly, EPS grow th more in-line w ith current consensus w ould support higher target
multiples as w ell.
SLB SLB currently trades at approximately 17x our 2014 EPS and 9x our 2014 EBITDA estimates. Our 12-month
estimates.
Much of the investment thesis for SLB rests w ith its ability to grow market share by delivering superior services quality and tool
reliability, and reduce the cost of services delivery. To the extent that execution of this strategy takes longer than w e currently
expect, our estimates—especially margins—could prove too aggressive. Similarly, SLB‘s human resources program has long been
a competitive advantage, and to the extent that the company loses key people (particularly to IOCs), its competitive positioning in
the industry could w eaken.
WFT WFT currently trades at approximately 16x our 2014 EPS and 7x our 2014 EBITDA estimates. Our 12-month
estimates.
This year, WFT needs to 1) execute on both its strategic divestitures, 2) high-grade its core portfolio of businesses to focus on
higher margin projects, and 3) deliver +/-$1bn in free cash flow from higher earnings, improved w orking capital turns, and low er
capex. It‘s a tall order, but should the company deliver—particularly on the free cash flow generation—its relative valuation should
begin to improve. How ever, w ith its early production facilities contracts in Iraq not likely to be completed until 3Q14, the company
remains susceptible to further cash losses associated w ith this w ork, and potential disappointments w ith respect to cash flow
generation.
CAM CAM currently trades at approximately 16x our 2014 EPS estimate and 9x our 2014 EBITDA estimate. Our 12-
month price target of $70 reflects a multiple of 17.5x our forw ard 4 quarter EPS and 9.5x our forw ard 4
quarter EBITDA estimates.
Although the stock has started to act better recently, investor confidence in management‘s ability to execute remains low .
Although w e believe the low level of confidence should be view ed as a low bar—and therefore easy to deliver upon—w e
acknow ledge that failure to execute could leave CAM in a value trap zip code.
FTI FTI currently trades at approximately 19x our 2014 EPS and 11x our 2014 EBITDA estimates. Our 12-month
price target of $60 reflects a multiple of 21.0x our forw ard 4 quarter EPS and 13.0x our forw ard 4 quarter
EBITDA estimates.
Execution continues to be the biggest risk for FTI. In our view , management needs to deliver on its stated goal of mid-teens
margins, and overruns and delays on the current backlog to get full credit for the 30% y/y increase in revenue/tree in backlog.
NOV NOV currently trades at approximately 13x our 2014 EPS estimate and 7x our 2014 EBITDA estimate. Our 12-
month price target of $95 reflects a multiple of 15.0x our forw ard 4 quarter EPS and 9.0x our forw ard 4
quarter EBITDA estimates.
Many investors still believe that NOV only w orks as a stock w hen backlog is grow ing (i.e., book-to-bill is greater than 1x) and
margins are expanding. Whereas last year, orders w ere strong and margins w eak, the concern for 2014 is the exact opposite:
that orders w ill be w eak even as margins improve modestly q/q. In our view , this conventional approach to the stock is more
consistent w ith a philosophy of momentum investing in oil services—a philosophy that does not apply in the current slow /no
grow th environment. How ever, w ithin a more relevant framew ork of sustainable competitive advantage, low capital intensity, and
high cash return, w e believe NOV screens w ell.
TS TS currently trades at approximately 16x our 2014 EPS and 8x our 2014 EBITDA estimates. Our 12-month
estimates.
The trade case before the ITC remains a w ildcard for TS and other U.S. OCTG manufacturers. The nine countries against w hich
the industry filed the trade petition (―the P9‖) still accounted for more than 50% of all OCTG imports as recently as 3Q13, so a
meaningful tariff ruling by the ITC could tighten the pipe supply-demand balance for 2H14 and 2015, and boost spot OCTG prices.
How ever, w e believe the industry‘s case against the P9 countries has w eakened not only by the evidence of continued imports
from P9 manufacturers (in the face of the potential for retroactive penalties), but by the the late December preliminary finding of
―de minimis‖ countervailing duties on OCTG from India and Turkey.

AKSO We arrive at our price target of kr125/sh by calibrating against our P/E valuation framew ork and our
discounted cash flow valuation methodology. Future estimated earnings grow th discounted by our cost of
capital implies a valuation range betw een a 23.2x multiple on our 2013 EPS estimate and a 17.4x multiple on
our 2014 EPS estimate. Our DCF valuation implies a value of kr115/sh, given strong grow th over the explicit
forecast, reinvestment of capital, and a normalization of returns w ithout economic rents.
Business Model Risk - The transition to a matrix business model that crosses regional management and product management in
order to create a single point of contact w ith customers poses a risk to existing client relationships that may threaten future
orders. At the same time, the change in management structure may also lead to supply chain and other execution issues. There is
a risk that AKSO may choose to grow revenues by underbidding the competition on price. Resultant low er margin business may
challenge the company‘s margin expansion goals.
CJES CJES currently trades at approximately 29x our 2014 EPS and 8x our 2014 EBITDA estimates. Our 12-month
estimates.
In our view , short of a major macro shift in the E&P spending outlook, w e believe much of CJES‘s organic grow th option value has
been deferred. Should E&P spending grow at a faster rate than w e now expect, how ever, our estimates could prove too low .
CLB We arrive at our price target of $180 per share by triangulating betw een our P/E valuation framew ork, yield-
based metrics, and our discounted cash flow valuation methodology. Future estimated earnings grow th
discounted by our cost of capital implies a valuation range betw een a 33.8x multiple on our 2013 EPS
estimate and a 30.5x multiple on our 2014 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. In addition,
w e see yield-based metrics magnifying the benefit of outsized returns, free cash flow grow th, and a fuller
payout strategy. In our view , CLB shares w ill continue to benefit from yield uplift, as payouts grow , providing
catalysts for the shareholders.
Since CLB‘s largest customers conduct roughly 75% of their reservoir testing in-house, there is a risk that they w ill look to fully
integrate their reservoir diagnostics internally. If the major integrated oil companies w ere to bring their testing in-house, roughly
30% of CLB‘s revenues may prove at risk. Secondly, increased perforation product competition from the larger pressure pumping
players, like HAL, BHI, and SLB, w ould challenge economics for CLB. In addition, if discovery of reserves in less challenging
basins shifts the sources of production, the need for more data, diagnostic tests, and equipment may decline w hich w ould
adversely impact CLB‘s earnings. Finally, if macro factors reduce commodity demand, resulting in a collapse of oil and natural gas
prices, numerous fields may prove uneconomic, leading to reduced upstream spending to the detriment of CLB economics. If
macro factors turn out stronger than our expectations, thus
increasing commodity demand, operator spending may provide upside to CLB earnings.
CRR We arrive at our price target of $95 per share by triangulating betw een our P/E valuation framew ork, yield-
based metrics, and our discounted cash flow valuation methodology. Future estimated earnings grow th
discounted by our cost of capital implies a valuation range betw een a 25.7x multiple on our 2013 EPS
estimate and a 21.6x multiple on our 2014 EPS estimate. Our DCF valuation implies a value of $95 per share,
given strong grow th over the explicit forecast, reinvestment of capital, and a normalization of returns. Given
management‘s desire to maintain grow th of a sustainable dividend, potential upside may lie in yield-based
metrics, w hich may magnify the benefit of outsized returns, free cash flow grow th, and the emergence and
communication of a fuller payout strategy.
Macroeconomic and Commodity Price Strength: If macro factors turn out stronger than our expectations, thus increasing
commodity demand, operator spending may provide upside to CRR earnings. Positive Investor Sentiment and Short Covering: If
investors become more optimistic on North American oil & gas activity throughout 2014, CRR‘s stock could rise. In the near term,
short covering may keep upw ard pressure on shares.
DRC DRC currently trades at approximately 19x our 2014 EPS and 11x our 2014 EBITDA estimates. Our 12-month
estimates.
As a leading compression manufacturing and services company, DRC‘s grow th is highly correlated w ith energy infrastructure
investment… investment that throughout 2013 w as ―slipping to the right.‖ Should these projects stop slipping and get booked,
orders in 2014 could prove to be far stronger than the +15% level built into our model, and visibility of earnings grow th in 2015
w ould improve. Macroeconomic shocks or a falling oil price environment could result in budget constraints and further delays and
project slippage, leaving dow nside risk to our grow th estimates.
DRQ We arrive at our price target of $120/sh by calibrating against our P/E valuation framew ork and our
our 2015 EPS estimate. Our DCF valuation implies a value of $120/sh, given strong grow th over the explicit
forecast, reinvestment of capital, and a normalization of returns w ithout economic rents.
The permitting delays in the Gulf of Mexico plagued drilling activity in the region during 2010 and 2011. The slow dow n continues to
negatively impact DRQ‘s w ellhead and other offshore equipment businesses. In recent months permit issuance has accelerated,
but persistent w eakness in the Gulf of Mexico remains a risk to future earnings – w hereas the Gulf of Mexico represented 44%
and 31% of revenues in 1Q10 and full year 2011, respectively. Also, given that Dril-Quip does not hedge its steel or other inputs,
the risk remains that rising input costs may erode margins on its fixed-price equipment.
FET We arrive at our price target of $28 per share by calibrating betw een our P/E valuation framew ork and our
capital implies a valuation range betw een an 19.0x multiple on 2013 EPS and a 16.7x multiple on our 2014
EPS estimate. Our DCF valuation implies a value of $28/share, given strong grow th over the explicit forecast,
reinvestment of capital, and a normalization of returns.
We see the ability to finance an acquisition strategy through debt or to maintain a valuation multiple that provides an accretive
equity currency as potential risks. The company may face competition from larger competitors if they enter FET's specific markets.
If macro factors reduce commodity demand, resulting in a collapse of oil and natural gas prices, reduced upstream spending
w ould negatively impact the company's operations. In terms of positive risks, if the North American services market reaches a
positive inflectiion point, FET w ould likely benefit gtiven its high leverage to the region.
FI FI currently trades at approximately 18x our 2014 EPS and 7x our 2014 EBITDA estimates. Our price target of
$27 is based on 20x our forw ard 4 quarter EPS and 11x our forw ard 4 quarter EBITDA estimates.
Given that FI generates an estimated 72% of its revenue offshore—the majority of w hich comes from DW and UDW projects that
have a higher degree of complexity and are subject to delays related to engineering and project management constraints at the
operator level, grow th beyond 2015 may not accelerate as w e currently expect. If onshore and offshore spending turn out
stronger than expected, our estimates may be too low .
OII We arrive at our price target of $80/sh by calibrating against our P/E valuation framew ork and our discounted
cash flow valuation methodology. Future estimated earnings grow th discounted by our cost of capital implies
a valuation range betw een a 20.0x multiple on our 2014 EPS estimate and a 16.0x multiple on our 2015 EPS
estimate. Our DCF valuation implies a value of $80/sh, given strong grow th over the explicit forecast,
reinvestment of capital, and a normalization of returns w ithout economic rents.
We assume that the ROV business grow s w ith the expansion of the offshore rigs fleet and the acceleration of offshore drilling
activity. Given OII‘s strategy to pass on low er margin contracts w ith Petrobras, one of the largest incremental consumers of
offshore rigs, OII may place their grow th prospects at risk. Also, if regulatory issues persist in the GoM, they may impede the
recovery activity. If offshore rig activity proves stronger than expectations, OII w ould likely benefit.
OIS OIS currently trades at approximately 18x our 2014 EPS and 7x our 2014 EBITDA estimates. Our price target
of $96 is based on 18.0x our forw ard 4 quarter EPS and 8.5x our forw ard 4 quarter EBITDA estimates.
In our view , the dow nside risk to OIS is minimal, given the event-driven catalysts of the Accommodations spin and M&A potential
of ―remain co.‖ How ever, should the company not receive IRS approval for REIT conversion, w e w ould expect the
Accommodations business to trade at a valuation level closer to non-REIT comps such as Black Diamond (BDI CN, Not Covered,
C$29.26), w hich now trades at 7.7x consensus 2014 EBITDA. Under this scenario, our sum-of-the-parts valuation w ould have
dow nside to $100—about in-line w ith w here the stock currently trades. If the REIT conversion materializes earlier than expected,
our valuation may be conservative.
SPN We arrive at our price target of $32 per share by calibrating betw een our P/E valuation framew ork and our
our 2015 EPS estimate. Our DCF valuation implies a value of $32/sh, given strong grow th over the explicit
forecast, reinvestment of capital, and a normalization of returns.
Given SPN‘s international grow th ambitions, if it w ere to take an undisciplined approach, adding large fixed costs ahead of
potentially risky revenue streams, SPN profitability may suffer. Failure to properly leverage capital expenditure may adversely
impact returns and economics. Investors have become fairly secure that oil prices w ill remain w ithin recent ranges. If U.S.
production grow th bumps up against domestic refining capacity, w ithout potential to relieve any potential glut, or exports from Iran
or Libya recover faster than expected, creating a disorderly international crude market, oil prices could fall. While global upstream
activity may see a negative impact from low er oil prices, shorter lead time, & higher marginal costs, North American
unconventional activity may fall off. Reduced activity, both domestic and international, w ould negatively impact our SPN thesis. If
N.A. activity surprises on the upside, SPN shares could strengthen.

ATW We arrive at a price target of $58/sh. Our methodology w eighs our NAV - Break-Up, or liquidation value of
the company, and our NAV - Reinvestment Value, w hich discounts the value of assumed future investment
against our view of the company‘s capital budgeting strategy and our future forecast of the offshore rig
market across asset classes.
Risks include construction (4 new builds), BOP maintenance dow ntime & dayrate exposure. Rig construction programs run the risk
of costs and delivery overruns that may impact earnings. Operational execution risk leaves the chance for higher maintenance
costs and dow ntime that may impact earnings. In a higher scrutiny, post-Macondo w orld, the risk of higher maintenance is
prevalent. Economic cycles impact commodity prices, w hich in turn impact drilling activity and rig demand. Thus, an economic
dow nturn may negatively impact earnings pow er.
DO We arrive at a price target of $65/sh. Our methodology triangulates betw een NAV - Break-Up, NAV -
Reinvestment, and yield based valuation metrics. While NAV provides baseline support, w e derive our price
target against yield- based valuation metrics, w here w e probability w eight the timing and magnitude of future
dividends in relation to the current capital market for yield entities.
Should midw ater dayrates exceed expectations DO could outperform, dow nside risks include construction and strategy (favoring
dividends over more aggressive reinvestment). Operational execution risk leaves the chance for higher maintenance costs and
dow ntime that may impact earnings. In a higher scrutiny, post-Macondo w orld, the risk of higher maintenance is prevalent.
Economic cycles impact commodity prices, w hich in turn impact drilling activity and rig demand. Thus, an economic dow nturn may
negatively impact earnings pow er.
ESV We arrive at a price target of $60/sh. Our methodology triangulates betw een NAV - Break-Up, NAV -
Risks include construction (7 new builds) and GOM exposure. Operational execution risk leaves the chance for higher
maintenance costs and dow ntime that may impact earnings. In a higher scrutiny, post-Macondo w orld, the risk of higher
maintenance is prevalent. A potential overbuild w ithin any segment of the rig market can depress dayrates and shorten contract
durations to the detriment of earnings. Economic cycles impact commodity prices, w hich in turn impact drilling activity and rig
demand. Thus, an economic dow nturn may negatively impact earnings pow er.
HERO We arrive at a price target of $5/sh. Our methodology triangulates betw een NAV - Break-Up, NAV -
Risks include construction (1 new build) and GOM exposure. Operational execution risk leaves the chance for higher maintenance
costs and dow ntime that may impact earnings. In a higher scrutiny, post-Macondo w orld, the risk of higher maintenance is
prevalent. A potential overbuild w ithin any segment of the rig market can depress dayrates and shorten contract durations to the
detriment of earnings. Economic cycles impact commodity prices, w hich in turn impact drilling activity and rig demand. Thus, an
economic dow nturn may negatively impact earnings pow er. Persistently high dayrates and favorable supply/demand dynamics
may benefit earnings.
NE We arrive at a price target of $42/sh. Our methodology triangulates betw een NAV - Break-Up, NAV -
Risks include construction (12 new builds), GOM and Mexico exposure, and RoF exposure. Given the volatility of contract
dayrates and contract terms, the company maintains a risk of low bids as the rig market improves as w ell as a false confidence in
bargaining pow er as the market declines. Rig construction programs run the risk of costs and delivery overruns that may impact
earnings. Operational execution risk leaves the chance for higher maintenance costs and dow ntime that may impact earnings.
ORIG We arrive at a price target of $28/sh. Our methodology triangulates betw een NAV - Break-Up, NAV -
Risks include construction (4 new builds). Given the volatility of contract dayrates and contract terms, the company maintains a
risk of low bids as the rig market improves as w ell as a false confidence in bargaining pow er as the market declines. Rig
construction programs run the risk of costs and delivery overruns that may impact earnings. Operational execution risk leaves the
chance for higher maintenance costs and dow ntime that may impact earnings.
PACD We arrive at a price target of $14/sh. Our methodology w eighs our NAV - Break-Up, or liquidation value of
Risks include construction (4 new builds) and BOP maintenance dow ntime. Rig construction programs run the risk of costs and
delivery overruns that may impact earnings. Operational execution risk leaves the chance for higher maintenance costs and
dow ntime that may impact earnings. In a higher scrutiny, post-Macondo w orld, the risk of higher maintenance is prevalent.
Economic cycles impact commodity prices, w hich in turn impact drilling activity and rig demand. Thus, an economic dow nturn may
negatively impact earnings pow er.
RDC We arrive at a price target of $36/sh. Our methodology w eighs our NAV - Break-Up, or liquidation value of
Risks include construction (4 new builds) and entry into new markets, w hich could potentially carry higher costs (UDW and SE
Asia). Given the volatility of contract dayrates and contract terms, the company maintains a risk of low bids as the rig market
improves as w ell as a false confidence in bargaining pow er as the market declines. Rig construction programs run the risk of
costs and delivery overruns that may impact earnings. A potential overbuild w ithin any segment of the rig market can depress
dayrates and shorten contract durations to the detriment of earnings. Persistently high dayrates and favorable supply/demand
dynamics may benefit earnings.
RIG We arrive at a price target of $55/sh. Our methodology triangulates betw een NAV - Break-Up, NAV -
Reinvestment, and yield-based valuation metrics. While NAV provides baseline support, w e derive our price
target against yield-based valuation metrics, w here w e probability-w eight the timing and magnitude of future
Macondo involvement remains a risk to the dow nside. Given the volatility of contract dayrates and contract terms, the company
maintains a risk of low bids as the rig market improves as w ell as a false confidence in bargaining pow er as the market declines.
Operational execution risk leaves the chance for higher maintenance costs and dow ntime that may impact earnings. In a higher
scrutiny, post-Macondo w orld, the risk of higher maintenance is prevalent. Economic cycles impact commodity prices, w hich in
turn impact drilling activity and rig demand. Thus, an economic dow nturn may negatively impact earnings pow er.
SDRL We arrive at a price target of $50/sh. Our methodology triangulates betw een NAV - Break-Up, NAV -
Reinvestment, and yield-based valuation metrics. While NAV provides baseline support, w e derive our price
target against yield-based valuation metrics, w here w e probability-w eight the timing and magnitude of future
Risks include construction (16 rig new builds) and financial leverage, SDRL is the most levererd name in our group. Rig
construction programs run the risk of costs and delivery overruns that may impact earnings. Operational execution risk leaves the
chance for higher maintenance costs and dow ntime that may impact earnings. In a higher scrutiny, post-Macondo w orld, the risk
of higher maintenance is prevalent. A potential overbuild w ithin any segment of the rig market can depress dayrates and shorten
contract durations to the detriment of earnings.
HP HP currently trades at approximately 7x our 2014 EBITDA and 9x our 2014 CFPS estimates. Our 12-month
price target of $87 is based on 6.0x our forw ard 4-quarter EBITDA and 8.0x our CFPS estimates.
Our investment thesis is predicated upon the idea that the rate of HP‘s market share gains remains relatively stable, and that
overall utilization suffers as a result of a market dow nturn in 2015. How ever, should HP‘s share gains accelerate into any potential
dow nturn next year, w e could be underestimating fleet utilization and earnings. Additionally, w e expect several large tenders this
year (for w ork in 2015-16) in countries like Saudi Arabia. Should HP w in any of these large international tenders, our estimates
w ould prove too conservative, as w e have assumed essentially flat international revenue and operating income.
NBR NBR currently trades at approximately 6x our 2014 EBITDA and 4x our 2014 CFPS estimates. Our 12-month
price target of $20 is based on 5.0x our forw ard 4 quarter EBITDA and 4.0x our CFPS estimates.
The risk in being NEUTRAL a low multiple stock is that a re-rate event (e.g., management change, execution of meaningful non-
core asset divestiture, etc.) could occur at any point. We continue to believe the event risk in NBR is low , as the leverage,
challenged asset base, and shareholder rights plan create challenges for potential activists.
PTEN PTEN currently trades at approximately 5x our 2014 EBITDA and 5x our 2014 CFPS estimates. Our 12-month
price target of $20 is based on 4.4x our forw ard 4-quarter EBITDA and 4.0x our CFPS estimates.
We continue to believe that the market for AC-electric rigs remains under-supplied by +/-600 rigs, and that PTEN has emerged as a
real leader in the AC market as a result of the efficiency of its APEX fleet and w orkforce. How ever, our expectations of a
commodity-price induced reduction in drilling activity in 2015 should create an air pocket in overall rig demand—including demand
for AC-electric rigs. Should the market hold up next year, our estimates for PTEN w ould very likely prove too conservative, and
much of the dow nside risk w ould be mitigated.

Additional Companies Mentioned (priced as of 03/13/14)
Company Name Ticker Price Rating
Murphy Oil Corp MUR 59.02$ NC
Noble Energy Inc NBL 66.94$ BUY
Nabors Industries Ltd NBR 21.81$ NEUTRAL
Noble Corporation PLC NE 28.98$ BUY
Newfield Exploration Co NFX 27.53$ NC
Ocean Rig UDW Inc ORIG 17.09$ BUY
Pacific Drilling SA PACD 9.89$ BUY
Petrofac Ltd PFC-LN 1,356.14£ NC
ROWAN COMPANIES PLC RDC 31.72$ NEUTRAL
ROYAL DUTCH SHELL PLC RDSA 25.75$ NC
Transocean Ltd RIG 39.54$ BUY
Repsol SA REP-MC 17.60 € NC
Seadrill Ltd SDRL 33.70$ BUY
Stone Energy Corp SGY 33.77$ NC
Spartan Energy Corp SPE-V 2.72$ NC
Statoil ASA STO 27.14$ NC
Santos Ltd STO-AU 13.64$ NC
Total SA TOT 63.00 € NC
W&T Offshore Inc WTI 14.84$ NC
Exxon Mobil Corp XOM 93.64$ NC
Company Name Ticker Price Rating
Marubeni Corp 8002-TO 721.00¥ NC
Anadarko Petroleum Corp APC 81.57$ BUY
Atwood Oceanics Inc ATW 46.02$ BUY
BHP Billiton Ltd BHP 64.46$ NC
BP PLC BP 47.59$ NC
Cobalt International Energy Inc CIE 17.66$ BUY
CENTRICA PLC CNA-LN 334.63£ NC
Chevron Corp CVX 114.45$ NC
Dana Gas PJSC DANA-AD 0.80$ NC
Diamond Offshore Drilling Inc DO 44.39$ BUY
Eni SpA E 47.19$ NC
EPL Oil & Gas Inc EPL 38.00$ NC
ENSCO PLC ESV 48.86$ NEUTRAL
Energy XXI (Bermuda) Ltd EXXI 22.13$ NEUTRAL
Freeport-McMoRan Copper & Gold IncFCX 30.64$ NC
Hercules Offshore Inc HERO 4.55$ NEUTRAL
Hess Corp HES 79.85$ NEUTRAL
Husky Energy Inc HSE-T 32.99$ NC
Contango Oil & Gas Co MCF 46.46$ NC

ANALYST CERTIFICATION
By issuing this research report, each Guggenheim Securities, LLC ("Guggenheim Securities") research analyst whose name appears in this report hereby certifies that (i) all of the views expressed in this
report accurately reflect the research analyst's personal views about any and all of the subject securities or issuers discussed herein and (ii) no part of the research analyst's compensation was, is, or will be
directly or indirectly related to the specific recommendations or views expressed by the research analyst.
IMPORTANT DISCLOSURES
The research analyst(s) and research associate(s) have received compensation based upon various factors, including quality of research, investor client feedback, and Guggenheim Securities, LLC's overall
revenues, which includes investment banking revenues.
Guggenheim Securities, LLC or its affiliates expect(s) to receive or intend(s) to seek compensation for investment banking services from Atwood Oceanics, Inc., Diamond Offshore Drilling Inc., Ensco plc,
Hercules Offshore, Inc., Noble Corp., Ocean Rig UDW Inc., Pacific Drilling S.A., Rowan Companies Inc., Seadrill Ltd., Transocean Ltd., Apache Corporation, Anadarko Petroleum Corporation, Baker Hughes,
Inc., Cameron International, Inc., Cobalt International Energy, Inc., C&J Energy Services, Inc., Core Laboratories NV, ConocoPhillips, CARBO Ceramics Inc., Dresser-Rand Group Inc., Dril-Quip, Inc., Energy
XXI Limited, Forum Energy Technologies, Inc., Frank's International N.V., FMC Technologies, Inc., Halliburton Company, Hess Corporation, Helmerich & Payne, Marathon Oil Company, Noble Energy, Inc.,
Nabors Industries, National Oilwell Varco, Oceaneering International, Inc., Oil States International Inc., Occidental Petroleum Corporation, Patterson-UTI, Schlumberger, Ltd., Superior Energy Services, Inc.
and Tenaris in the next 3 months.
Please refer to this website for company-specific disclosures referenced in this report: https://guggenheimsecurities.bluematrix.com/sellside/Disclosures.action. Disclosure information is also available from
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RATING DEFINITIONS
BUY (B) - Describes stocks that we expect to provide a total return (price appreciation plus yield) of 15% or more within a 12-month period.
NEUTRAL (N) - Describes stocks that we expect to provide a total return (price appreciation plus yield) of plus 15% or minus 15% within a 12-month period.
SELL (S) - Describes stocks that we expect to provide a total negative return (price appreciation plus yield) of 15% or more within a 12-month period.

NR - The investment rating and price target have been temporarily suspended. Such suspensions are in compliance with applicable regulations and/or Guggenheim Securities, LLC policies.
CS - Coverage Suspended. Guggenheim Securities, LLC has suspended coverage of this company.
NC - Not covered. Guggenheim Securities, LLC does not cover this company.
Restricted - Describes issuers where, in conjunction with Guggenheim Securities, LLC engagement in certain transactions, company policy or applicable securities regulations prohibit certain types of
communications, including investment recommendations.
Monitor - Describes stocks whose company fundamentals and financials are being monitored, and for which no financial projections or opinions on the investment merits of the company are provided.
Guggenheim Securities, LLC methodology for assigning ratings may include the following: market capitalization, maturity, growth/value, volatility and expected total return over the next 12 months. The price
targets are based on several methodologies, which may include, but are not restricted to, analyses of market risk, growth rate, revenue stream, discounted cash flow (DCF), EBITDA, EPS, cash flow (CF),
free cash flow (FCF), EV/EBITDA, P/E, PE/growth, P/CF, P/FCF, premium (discount)/average group EV/EBITDA, premium (discount)/average group P/E, sum of the parts, net asset value, dividend returns,
and return on equity (ROE) over the next 12 months.
RATINGS DISTRIBUTIONS FOR GUGGENHEIM SECURITIES:
IB Serv./ Past 12Mos.
Rating Category Count Percent Count Percent
Buy 108 50.23% 21 19.44%
Neutral 102 47.44% 8 7.84%
Sell 5 2.33% 0 0.00%
OTHER DISCLOSURES
This research is for our clients and prospective clients only. Other than disclosures relating to Guggenheim Securities and its affiliates, this research is based on current public information that we consider
reliable, but we do not represent it is accurate or complete, and it should not be relied on as such. We seek to update our research as appropriate, but various regulations may prevent us from doing so.
Other than certain industry reports published on a periodic basis, the large majority of reports are published at irregular intervals as appropriate in the research analyst's judgment. Guggenheim Securities
conducts a full-service, integrated investment banking and brokerage business, and one or more of its affiliates conduct an investment management business. Guggenheim Securities is a member of SIPC
(http://www.sipc.org). Our salespeople, traders, and other professionals may provide oral or written market commentary or trading strategies to our clients and our employees trading for our own account that
reflect opinions that are contrary to the opinions expressed in this research. Guggenheim Securities or certain of its affiliates conducts an investment management business, trades for its own account, and
conducts an investment business, and may make investment decisions that are inconsistent with the recommendations or views expressed in this research.
We and our affiliates, officers, directors, and employees, excluding equity and credit analysts, will from time to time have long or short positions in, act as principal in, and buy or sell, the securities or derivatives,
if any, referred to in this research. We and our affiliates also may sell to or buy from customers on a principal basis the securities described herein. We and our affiliates also do business with, or that relates
to, companies covered in Guggenheim Securities’ research, and may have a position in the debt of the company or companies discussed herein.
This research is not an offer to sell or the solicitation of an offer to buy any security. It does not constitute a personal recommendation or take into account the particular investment objectives, financial situations,
or needs of individual clients. Clients should consider whether any advice or recommendation in this research is suitable for their particular circumstances and, if appropriate, seek professional advice, including
tax advice. The price and value of investments referred to in this research and the income from them may fluctuate. Past performance is not a guide to future performance, future returns are not guaranteed,
and a loss of original capital may occur. Fluctuations in exchange rates could have adverse effects on the value or price of, or income derived from, certain investments.
TACTICAL TRADING IDEA DISCLAIMER
Guggenheim Securities, LLC produces "Tactical Trade Ideas" that identify short-term, catalyst-driven trading opportunities impacting companies within the Firm’s coverage universe. Tactical Trade Ideas may
exist on companies in this report and may be contrary to the analyst’s published rating.
Copyright © 2014 by Guggenheim Securities, LLC, ("Guggenheim") a FINRA registered broker-dealer. All rights reserved. The contents of this report are based upon information or are obtained from sources
that Guggenheim generally considers reliable, but Guggenheim makes no representations or warranties with respect to their accuracy, completeness, timeliness, suitability or otherwise, and assumes no
responsibility to update them for subsequent events or knowledge. Guggenheim is not responsible for your use of this information.

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