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					                                                                                                            14 June 2010
                                                                                                                Americas
                                                                                                         Equity Research
                                                Energy (Integrated Oil & Gas/E&P/European Refiners/Oil & Gas Equipment &
                                                                              Services) / MARKET WEIGHT/OVERWEIGHT




                                            Macondopendium
                        Research Analysts
                                                COMMENT
                      Jonathan Wolff, CFA


                                            A Compendium of Credit Suisse Research on
                         Edward Westlake
                                            Macondo
                             Brad Handler   ■    In response to significant client requests, the Credit Suisse Energy Team
                                                 has compiled all of the research we have published related to the Macondo
                                                 oil spill into the following document.
                       Arun Jayaram, CFA
                                            ■    If you have any questions, please feel free to reach out to members of the
                                                 Energy Team.
                              Kim Fustier



                         Anish Patel, CFA




DISCLOSURE APPENDIX CONTAINS IMPORTANT DISCLOSURES, ANALYST CERTIFICATIONS, INFORMATION ON
TRADE ALERTS, ANALYST MODEL PORTFOLIOS AND THE STATUS OF NON-U.S ANALYSTS. FOR OTHER
IMPORTANT DISCLOSURES, visit www.credit-suisse.com/ researchdisclosures or call +1 (877) 291-2683. U.S.
Disclosure: Credit Suisse does and seeks to do business with companies covered in its research reports. As a result,
investors should be aware that the Firm may have a conflict of interest that could affect the objectivity of this report. Investors
should consider this report as only a single factor in making their investment decision.
                                                                                   14 June 2010




Table of contents
                                                           th
  Macondo May Have Positive Implications for Gas (Jun 11 , 2010)              3
  BP Implied Liability (after clean up) is $38bn; $60bn for the group (Jun
     th
  11 , 2010)                                                                  5
                                                   th
  BP – Lowering clean-up costs by $3bn (Jun 10 , 2010)                        9
  Offshore Drillers – Macondo Moratorium Mayhem: Lower Estimates and
                        th
  Target Prices (Jun 9 , 2010)                                               12
  BP - Macondo – Shoreline Oil Impact Now Potentially Falling (Jun 4th,
  2010)                                                                      32
  Insight Downhole – Still Cautious but Risk/Reward Skews Favorably
  (Jun 3rd, 2010)                                                            35
  BP - Potential value; but no visibility (Jun 2nd, 2010)                    41
  Delays in the Deepwater GOM, Reduce Targets (Jun 1st, 2010)                45
  Macondolypse Now Means Now – Initial Safety Rules and the 6-month
  Pause (May 30th, 2010)                                                      48
  BP - Top Kill Ongoing, Liabilities to Rise (May 28th, 2010)                 51
  Macondo Big Oil - Gulf of Mexico Project Delays (Part 2) (May 28th,
  2010)                                                                      56
  Delaying Gulf of Mexico projects (May 28th, 2010)                          59
  Credit Suisse Energy Team Goes to D.C. – Two Positives; But Remain
  Cautious on Group (May 27th, 2010)                                          62
  Macondolypse Now - Earnings Implications from Potential GoM Delays
  (May 18th, 2010)                                                           65
  Anadarko Petroleum Corp. – Good Value Despite Likely Costs (May
  17th, 2010)                                                                 73
  Global Energy Insights: (May 12th, 2010)                                    75
  Macondo Liability Conference Call Highlights (May 10th, 2010)              111
  Macondo Oil Spill Liability, a More Conservative Case (May 3th, 2010)      114
  Macondo Well Tragedy Slams Services – Earnings analyses for CAM,
  FTI, and OII (Apr 30th, 2010)                                              117
  BP (BP.L) – Strong 1Q10 results. Momentum pick up. (Apr 27th, 2010)        120
  Transocean Inc. (RIG) – What’s the Financial Impact on the Horizon?
  (Apr 26th, 2010)                                                           123




Macondopendium                                                                               2
                                                                                                  14 June 2010



US E&P: Macondo May Have Positive Implications
for Gas (June 11th, 2010)
Below is a script of a presentation that we gave recently discussing the positive long-term
implications for natural gas following the Macondo oil spill:
You have probably noticed that we have made some more positive comments on US
natural gas stocks lately so let us go through the logic.
Our positive view is mostly premised on a potentially better long-term demand outlook
amid increasing clarity about big low-cost gas shale reserves and security and safety
concerns around oil and coal supply as well as potential for M&A which we will touch on in
a minute.
We like low cost producers that can endure the cycle and make returns below $5 gas and
those include Petrohawk in the Haynesville and Eagle Ford. The Hawk is our favorite gas
name due to its giant resource base and takeout appeal.
We also like Appalachia names that have Marcellus shale positions in Pennsylvania. This
is the best play in the country and Range Resources and EQT Corp are ways to play it.
Let us begin by saying that we are not out of the woods yet for gas. Supply remains high
and is growing and demand is fairly dull so lower than mid-cycle prices are likely to persist
for much of 2010.
And we’d remind you that are forecast is $4.66 for this year compared to the current price
of $4.72, which is off its sub-$4 lows. The natural gas rig count is up a lot this year so
supply is likely to rise heading into the summer, thereby squashing any significant rallies.
Also, our long-term outlook of $7 could prove high as we think the overall cost curve is
coming down to the $6 to $6.50 range. However, the stocks are not reflecting prices much
higher than $6 anyway.
So if the near-term outlook is dull, why are we starting to like gas equities more?
Four key points to make here.
Demand
The administration HAS to think more about incentivizing use of clean, available, domestic
natural gas given the identification of massive shale resources in recent years and the
combination of the oil spill and the Massey coal accident should further shine a light on
gas.
Also, gas is much cheaper than oil and its even cheaper than coal. In fact, gas is cheaper
than coal all the way out the 5 year curve, which is very unusual on a historic basis.
Policy decisions could lead to consumer incentives to use gas through a potential energy
bill and industrial and power users have to be thinking about gas given its wider availability.
Also potential new EPA rules on SOX, NOX and mercury could cause 8% or more of the
coal fleet to shut-down. Longer-term potential for electric cars would also greatly stimulate
gas demand.
Obviously, gas demand trends may not change for several years in a major way, but a
better long-term outlook enables investors to put higher multiples on near-term cash flows.
Portfolio Rebalancing
From a stock market standpoint, nearly every PM had a very Deepwater heavy portfolio as
that was the BIG secular theme for the oil industry. Likewise, with investors shifting out of
deepwater related names they need a place to go as PMs generally don't want to be
UNDERWEIGHT energy and we think this is causing a shift to onshore related stocks and
we would suggest that onshore gas names as well as onshore oil names like Bakken and
oil sands will benefit in a significant way.


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                                                                                                 14 June 2010


M&A
The integrateds NEED to replace reserves each year and the deepwater WAS a big part
of the solution, but that solution is gone for a while so there will be intense pressure to
secure new reserves and shale gas is low-risk and provides consistent reserve
replacement.
The Majors have started to invest more in US gas, but they are way behind accounting for
less than 20% of US production.
In the last year, only XOM has made a big splash with the purchase of XTO and that may
start to look very smart should the gas demand outlook improve. Recall that last
December XOM paid $41B for XTO or 7.1x hedged EBITDA and 10.0x unhedged EBITDA
and the group is currently trading 7.2x at the strip and 5.7x at our price deck.
Also, Shell has quietly over the past three weeks made $6B in shale acreage purchases,
but others have only small positions in shale including Marathon, Total, ENI, BP and
Statoil and Chevron has none so look for more M&A for predictable shales.
Use it or Lose it!
You may have noticed the note we put out Thursday night about Cheniere Energy's plan
to provide liquefaction services for its Sabine Pass plant in Louisiana. The idea here is that
gas trades at much higher prices in Europe and Asia such that customers want to take US
gas to other markets through LNG. There may be legal issues around exporting gas but
the point is clear, if the US doesn't create markets for its cheap gas, people may try to take
it elsewhere.

Exhibit 1: MMBtu Equivalent Coal Prices by Region

                7.0
                                     Nat Gas vs CAPP Pricing Parity
                6.5

                6.0

                5.5
    $ / MMBtu




                5.0

                4.5

                4.0                                                  NYMEX Natural Gas
                                                                     NYMEX CAPP Coal
                3.5

                3.0
                      07/10 11/10 03/11 07/11 11/11 03/12 07/12 11/12 03/13 07/13
Source: Bloomberg and Credit Suisse estimates




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                                                                                                  14 June 2010



Integrated Oils: BP Implied Liability (after clean up) is
$38bn; $60bn for the group (June 11th, 2010)
We met with Tony Hayward’s chief of staff, Steve Westwell. This is a recap of the note we
published yesterday – we’ve also taken a look at the liability implied in BP - at current
prices, the market implied liability for BP is $38bn or close to $60bn for the whole operator
group (BP, APC, Mitsui).
Recent Newsflow

■   Admiral Allen has suggested that the oil spill would only take several months to clean
    up once the flow is capped.

■   NOAA water tests on the plumes show very low concentrations of the polycyclic
    aromatic hydrocarbons (PAHS's) that are most dangerous.

■   WSJ estimates the flow rate is now 20 - 40kbd.

■   Political posturing seeks to widen the Operator group's liability for economic damage
    (in light of drilling moratorium).


Commentary on BP Meeting

■   There are several reasons why the simple maths on flow is overstating the amount of
    oil that needs to be cleaned up from the surface and the shore. The LMRP is capturing
    15kbd (this will rise to 28kbd once the reverse top-kill is in operation next week), the
    use of subsea dispersants has proven highly effective at reducing the amount of oil
    that reaches the surface, the oil is light and evaporates, the skimming effort therefore
    is capturing a greater proportion of the oil that has been released than we thought.
    The pictures you see of orange sludge on CNN is the bottom of the barrel – may only
    represent a low fraction of the released oil. Although the flow rate is rising to 20 -
    40kbd if your read WSJ - BP believe the clean up costs will be $4-6bn cf $5-8bn CS.

■   On top of the $5-8bn for clean up we add $1-4bn of Clean Water Act fines ($4bn
    requires gross negligence) for a total of $6-12bn clean up. This is less than our $6-
    14bn prior estimate. We wanted to signal BP's improved confidence in a quick clean
    up. The risks remains a hurricane. BP would need to disconnect their current system
    for 10days in this event. BP are building a more hurricane resistant solution to be in
    place by mid-July (could be re-hooked up in 2-3days).

■   The relief wells are a little ahead of schedule - BP will use GPS and Magnetic Sensors
    and highly confident that the relief wells to work (early-mid August). One is at 14000
    feet, other at 8500 ft. Target is 18,000 feet. Note the last 100feet or so is critical and
    will be slow. Each relief well can be sidetracked in the event that the initial attempt
    fails. (i.e. Repeated attempts per well).

■   BP is about to make a cash call on its partners APC and Mitsui for their share of OPA
    clean up costs incurred.

■   For the investigation itself - BP highlight that this is a complex tragedy with 7 different
    failures that had to take place for the spill to occur. BP reiterated that the well design
    has been used by around 40% of the last 80 wells in the Gulf and that all procedures
    had been approved by the MMS. The complexity of the failure will make the legal
    debate long and involved, we believe.

■   Radical restructuring: BP stressed that they have significant operational cashflow and
    assets to weather this storm without the more radical proposals outlined in recent
    press articles.




Macondopendium                                                                                              5
                                                                                                     14 June 2010


Our View

■   Although positive meeting - clean up costs really do not matter. The liabilities are the
    main concern. There has been political discussion of how wide ranging the Oil
    Pollution Act will be interpreted, given the 6mth moratorium. BP are going to continue
    playing "legitimate claims" as defined under OPA. They are going to get this spill
    capped and cleaned. Once there is stability, we think the UK govt, the US oil industry
    will all get involved in framing the appropriate response to this incident. We believe BP
    will honor all stakeholder claims legitmately but these claims still need to be within the
    law.

■   BP and APC are now down 45% or have lost $100bn of market value together, $80bn
    on a relative basis versus the market. It's quite likely we will see a liability figure from a
    Louisiana tort lawyer that is very high. However, non-legitimate claims will be disputed
    for many years to come. ExxonValdez has been rumbling through courts for 20yrs.

■   The table below shows the implied claims liability in BP (after subtracting BP's share
    of our high end clean up cost estimate of $12bn). Based on a current Big Oil 2012 P/E
    multiple of 6.8x and after subtracting $8bn (65% of clean up costs and Clean Water
    Act fines), at current prices, the market implied liability for BP is $38bn or close to
    $60bn for the whole operator group (BP, APC, Mitsui). The energy sector is also
    oversold. Were the sector to rerate to recent historical multiples, but keeping the
    current market implied liability for BP, the ADR would be theoretically worth around
    $54/ADR. Each $1bn of BP's net liability is worth $0.3/ADR.




Macondopendium                                                                                                 6
                                                                        14 June 2010



Exhibit 2: Clean up cost estimates
            Oil Released                               Low     High
            Flow rate, kbd                              20      40
            Flow rate post riser cut, kbd               25      50

            % Dispersed                                50%      50%

            Flow rate, kbd                              10       20
            Flow rate post riser cut, kbd              12.5      25

            20 April-4 June, Days                      45        45
            5-June-15 August, Days                     72        72

            LMRP Efficiency                            90%      90%

            Total Barrels Released
            20 April-4 June                            450       900
            5-June-15 August                            90       180
            Total Barrels Released, KB                 540      1080
            Total Gallons Released                    22,680   45,360
            Multiple of ExxonValdez                     2.1      4.2

            20 April-4 June, Skimming Flow Rate         3        3
            5-June-15 August, Skimming Flow Rate        5        5

            Barrels Hitting Shore (Potential)
            20 April-4 June, Barrels Hitting Shore     315       765
            5-June-15 August, Barrels Hitting Shore   -270      -180
            Total Kb Hitting Shore                      45       585
            Total Gallons Hitting Shore               1,890    24,570
            Multiple of ExxonValdez                    0.2       2.3

            Onshore Clean Up                           219      3,700
            Offshore Clean Up                         4,050     4,050
            Clean Water Act                            540      4,320
            Other costs (barrier islands)              360       360
            Sub Total (onshore and offshore)          5,169    12,430
            Sub Total (excluding Clean Water Act)     4,629     8,110
            Memo : Based on Valdez Hitting Shore       717      9,320

            Prior                                              15,500
            % change                                           -3,070
Source: Company data, Credit Suisse estimates




Macondopendium                                                                    7
                                                                                        14 June 2010



Exhibit 3: Potential claims
Latest Revenue Figures                           Yr 1       Yr 2      Yr 3     Yr 4
Alabama
- Tourism                                       $3,200    $3,200    $3,200    $3,200
- Fisheries                                     $1,154    $1,154    $1,154    $1,154
                                                $4,354    $4,354    $4,354    $4,354
Louisiana
- Tourism                                       $9,300    $9,300    $9,300    $9,300
- Fisheries                                     $3,107    $3,107    $3,107    $3,107
                                                $12,407   $12,407   $12,407   $12,407
MI
- Tourism                                       $1,600    $1,600    $1,600    $1,600
- Fisheries                                      $205      $205      $205      $205
                                                $1,805    $1,805    $1,805    $1,805
Florida (Total)
- Tourism                                       $57,000   $57,000   $57,000   $57,000
- Fisheries                                     $5,000    $5,000    $5,000    $5,000

Florida (PanHandle, @ 20%)
- Tourism                                       $11,400   $11,400   $11,400   $11,400
- Fisheries                                     $1,000    $1,000    $1,000    $1,000
                                                $12,400   $12,400   $12,400   $12,400

Total Tourism                                   $25,500   $25,500   $25,500   $25,500
Total Fisheries                                 $5,466    $5,466     $5,466    $5,466
Total Tourism & Fisheries Revenues              $30,966   $30,966   $30,966   $30,966

Assumed Earnings Margin impact                   50%       50%       50%       50%

Economic Losses                                 Year 1     Year 2   Year 3    Year 4
Tourism                                          25%       20.0%    15.0%     10.0%
Fishing                                         100%        50%      25%       25%

Clean-up (High End)                             $12,430
Lost Earnings - Tourism                         $3,188    $2,550    $1,913    $1,275
Lost Earnings - Fishing                         $2,733    $1,367     $683      $683
Lost Earnings - Total                           $5,921    $3,917    $2,596    $1,958
  Lost tourism earnings as % of total             54%      65%       74%       65%
  Lost fishing earnings as % of total             46%      35%       26%       35%

Total Out of Pocket                             $18,350   $3,917    $2,596    $1,958
Discount rate                                     8%
Present Value                                   $23,849

                                                65% BP    100% BP
BP share, $MM                                   $15,502   $23,849
Per share impact, $                              $5.0       $7.6

APC Share, $MM                                  $5,962
Per Share impact, $                              $12.1
Source: Company data, Credit Suisse estimates




Macondopendium                                                                                    8
                                                                                                  14 June 2010



Integrated Oils: BP – Lowering clean-up costs by
$3bn (June 10th, 2010)
As part of our European oil & gas bus tour, we hosted a breakfast meeting with BP's Chief
of Staff Steve Westwell.

■   Quicker clean-up : Although this tragedy is ongoing, some notable newsflow has
    been released in the last days that should help put the impacts into some perspective.
    1.   The BBC report that Admiral Allen told reporters it would take only "a couple of
         months to clear the oil slick from the surface of the Gulf". This might be
         considered a surprise but reflects the fact that subsea dispersant is proving
         effective, that lighter ends are evaporating, aggressive skimming is taking place
         and the heavy sludge reaching the shore represents only a fraction of the oil
         volumes released.
    2.   The NOAA confirmed the presence of very low concentrations of sub-surface oil
         and PAHs (polycyclic aromatic hydrocarbons) at sampling depths ranging from 50
         meters to 1,400 meters.
    3.   The LMRP is working - BP is currently containing 15kbd of flow and will have the
         capacity to contain the bulk of the flow (28kbd) by mid-June once the top-kill
         manifold has been reversed.

■   Financial firepower: In its June 10th press release, BP stated it is not aware of any
    reason for the steep share price fall on June 9th. BP stressed again their financial
    strength - the company generates over $30bn of annual operating cash flow (around
    $37bn on our estimates at $80/bbl) and ended 1Q10 with a gearing ratio (Net Debt to
    Capital Employed) of 19%, below the target range of 20-30%. BP has good liquidity,
    with $5bn of cash on balance sheet and $10bn of available bank lines.

■   Lowering clean-up estimates: BP highlighted Admiral Allen’s comments on the
    relatively short timeframe to clean up the surface and beaches. However fully restoring
    the environment and natural habitats will take years. We had previously estimated the
    initial clean-up effort would take 12 months. BP has incurred $1.43bn of total costs to
    date, and expects the total costs of containment and clean-up to be around $3-6bn.
    Like for like with BP, our new estimate would be $5-8bn. Including Clean Water Act
    liabilities of $0.7-4.2bn we are lowering our estimate of clean up costs from $6-14bn to
    $6-12bn today. These are all 100% figures – as outlined in their investor call, BP
    should soon make a cash call to partners for their share (BP own 65%, APC 25%,
    Mitsui 10%). BP now has 3600 vessels involved in the offshore operation.

■   Liability still uncertain but recent progress should improve confidence levels:
    BP reiterated that they will pay all legitimate claims (as defined under OPA) and will
    not hide behind the $75m cap. 38% of our $14bn value of potential claims ($12bn
    present value) is from the fishing industry, 62% is from tourism. While it is too early to
    know the impact of this tragedy on the Gulf Coast, the ability to quickly clean beaches
    and the ongoing NOAA tests together with the $500m research grant from BP may
    help offset tourist concerns and mitigate the $7bn liability we assume for tourism
    losses. We stress that we publish these liability estimates to help frame the potential
    financial impact on BP actual liabilities could be higher or lower it is too early to tell.
                            -                                           -
    In our view, BP will likely contest unreasonable claims and this process will take many
    years.

■   Update on containment efforts: BP is funnelling 15kbd of oil from the LMRP and
    expects to raise the capture rate to 28kbd next week once the "reverse top-kill" is in
    place. BP plans to put in place a more permanent solution in mid-July, which can be
    quickly hooked up and disconnected in a hurricane (48 hours instead of 10 days). The
    two relief wells are on track for completion in August, with the first well expected in


Macondopendium                                                                                              9
                                                                                             14 June 2010


    early August and the second two weeks afterwards. BP is highly confident that it will
    successfully shut the leak with the two relief wells, and points out that there are no
    known instances of relief wells failing to plug leaks. The relief well design can be
    sidetracked if the initial attempt fails.


Exhibit 4: Clean up cost estimates
             Oil Released                                      Low     High
             Flow rate, kbd                                     12      19
             Flow rate post riser cut, kbd                      20      28

             20 April-4 June, Days                             45       45
             5-June-15 August, Days                            72       72

             LMRP Efficiency                                   90%      90%

             Total Barrels Released
             20 April-4 June                                   540       855
             5-June-15 August                                  144      201.6
             Total Barrels Released, KB                        684      1057
             Total Gallons Released                           28,728   44,377
             Multiple of ExxonValdez                            2.7      4.1

             20 April-4 June, Skimming Flow Rate                3        3
             5-June-15 August, Skimming Flow Rate               5        5

             Barrels Hitting Shore (Potential)
             20 April-4 June, Barrels Hitting Shore            405       720
             5-June-15 August, Barrels Hitting Shore          -216      -158
             Total Kb Hitting Shore                            189      562
             Total Gallons Hitting Shore                      7,938    23,587
             Multiple of ExxonValdez                           0.7       2.2

             Onshore Clean Up                                  919      3,552
             Offshore Clean Up                                4,050     4,050
             Clean Water Act                                   684      4,226
             Other costs (barrier islands)                     360       360
             Sub Total (onshore and offshore)                 6,013    12,188
             Sub Total (excluding Clean Water Act)            5,329     7,962
             Memo : Based on Valdez (All Oil Hitting Shore)   3,011     8,947

             Prior                                                     15,500
             % change                                                  -3,312
Source: Company data, Credit Suisse estimates




Macondopendium                                                                                        10
                                                                                                      14 June 2010



Exhibit 5: Estimate of liabilities for economic damages
                 Latest Revenue Figures                       Yr 1       Yr 2       Yr 3       Yr 4
                 Alabama
                 - Tourism                                 $3,200     $3,200     $3,200     $3,200
                 - Fisheries                               $1,154     $1,154     $1,154     $1,154
                                                           $4,354     $4,354     $4,354     $4,354
                 Louisiana
                 - Tourism                                 $9,300     $9,300     $9,300     $9,300
                 - Fisheries                               $3,107     $3,107     $3,107     $3,107
                                                          $12,407    $12,407    $12,407    $12,407
                 MI
                 - Tourism                                 $1,600     $1,600     $1,600     $1,600
                 - Fisheries                                 $205       $205       $205       $205
                                                           $1,805     $1,805     $1,805     $1,805
                 Florida (Total)
                 - Tourism                                $57,000    $57,000    $57,000    $57,000
                 - Fisheries                               $5,000     $5,000     $5,000     $5,000

                 Florida (PanHandle, @ 20%)
                 - Tourism                                $11,400    $11,400    $11,400    $11,400
                 - Fisheries                               $1,000     $1,000     $1,000     $1,000
                                                          $12,400    $12,400    $12,400    $12,400

                 Total Tourism                            $25,500    $25,500    $25,500    $25,500
                 Total Fisheries                           $5,466     $5,466     $5,466     $5,466
                 Total Tourism & Fisheries Revenues       $30,966    $30,966    $30,966    $30,966

                 Assumed Earnings Margin impact              50%         50%       50%        50%

                 Economic Losses                           Year 1      Year 2     Year 3     Year 4
                 Tourism                                     25%      20.00%     15.00%     10.00%
                 Fishing                                    100%         50%        25%        25%

                 Clean-up (High End)                      $12,188
                 Lost Earnings - Tourism                   $3,188     $2,550     $1,913     $1,275
                 Lost Earnings - Fishing                   $2,733     $1,367       $683       $683
                 Lost Earnings - Total                     $5,921     $3,917     $2,596     $1,958
                 Lost tourism earnings as % of total         54%        65%         74%        65%
                 Lost fishing earnings as % of total         46%        35%         26%        35%

                 Total Out of Pocket                      $18,109     $3,917     $2,596     $1,958
                 Discount rate                                 8%
                 Present Value                            $23,625

                                                          65% BP     100% BP
                 BP share, $MM                            $15,356     $23,625
                 Per share impact, $                        $4.90       $7.60

                 APC Share, $MM                            $5,906
                 Per Share impact, $                       $11.90
Source: Company data, Credit Suisse estimates




Macondopendium                                                                                                 11
                                                                                                  14 June 2010



US OFS: Offshore Drillers – Macondo Moratorium
Mayhem: Lower Estimates and Target Prices (June
9th, 2010)
■   Deepwater moratorium. On May 28, the Department of Interior (DOI) imposed a 6-
    month moratorium on the drilling of new wells in the U.S. GOM by floating rigs in water
    depths of 500 ft or greater. While certain activity is permitted (completions, workovers,
    waterfloods, gas injection/disposal wells, abandonment, wells to sustain reservoir
    pressure, and relief wells for Macondo), it appears the bulk of the floaters in the GOM
    will be impacted by the moratorium.
■   Significant impact on floater market. The GOM is one of the world’s largest
    deepwater markets, representing 24% of total deepwater capacity (31 of 127 units) and
    34% of ultra-deepwater capacity (26 of 76 units). The GOM accounts for 19% of global
    floater backlog ($21.9 billion out of $112.5 billion). The companies with the most
    contracted floaters in the GOM are Transocean (RIG) with 14, Noble (NE) with 7,
    Diamond Offshore (DO) with 6, and Ensco with 4.
■   We believe 10 to 13 rigs are at risk for early termination. There are 41 contracted
    floaters in the U.S. GOM market, including 9 newbuilds. Our detailed analysis indicates
    10 to 13 contracts for floaters could be at risk for early termination stemming from the
    invocation of ‘force majeure’ (FM) clauses. Meanwhile, we believe 13 rigs or more
    could mobilize to international markets on an interim basis until the moratorium is lifted.
■   Lowering dayrates and utilization assumptions. As a result of the moratorium, we
    further reduced our ultra-deepwater dayrate assumptions to a range of $300K to $350K
    vs. $390K previously, which will likely put rate pressure on 4th generation and mid-
    water floaters. We are now using 85% utilization for 5th and 6th gen rigs (from 90%),
    80% for 4th gen rigs (from 85%), 70% for 3rd gen rigs (from 80%), and 60% for 2nd
    gen assets (from 70%).
■   Cutting estimates and target prices. As illustrated in Exhibit 41, we lowered our 2010
    and 2011 EPS assumptions by 7% and 16%, respectively. We are now 11% and 21%
    below consensus. We reduced our DCF based target prices by 19%.
■   Reiterate cautious view. While group sentiment is decidedly bearish, we remain on
    the sidelines given our anticipation of further FM declarations as well as the knock-on
    effect to the deepwater market from rig mobilizations to the international market. Based
    on our revised estimates, the group is trading at 66% of replacement cost vs. an
    average of 52% at cyclical troughs. A potential reversion to trough level valuations on
    replacement cost would cause us to revisit our cautious thesis. Despite the moratorium,
    we continue to recommend Pride International (PDE) given their limited GOM exposure
    and superior backlog coverage. We also favor outperform rated Nabors Industries
    (NBR) and Hercules Offshore (HERO) given the apparent lifting of the shallow water
    moratorium.
■   ‘Force Majeure’ clouds visibility. Thus far, Cobalt, Anadarko, and ExxonMobil have
    attempted to invoke FM clauses in contracts. CIE and XOM declared FM on sublets on
    the Ocean Monarch and West Sirius semis. Meanwhile, APC has declared FM on their
    portion of the Monarch contract as well as term fixtures on RIG’s Discoverer Spirit
    drillship and NE’s Amos Runner semi. NE has challenged APC’s FM declaration citing
    the activities still permitted by the MMS in the GOM plus the ability of the rig to work in
    international markets. The West Sirius contract has since been assigned to BP for 4-
    years at a dayrate of $473K.
■   Extended ‘Air Pocket’ is likely. In “Energy in 2010: Endurance”, we shifted to a more
    cautious stance on the deepwater drillers in anticipation of an ‘air pocket’ in the market
    in 2011 on meaningful uncontracted newbuild additions plus signs of demand
    saturation. The ‘air pocket’ thesis appears to be playing out as there are 5 idle



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                                                                                                 14 June 2010


    deepwater rigs globally and leading-edge deepwater rates have declined by 32%. We
    believe the moratorium in the GOM will undoubtedly place further pressure on the
    floater market given the potential for early contract terminations related to FM contracts
    on more than a dozen rigs plus increased rig-on-rig competition from the mobilization
    of contracted rigs out of the GOM.
■   Lowering replacement cost estimates. We also lowered our replacement cost
    estimates for the offshore drillers to reflect lower construction costs given the slowdown
    in new order activity and the appreciation of the U.S. dollar versus foreign currencies.
    On average, our replacement cost estimates for jackups and floaters declined by 16%
    and 11%, respectively. As a result, we reduced our normalized dayrate assumptions
    for all rig types (14% on average) that are utilized in our DCF analysis.


Moratorium on Deepwater Drilling
On May 28, the Department of the Interior (DOI) placed a 6-month pause in drilling activity
to enhance safety regulations following the Macondo Oil spill. The DOI directive issued to
leaseholders on the Outer Continental Shelf: (1) restricts the drilling of any new deepwater
wells (inclusive of wellbore sidetracks and bypasses); (2) limits the spudding of any new
deepwater wells even with an ‘Application for Permit to Drill’ (APD); and (3) suspends the
approval of deepwater well permits for 6 months (May 30 through November 30). For
purposes of the directive, the DOI defined ‘deepwater’ as wells operating in water depths
greater than 500 ft. In addition, operators were required to safely stop operations and
temporarily abandon wells covered by the Moratorium.
Excluded in the Moratorium are the drilling of relief wells for emergency purposes (i.e. the
2 relief wells at Macondo), operations necessary to sustain reservoir pressure from
production wells, workover, waterflood, gas injection and disposal wells, and any drilling
operation that is related to the safe closure/abandonment of a well and well completion.
The MMS will continue to process APDs and other permits for wells not covered by the
Moratorium NTL (i.e. for shallow water activity).


GOM Floater Market
The moratorium will likely have a significant negative impact on the global market for
floaters. The GOM is the third largest floating rig market, representing 15% of global
capacity (35 out of 241 floating rigs as shown in Exhibit 6), but with a disproportionately
higher share of the deepwater and ultra-deepwater markets. We estimate the U.S. GOM
represents 24% of the global deepwater market (31 out of 127 units as illustrated in Exhibit
7) and 34% of the ultra-deepwater market (26 out of 76) units. Of the total contracted rigs
in the GOM, our analysis indicates 10 to 13 rigs are at risk for early termination through
‘force majeure’ clauses on contracts, including 3 to 4 for Transocean, 3 to 4 for Diamond
Offshore, 3 to 4 for Noble, and possibly 1 for Ensco. We see limited risk for Pride and
Seadrill based on our analysis below.




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                                                                                                                         14 June 2010



Exhibit 6: Geographic Distribution of Floaters (241              Exhibit 7: Geographic Distribution of Deepwater Rigs
floating rigs)                                                   (4,500 ft and greater)

                                Other
                                 32%

                                                                              Other                           U.S. GOM
                                                                               26%                              24%


                                                 U.S. GOM
                                                    15%


        North Sea
          16%                                                            North Sea
                                                                            6%
                                                                                                                S. America
                                              S. Am erica                                                           29%
                    W. Africa                     26%                             W. Africa
                      11%                                                           15%



Source: ODS-Petrodata, Credit Suisse estimates, Company data     Source: ODS-Petrodata, Credit Suisse estimates, Company data

Exhibit 8 and Exhibit 9 illustrate the contracted backlog for the floating rig market and
deepwater markets, respectively. The GOM represents 19% of the floating rig market
backlog ($21.9 billion out of a backlog total of $112.5 billion). Meanwhile, the GOM
accounts for 23% of the deepwater backlog ($21.5 billion out of $94.0 billion).

Exhibit 8: Floating Rig Backlog by Market                        Exhibit 9: Deepwater Rig Backlog by Market


                    Other                   U.S. GOM                                 Other
                                                                                                               U.S. GOM
                     17%                                                              18%
                                               19%                                                                23%




                                                                      North Sea
                                                                         5%
     North Sea
       11%                                                              W. Africa
                                                                           8%
        W. Africa
           7%
                                              S. Am erica
                                                  46%                                                      S. Am erica
                                                                                                               46%


Source: ODS-Petrodata, Credit Suisse estimates, Company data     Source: ODS-Petrodata, Credit Suisse estimates, Company data



Exhibit 10 illustrates the current contract status of rigs in the U.S. GOM. In total, there are
32 floaters in the GOM, with estimated backlog of $13.1 billion or 64% of total backlog.




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                                                                                                                                                   14 June 2010



Exhibit 10: GOM floater roll-off schedule
      Rig Name                       Manager                        Rig Type         Contract End     Operator                  Day Rate       Backlog ($ MM)
  1   Ocean Voyager                  Diamond Offshore                 Semi            30-Jun-2010     Walter Oil & Gas          $200,000                  $4.4
  2   Noble Paul Romano              Noble                            Semi             16-Jul-2010    Marathon                  $375,000                 $14.3
  3   Ocean Victory                  Diamond Offshore                 Semi            15-Aug-2011     Newfield Exploration      $300,000                $129.9
  4   Discoverer Deep Seas           Transocean                     Drillship           1-Feb-2011    Chevron                   $512,000                $121.9
  5   Noble Jim Thompson             Noble                            Semi              1-Mar-2011    Shell                     $505,000                $134.3
  6   Noble Amos Runner              Noble                            Semi              8-Mar-2011    Anadarko                  $440,000                $120.1
  7   Transocean Amirante            Transocean                       Semi             30-Apr-2011    Eni                       $361,000                $117.7
  8   Noble Lorris Bouzigard         Noble                            Semi            24-Jun-2011     LLOG                      $270,000                $102.9
  9   Ocean Endeavor                 Diamond Offshore                 Semi            30-Jun-2011     Devon Energy              $295,000                $114.2
 10   Ocean Saratoga                 Diamond Offshore                 Semi            30-Jun-2011     Taylor Energy             $205,000                 $79.3
 11   Noble Clyde Boudreaux          Noble                            Semi            15-Nov-2011     Noble Energy              $605,000                $317.6
 12   Transocean Marianas            Transocean                       Semi            29-Dec-2011     Eni                       $565,000                $321.5
 13   Deepwater Nautilus             Transocean                       Semi            31-Dec-2011     Shell                     $542,000                $309.5
 14   Ocean Confidence               Diamond Offshore                 Semi            31-Mar-2012     ATP Oil & Gas             $510,000                $337.6
 15   Frontier Driller               Frontier Drilling                Semi            14-May-2012     Shell                     $300,000                $211.8
 16   GSF Development Driller I      Transocean                       Semi            28-Jun-2012     BHP Billiton              $514,000                $386.0
 17   Discoverer Enterprise          Transocean                     Drillship         22-Aug-2012     BP                        $523,000               $421.5
 18   Ocean Monarch                  Diamond Offshore                 Semi            13-Mar-2013     Anadarko                  $440,000                $444.0
 19   ENSCO 8501                     Ensco                            Semi             1-May-2013     Noble Energy              $365,000                $386.2
 20   ENSCO 8500                     Ensco                            Semi              9-Jun-2013    Anadarko                  $297,500                $326.4
 21   Maersk Developer               Maersk Drilling                  Semi            10-Sep-2013     Statoil                   $450,000                $535.5
 22   GSF C.R. Luigs                 Transocean                     Drillship         21-Sep-2013     BHP Billiton              $522,000                $626.9
 23   Discoverer Americas            Transocean                     Drillship           1-Oct-2013    Statoil                   $482,000                $583.7
 24   Discoverer Spirit              Transocean                     Drillship         15-Nov-2013     Anadarko                  $505,000                $634.3
 25   GSF Development Driller II     Transocean                       Semi            27-Nov-2013     BP                        $580,000                $735.4
 26   Noble Danny Adkins             Noble                            Semi            17-Feb-2014     Shell                     $447,000                $603.5
 27   Discoverer Clear Leader        Transocean                     Drillship           19-Jul-2014   Chevron                   $500,000                $751.0
 28   West Sirius                    Seadrill                         Semi             24-Jul-2014    BP                        $473,000                $712.8
 29   Stena Forth                    Stena                          Drillship         13-Aug-2014     Hess                      $520,000                $794.0
 30   Discoverer Inspiration         Transocean                     Drillship         11-Mar-2015     Chevron                   $472,329                $820.4
 31   Deepwater Pathfinder           Transocean                     Drillship          18-Apr-2015    Eni                       $550,000                $976.3
 32   Development Driller III        Transocean                       Semi            25-Nov-2016     BP                        $403,000                $951.9
                                     Total Backlog                                                                                                  $13,126.7
Source: ODS-Petrodata, Credit Suisse estimates, Company data

In addition, there are 9 newbuilds that are contracted in the GOM under long-term
contract. These contracts represent $7.3 billion in contract backlog or 64% of the total in
the U.S. GOM.

Exhibit 11: Backlog for newbuilds under construction

     Rig Name               Manager                     Rig Type              Operator   Contract Start                 Contract End     Dayrate       Backlog
 1   Noble Jim Day          Noble                       Semi           Marathon             9-Jun-2010                   22-Sep-2014    $515,000         $806.5
 2   Deep Ocean Ascension   Pride                       Drillship      BP                   13-Jul-2010                    1-Jul-2015   $488,600         $886.3
 3   ENSCO 8502             Ensco                       Semi           Nexen                1-Aug-2010                    1-Aug-2012    $455,000         $332.6
 4   Bully I                Frontier Drilling           Drillship      Shell               14-Oct-2010                   14-Oct-2015    $300,000         $547.8
 5   ENSCO 8503             Ensco                       Semi           Cobalt             31-Dec-2010                    30-Dec-2012    $525,000         $383.3
 6   Deep Ocean Clarion     Pride                       Drillship      BP                  31-Jan-2011                   31-Dec-2015    $550,800         $988.7
 7   Bully II               Frontier Drilling           Drillship      Shell                1-Mar-2011                   26-Feb-2021    $300,000       $1,095.0
 8   DragonQuest            Vantage Drilling            Drillship      Petrobras            7-Sep-2011                    5-Sep-2019    $490,000       $1,430.8
 9   Pacific Santa Ana      Pacific Drilling Services   Drillship      Chevron            15-Sep-2011                    13-Sep-2016    $450,000         $821.3
                                  Total Backlog                                                                                                        $7,292.2

Source: ODS-Petrodata, Credit Suisse estimates, Company data

The companies with the most contracted deepwater rigs include Transocean (RIG) with 14,
Noble (NE) with 7, Diamond Offshore (DO) with 6, and Ensco with 4. The backlog details
per company are shown in Exhibit 12 and Exhibit 13.




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                                                                                                                                                                                                   14 June 2010



Exhibit 12: GOM Floater Backlog & % Total Backlog                                            Exhibit 13: GOM Floater Backlog by Company ($MM)
                                    GOM Floater Total Co. Backlog    % GOM Floater
                                                                                                                T ra nso ce a n                                                                          $ 7,786
Manager                           Backlog ($MM)            ($MM)          Backlog
                                                                                                          F ro nt ie r D rilling                                  $ 3,010
Transocean                                7,786           28,538                27%
                                                                                                                        N o ble                              1
                                                                                                                                                        $ 2,1 0
Noble                                     2,110            6,876                31%
                                                                                                                         P ride                        $1,875
Pride                                     1,875            6,434                29%
Ensco                                     1,431            2,537                56%                                     E nsc o                   $1,431

Vantage Drilling                          1,431            3,543                40%                       V ant age D rilling                     $1,431

Diamond Offshore                          1,139            8,519                13%                    D iam o nd O f fs ho re                   ,1
                                                                                                                                               $1 39

Pacific Drilling Services                   821              821               100%            P a c if ic D rilling S erv ic e s          $821

Stena                                       697            1,968                35%                                   S e a drill         $ 713

Maersk Drilling                             537            3,236                17%                                      S t e na         $ 697

Seadrill                                    713           11,430                    6%                     M a e rs k D rilling          $537

Dolphin                                     335            2,631                13%                                   D o lphin         $335

Frontier Drilling                         3,010            3,402                88%                                                 0    1,000     2,000    3,000      4,000    5,000   6,000   7,000   8,000   9,000
Total                                    21,885           79,936                27%
Source: ODS-Petrodata, Credit Suisse estimates, Company data                                  Source: ODS-Petrodata, Credit Suisse estimates, Company data



Transocean
Exhibit 14 illustrates Transocean’s contracted fleet in the U.S. GOM that includes 14 rigs.
In total, these rigs account for approximately $7.79 billion of the company’s $28.5 billion
backlog (27% of total backlog).

Exhibit 14: RIG GOM floater roll-off schedule
                                                                                                                      Market Cap               2010E Upstream
     Rig Name                      Manager           Rig Type       Contract End    Operator                              ($MM)                   Capex ($MM)                  Day Rate           Backlog ($ MM)
 1   Discoverer Deep Seas          Transocean        Drillship        1-Feb-2011    Chevron                             $143,317                      $17,300                  $512,000                    $123.9
 2   Transocean Amirante           Transocean          Semi          30-Apr-2011    Eni                                  $12,277                      $13,959                  $361,000                    $119.1
 3   Transocean Marianas           Transocean          Semi          29-Dec-2011    Eni                                  $12,277                      $13,959                  $565,000                   $323.7
 4   Deepwater Nautilus            Transocean          Semi          31-Dec-2011    Shell                               $157,598                      $21,000                  $542,000                    $311.7
 5   GSF Development Driller I     Transocean          Semi          28-Jun-2012    BHP Billiton                        $162,593                           n/a                 $514,000                   $388.1
 6   Discoverer Enterprise         Transocean        Drillship       22-Aug-2012    BP                                  $115,086                       $9,300                  $523,000                    $423.6
 7   GSF C.R. Luigs                Transocean        Drillship       21-Sep-2013    BHP Billiton                        $162,593                           n/a                 $522,000                    $629.0
 8   Discoverer Americas           Transocean        Drillship        1-Oct-2013    Statoil                              $62,507                      $12,000                  $482,000                    $585.6
 9   Discoverer Spirit             Transocean        Drillship       15-Nov-2013    Anadarko                             $22,177                       $4,796                  $505,000                    $636.3
10   GSF Development Driller II    Transocean          Semi          27-Nov-2013    BP                                  $115,086                       $9,300                  $580,000                    $737.8
11   Discoverer Clear Leader       Transocean        Drillship        19-Jul-2014   Chevron                             $143,317                      $17,300                  $500,000                    $753.0
12   Discoverer Inspiration        Transocean        Drillship       11-Mar-2015    Chevron                             $143,317                      $17,300                  $472,329                   $822.3
13   Deepwater Pathfinder          Transocean        Drillship       18-Apr-2015    Eni                                  $12,277                      $13,959                  $550,000                    $978.5
14   Development Driller III       Transocean          Semi          25-Nov-2016    BP                                  $115,086                       $9,300                  $403,000                    $953.5
                                   Total Backlog                                                                                                                                                        $7,786.1

Source: ODS-Petrodata, Credit Suisse estimates, Company data

Exhibit 15 shows RIG’s floaters by prospect type and reserve category. Of RIG’s 14 rigs in
the GOM, we believe 3 to 4 rigs are at risk of early contract termination owing to ‘force
majeure’, including the Discoverer Deep Seas, Deepwater Nautilus, GSF Development
Driller I, and Discoverer Spirit (note: Anadarko declared FM on the Spirit on June 3). We
estimate the backlog at risk for Transocean is approximately $1.5 billion or 19% of total
GOM backlog. We believe 4 recent vintage newbuilds (Discoverer Americas, Discoverer
Clear Leader, Discoverer Inspiration, and Development Driller III) have significant early
termination penalties that would limit the potential for a ‘force majeure’ declaration. In
addition, the Discoverer Enterprise, Development Driller II, and Development Driller III are
operating in support of the oil spill containment efforts at Macondo and would not be at risk
for early termination, in our opinion. Our discussion with ENI suggested that the company
has ready to drill prospects in West Africa for the Amirante and Marianas
semisubmersibles. While the company has not yet decided what to do with the Deepwater
Pathfinder drillship that is currently mobilizing to the U.S. GOM, ENI does plan to redirect
the rig to another region during the moratorium. We believe the risk of ‘force majeure’ may
be more limited on the CR Luigs drillship that is performing development drilling at the
Shenzi development project (350 to 400 MMBOE).




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                                                                                                                                        14 June 2010



Exhibit 15: Transocean’s GOM floaters by prospect
                                                                                                                            Estimated Prospect
         Rig Name                                    Block         Prospect Name                      Water Depth                         Size
   1     Discoverer Deep Seas                       GB 973                       n/a                        Standby                        n/a
   2     Transocean Amirante                        GC 254                Allegheny                            3,226               14.8 mmboe
   3     Transocean Marianas                        MC 728                    Triton                           5,380                       n/a
   4     Deepwater Nautilus                         MC 687                   Mensa                             5,292                500 mmboe
   5     GSF Development Driller I                      n/a       Completed Firefox           Yard for maintenance                         n/a
   6     Discoverer Enterprise                      MC 252                       n/a              Spill containment                        n/a
   7     GSF C.R. Luigs                             GC 653      Shenzi Development                             4,234            350-400 mmboe
   8     Discoverer Americas                        MC 540                Krakatoa                             2,036                       n/a
   9     Discoverer Spirit                          EB 602                  Nansen                             3,681                117 mmboe
  10     GSF Development Driller II                 MC 252                Macondo                              5,132                       n/a
  11     Discoverer Clear Leader                    SS 362                       n/a                           6,590                       n/a
  12     Discoverer Inspiration                     KC 736                Moccasin                             6,750                       n/a
  13     Deepwater Pathfinder                           n/a                      n/a                       En route                        n/a
  14     Development Driller III                    MC 252                Macondo                              5,159                       n/a
Source: ODS-Petrodata, Credit Suisse estimates, Company data



Noble
Exhibit 16 illustrates Noble’s contracted fleet in the U.S. GOM that includes 7 rigs. In total,
these rigs account for approximately $2.11 billion of the company’s $6.88 billion backlog
(31% of total backlog) inclusive of newbuild semi the Noble Jim Day, which is expected to
leave the shipyard this month and begin a 4-year contract in September at a dayrate of
$515K with Marathon (MRO).

Exhibit 16: NE GOM floater roll-off schedule
                                                                                            Market Cap    2010E Upstream
     Rig Name                 Manager         Rig Type   Contract End    Operator               ($MM)        Capex ($MM)    Day Rate   Backlog ($ MM)
 1   Noble Paul Romano        Noble             Semi       16-Jul-2010   Marathon              $22,007            $2,868    $375,000             $15.8
 2   Noble Jim Thompson       Noble             Semi       1-Mar-2011    Shell                $157,598           $21,000    $505,000            $136.4
 3   Noble Amos Runner        Noble             Semi       8-Mar-2011    Anadarko              $22,177            $4,796    $440,000            $121.9
 4   Noble Lorris Bouzigard   Noble             Semi      24-Jun-2011    LLOG                   Private               n/a   $270,000            $104.0
 5   Noble Clyde Boudreaux    Noble             Semi      15-Nov-2011    Noble Energy          $10,588            $2,500    $605,000           $320.0
 6   Noble Danny Adkins       Noble             Semi      17-Feb-2014    Shell                $157,598           $21,000    $447,000           $605.2
 7   Noble Jim Day            Noble             Semi      22-Sep-2014    Marathon              $22,007            $2,868    $515,000           $806.5
                              Total Backlog                                                                                                  $2,109.7

Source: ODS-Petrodata, Credit Suisse estimates, Company data

Exhibit 17 illustrates NE’s floaters by prospect type and reserve category. Of NE’s 7
contracted rigs in the GOM, we believe 3 to 4 rigs are at risk of early contract termination
owing to ‘force majeure’, including the Paul Romano, Lorris Bouzigard, Clyde Boudreaux,
and Amos Runner (note: Anadarko declared FM on the Amos Runner on June 3). That
said, we do not expect FM declarations on the Danny Adkins and Jim Day
semisubmersibles that will be used for development drilling work at Perdido (Tobago,
Great White, and Silvertip fields) and Droshky, respectively. These two rigs account for
67% of the company’s backlog in the GOM.

Exhibit 17: NE GOM floaters by prospect
                                                                                                                            Estimated Prospect
         Rig Name                                    Block               Prospect Name                    Water Depth                     Size
     1   Noble Paul Romano                          MC 993                     Innsbruck                         6,291           75-150 mmboe
     2   Noble Jim Thompson                         MC 984                           Vito                        4,038             200 mm boe
     3   Noble Amos Runner                          KC 875                        Lucius                         6,840              250 mmboe
     4   Noble Lorris Bouzigard                     MC 503                    Appaloosa                          2,642              100 mmboe
     5   Noble Clyde Boudreaux                      GC 723                    Deep Blue                          5,040              150 mmboe
     6   Noble Danny Adkins                         AC 859                       Tobago                          9,627              500 mmboe
     7   Noble Jim Day                                 n/a                     Newbuild                            n/a                     n/a
Source: MMS, Company data, Credit Suisse estimates




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                                                                                                                                         14 June 2010




Diamond Offshore
Exhibit 18 illustrates Diamond Offshore’s contracted fleet in the U.S. GOM that includes 6
rigs. In total, these rigs account for approximately $1.14 billion of the company’s $8.52
billion backlog (13% of total backlog).

Exhibit 18: DO GOM floater roll-off schedule
                                                                                            Market Cap    2010E Upstream
     Rig Name           Manager            Rig Type   Contract End   Operator                   ($MM)        Capex ($MM)     Day Rate   Backlog ($ MM)
 1   Ocean Voyager      Diamond Offshore     Semi      30-Jun-2010   Walter Oil & Gas           Private                n/a   $200,000              $5.2
 2   Ocean Endeavor     Diamond Offshore     Semi      30-Jun-2011   Devon Energy              $28,153            $4,715     $295,000            $102.9
 3   Ocean Saratoga     Diamond Offshore     Semi      30-Jun-2011   Taylor Energy              Private                n/a   $205,000            $114.2
 4   Ocean Victory      Diamond Offshore     Semi      15-Aug-2011   Newfield Exploration       $6,656            $1,600     $300,000            $131.1
 5   Ocean Confidence   Diamond Offshore     Semi      31-Mar-2012   ATP Oil & Gas                $441               $497    $510,000            $339.7
 6   Ocean Monarch      Diamond Offshore     Semi      13-Mar-2013   Anadarko                  $22,177            $4,796     $440,000            $445.7
                        Total Backlog                                                                                                         $1,138.7

Source: ODS-Petrodata, Credit Suisse estimates, Company data

Exhibit 19 illustrates DO’s floaters by prospect type and reserve category. Of DO’s 6 rigs
in the GOM, we believe 3 to 4 rigs are at risk of early contract termination owing to ‘force
majeure’, including the Ocean Endeavor, Ocean Victory, Ocean Confidence, and Ocean
Monarch (note: Cobalt, which sublet the rig from Anadarko, declared FM on the Ocean
Monarch on June 1). We believe the contract on the Ocean Saratoga will continue as
Taylor Energy is using the rig for plugging and abandonment work in less than 500 ft of
water and P&A work is permitted (even in the deepwater).

Exhibit 19: DO GOM floaters by prospect
                                                                                                                             Estimated Prospect
         Rig Name                                Block               Prospect Name                        Water Depth                      Size
     1   Ocean Voyager                          EW 834                 Hummingbird                               1,183                      n/a
     2   Ocean Endeavor                         WC 184                          n/a                       Hot Stacked                       n/a
     3   Ocean Saratoga                          MC 20                    P&A work                                 430                      n/a
     4   Ocean Victory                          GB 293                     Pyrenees                             2,095                 50 mmboe
     5   Ocean Confidence                       MC 305                   Aconcagua                               6,997                      n/a
Source: MMS, ODS-Petrodata, Credit Suisse estimates, Company data



Ensco
Exhibit 20 illustrates ENSCO’s contracted fleet in the U.S. GOM that includes 4 rigs. In
total, these rigs account for approximately $1.43 billion of the company’s $2.54 billion
backlog (56% of total backlog), including newbuild semis ENSCO 8502 and ENSCO 8503,
which will commence 2-year contracts later this year at dayrates of $455K and $525K,
respectively.

Exhibit 20: ESV GOM floater roll-off schedule
                                                                                            Market Cap    2010E Upstream
     Rig Name           Manager            Rig Type   Contract End   Operator                   ($MM)        Capex ($MM)     Day Rate   Backlog ($ MM)
 1   ENSCO 8502         Ensco                Semi       1-Aug-2012   Nexen                     $11,084            $2,500     $455,000            $332.6
 2   ENSCO 8503         Ensco                Semi      31-Dec-2012   Cobalt                     $2,460               $430    $525,000            $383.3
 3   ENSCO 8501         Ensco                Semi       1-May-2013   Noble Energy              $10,588            $2,500     $365,000            $387.6
 4   ENSCO 8500         Ensco                Semi       9-Jun-2013   Anadarko                  $22,177            $4,796     $297,500            $327.5
                        Total Backlog                                                                                                         $1,431.0

Source: ODS-Petrodata, Credit Suisse estimates, Company data

Exhibit 21 illustrates ESV’s floaters by prospect type and reserve category. Of ESV’s 4
contracted rigs in the GOM, we see limited potential for ‘force majeure’ as Anadarko plans
to relocate the ENSCO 8500 to West Africa during the moratorium. On June 1, Cobalt
reaffirmed its intention to accept delivery of the ENSCO 8503 newbuild in Q410. While
NBL was utilizing ENSCO 8501 at its Santa Cruz prospect, we believe the company will
likely keep the rig for future work in the Mediterranean (Israel) or West Africa. Nexen has a
two-year contract on the ENSCO 8502 newbuild that is scheduled for delivery in Q310. We
believe Nexen was planning to use the rig for exploration drilling in the GOM. While it is
unclear whether Nexen will declare FM for the rig given the timing of the newbuild delivery,



Macondopendium                                                                                                                                      18
                                                                                                                                                             14 June 2010


we would note that Nexen also contracted 1.5 years of rig time on the ENSCO 8501 rig
under its rig share agreement with Noble Energy.

Exhibit 21: ESV GOM floaters by prospect
                                                                                                                                            Estimated Prospect
        Rig Name                                           Block                  Prospect Name                        Water Depth                        Size
    1   ENSCO 8502                                           n/a                       Newbuild                                n/a                         n/a
    2   ENSCO 8503                                           n/a                       Newbuild                                n/a                         n/a
    3   ENSCO 8501                                        MC 519                      Santa Cruz                             6,500                  130 mmboe
    4   ENSCO 8500                                        GB 877                       Red Hawk                              5,334                 39.5 mmboe
Source: MMS, ODS-Petrodata, Credit Suisse estimates, Company data



Seadrill
Exhibit 22 illustrates Seadrill’s contracted fleet in the U.S. GOM that includes the West
Sirius rig. In total, the West Sirius accounts for $713 million of the company’s $11.4 billion
backlog (6% of total backlog). We see limited backlog risk as the contract on the West
Sirius semi was just assigned from Devon to BP for 4 years at a dayrate of $473K. On a
near-term basis, we believe the West Sirius will be used for support purposes at Macondo.

Exhibit 22: SDRL GOM floater roll-off schedule
                                                                                                         Market Cap     2010E Upstream
   Rig Name                  Manager               Rig Type          Contract End Operator                   ($MM)         Capex ($MM)      Day Rate        Backlog ($ MM)
 1 West Sirius               Seadrill                Semi             24-Jul-2014 BP                       $278,595            $22,046      $473,000                $712.8
                             Total Backlog                                                                                                                          $712.8

Source: ODS-Petrodata, Credit Suisse estimates, Company data

Exhibit 23 illustrates Pride’s contracted fleet in the U.S. GOM that includes 2 newbuild
drillships, the Deep Ocean Ascension and the Deep Ocean Clarion. The Deep Ocean
Ascension is scheduled to start operations in July, while the Deep Ocean Clarion is
available in early 2011. In total, the backlog from these 2 newbuilds accounts for $1.88
billion of the company’s $6.4 billion backlog (29% of total backlog). Similar to Transocean,
we believe the contracts on the Ascension and Clarion have significant early termination
penalties that would limit the potential for a ‘force majeure’ declaration from BP on either
unit.


Pride

Exhibit 23: PDE GOM floater roll-off schedule
                                                                                                   2010E Upstream Market Cap   2010E Upstream
Rig Name               Manager         Rig Type     Contract Start      Contract End    Operator      Capex ($MM)     ($MM)       Capex ($MM)     Dayrate    Backlog ($MM)
Deep Ocean Ascension   Pride           Drillship       13-Jul-2010         1-Jul-2015        BP            $9,300   $115,086           $9,300    $488,600            $886.3
Deep Ocean Clarion     Pride           Drillship      31-Jan-2011        31-Dec-2015         BP            $9,300   $115,086           $9,300    $550,800            $988.7
                       Total Backlog                                                                                                                               $1,875.0

Source: ODS-Petrodata, Credit Suisse estimates, Company data



Extended ‘Air Pocket’ Likely
In Credit Suisse’s “Energy in 2010: Endurance” outlook report, we highlighted our concern
the deepwater rig market could hit an ‘air pocket’ in 2011 given signs of demand saturation
plus meaningful uncontracted capacity additions. We also felt Petrobras’ insatiable thirst
for deepwater rigs might be satisfied following recent awards and the shift toward a
newbuild strategy emphasizing local content. Recent contract activity plus anecdotal
commentary from contractors suggest the timing of our ‘air pocket’ thesis is playing out
faster than anticipated as 5 deepwater rigs went idle prior to the blow-out at Macondo.




Macondopendium                                                                                                                                                         19
                                                                                                                                                                                                                                                                                14 June 2010



Exhibit 24: Idle Deepwater Rigs
Rig Name                                                                                     Rig Water Depth (ft.)                               Manager                                                        Idle Date
Aban Abraham                                                                                                 6,600                     Aban Offshore                                                                   Apr-10
Jim Cunningham                                                                                               4,600                     Transocean                                                                      Apr-10
Sedco 709                                                                                                    5,000                     Transocean                                                                      Feb-10
Transocean Richardson                                                                                        5,000                     Transocean                                                                      Jun-10
Deep Venture                                                                                                 5,500                     Larsen Oil & Gas                                                                May-10
Source: ODS-Petrodata, Company data, Credit Suisse estimates
Note: Previously idle Transocean Rather to substitute in for Transocean Richardson for remainder of
contract on Richardson


Of the total contracted rigs in the GOM, our analysis indicates that 10 to 13 rigs are at risk
for early termination through ‘force majeure’ clauses on contracts following the moratorium
in the GoM. We believe the potential idling of 13 rigs in the U.S. GOM plus the mobilization
of several additional units will have a knock-on effect on international markets. As such,
we are reducing our EPS estimates and target prices to incorporate lower dayrate and
utilization forecasts given the further softening in deepwater supply-demand fundamentals.


Rising Supply
Exhibit 25 and Exhibit 26 illustrate the historical growth in the deepwater and
ultra-deepwater markets. Including newbuilds, the deepwater and ultra-deepwater fleets
are scheduled to grow at long-term compound annual growth rates of 11% and 16% from
2000 to 2013, with significant supply additions in the 2010 to 2012 time frame.

Exhibit 25: Deepwater Market Historical and Projected                                                                                           Exhibit 26: Ultra-Deepwater Market Historical and
Newbuild Supply                                                                                                                                 Projected Newbuild Supply
                        200                                                                                                                                                   160

                        180
                                                                                                                                                                              140
                        160
                                                                                                                                                 Ultra-Deepwater Rig Supply




                                                                                                                                                                              120
 Deepwater Rig Supply




                        140

                        120                                                                                                                                                   100

                        100                                                                                                                                                    80
                         80
                                                                                                                                                                               60
                         60
                                                                                                                                                                               40
                         40

                         20                                                                                                                                                    20

                         0
                                                                                                                                                                                0
                                                                                                                             2011E


                                                                                                                                     2013E
                              1985


                                     1987


                                            1989


                                                   1991


                                                          1993


                                                                 1995


                                                                        1997


                                                                               1999

                                                                                      2001


                                                                                               2003


                                                                                                      2005


                                                                                                               2007


                                                                                                                      2009




                                                                                                                                                                                                                                                                                 2011E


                                                                                                                                                                                                                                                                                         2013E
                                                                                                                                                                                    1985


                                                                                                                                                                                           1987


                                                                                                                                                                                                  1989


                                                                                                                                                                                                         1991


                                                                                                                                                                                                                1993


                                                                                                                                                                                                                        1995


                                                                                                                                                                                                                               1997


                                                                                                                                                                                                                                      1999


                                                                                                                                                                                                                                             2001


                                                                                                                                                                                                                                                    2003


                                                                                                                                                                                                                                                           2005


                                                                                                                                                                                                                                                                  2007


                                                                                                                                                                                                                                                                         2009




Source: ODS-Petrodata, Credit Suisse estimates.                                                                                                 Source: ODS-Petrodata, Credit Suisse estimates.

Exhibit 27 and Exhibit 28 illustrate the timing and magnitude of newbuild additions
forecast, including a split between contracted and uncontracted units. We believe
deepwater rig supply is finally poised to catch-up with demand in 2011 as 19 ultra-
deepwater newbuilds (3 in 2010 and 16 in 2011) remain uncontracted.




Macondopendium                                                                                                                                                                                                                                                                                   20
                                                                                                                                           14 June 2010



Exhibit 27: Projected Floater Fleet Growth                            Exhibit 28: Floater Additions by Year
 30                                                                    12
                                                  Speculative                                                                              Speculative

 25                                               Contracted           10           2                                                      Contracted
                                                                                           1

              4                  16
 20                                                                     8
                                                                                                                5


 15                                                                     6

                                                                                                  2
                                                   6                                9      9                           5      3      1
 10                                                                     4                                4
             19

                                 13                                                                             5
  5                                                                     2                         4                                  4
                                                   8                         1                                                3             1
                                                                                                         2             2
                                                                             1                                                              1       1
  0                                                                     0
             2010                2011             2012                      Q210   Q310   Q410   Q111   Q211   Q311   Q411   Q112   Q212   Q312   Q412


Source: ODS-Petrodata, Credit Suisse estimates.                       Source: ODS-Petrodata, Credit Suisse estimates.

Exhibit 29 illustrates the projected increase in the worldwide competitive floater fleet
between now and the end of 2013. During this time period, we expect capacity to increase
by 28% to 310 rigs globally, while the deepwater rig fleet is set to rise by 52%. This is a
meaningful increase in capacity in a short time period, which will likely put pressure on
rates given the sizeable number of speculative rigs in the newbuild order book and soft
tendering activity.

Exhibit 29: Projected Increase In Floater Fleet
Year                                                      Floaters                               % Change
Competitive Floater Fleet                                       243
2010 Additions                                                   23                                       9%
2011 Additions                                                   29                                      11%
2012 Additions                                                   14                                       5%
2013 Additions                                                    1                                     0.3%
Projected Fleet                                                 310                                      28%
Source: ODS-Petrodata, Credit Suisse estimates

Exhibit 30 illustrates the ownership profile of the floaters in the newbuild order book.
According to ODS-Petrodata, 27 contractors are constructing a total of 70 rigs. We
estimate 29 of the 70 newbuilds (41%) will be in the hands of newer market entrants such
as Pacific Drilling, IPC, and Sevan Drilling, which will result in significant industry de-
consolidation and increase the likelihood of rig-on-rig competition. In addition, half of the
speculative newbuilds are in the hands of newer market entrants (14 of 27 speculative
rigs).




Macondopendium                                                                                                                                           21
                                                                                                                                                                                                                                                                                                                                                  14 June 2010



Exhibit 30: Ownership Profile of Floating Rig Order Book

  7
                                                                                                                                                                                                                                                                                                       Speculative
  6
                                                                                                                                                                                                                                                                                                       Contracted
  5


  4           2                      2
                                                       1
  3   6
                          5                                   3                    3                                             1
  2                                                                   4
              3                      3                 3                                                      3                          1                                      1     1                                     1
  1                                                                                                                              2                 2                  2                            2               2                    2               2
                                                              1                    1                                                     1                                      1     1                                     1                                        1         1                1      1       1          1               1
  0
                                                                                  Pacific Drilling Services




                                                                                                                                                                                      Petroserv
                          Schahin

                                    Vantage Drilling

                                                       COSL

                                                              Ensco

                                                                      Ocean Rig




                                                                                                                                         Atwood
                                                                                                              Odfjell Drilling




                                                                                                                                                  Frontier Drilling




                                                                                                                                                                                                  Queiroz Galvao




                                                                                                                                                                                                                                       Sevan Drilling

                                                                                                                                                                                                                                                        Transocean

                                                                                                                                                                                                                                                                     Etesco
              Odebrecht




                                                                                                                                                                      Gazflot

                                                                                                                                                                                IPC




                                                                                                                                                                                                                                                                                                KNOC



                                                                                                                                                                                                                                                                                                               Rosneft
                                                                                                                                                                                                                   Saipem
      Delba




                                                                                                                                 Pride




                                                                                                                                                                                                                                                                              Island Offshore



                                                                                                                                                                                                                                                                                                       Noble




                                                                                                                                                                                                                                                                                                                                          Stena
                                                                                                                                                                                                                                                                                                                         Songa Offshore
                                                                                                                                                                                                                            Seadrill




Source: ODS-Petrodata, Credit Suisse estimates



Saturation in Demand
While the international deepwater market is tight, there is a fair amount of rig availability in
2011 as shown in Exhibit 31. In total, we estimate there is 33 rig years worth of deepwater
rig availability next year excluding rigs that might be available as a result of the moratorium




Macondopendium                                                                                                                                                                                                                                                                                                                                             22
                                                                                                                                                                                          14 June 2010



Exhibit 31: Supply-Demand in Deepwater Rig Fleet
                        Days Available: Deepwater Rigs (>4,499 ft. WD)


Already Delivered                                                      2010E                        2011E                   2012E
Days Uncontracted                                                       1,849                       8,774                  16,603
Total Days Available                                                   45,521                   46,720                     46,848
Percent Available                                                       4.1%                        18.8%                   35.4%



Under Construction
Days Uncontracted                                                             262                   3,100                     7,866
Total Days Available                                                    2,080                   12,140                     20,070
Percent Available                                                      12.6%                        25.5%                   39.2%



Total Deepwater Fleet
Days Uncontracted                                                       2,111                   11,874                     24,469
Total Days Available                                                   47,601                   58,860                     66,918
Percent Available                                                       4.4%                        20.2%                   36.6%



Number of Rigs Available                                                        6                           33                      67
Number of Rigs Contracted                                                     125                      129                        116
Total                                                                         130                      161                        183
Source: ODS-Petrodata, Credit Suisse estimates

Despite the meaningful improvement in oil prices, there has been a significant decline in
contract activity in recent quarters, which points to demand saturation. Once the newbuilds
in the order book are delivered, we estimate that the industry will need to sign 37 rig years
of new contracts quarterly to absorb excess capacity. We believe the level of contract
signings could be below trend for several quarters as operators digest newbuilds and other
rigs under long-term contracts as well as the impact from the deepwater moratorium.

Exhibit 32: New Contract Signings
                       200

                       180

                       160

                       140
    Rig Years Signed




                       120

                       100

                       80

                       60

                       40

                       20

                        0
                             Q105
                                    Q205
                                           Q305

                                                  Q405
                                                         Q106

                                                                Q206
                                                                       Q306
                                                                               Q406
                                                                                      Q107

                                                                                             Q207
                                                                                                     Q307

                                                                                                             Q407
                                                                                                                    Q108

                                                                                                                           Q208
                                                                                                                                  Q308
                                                                                                                                         Q408
                                                                                                                                                Q109

                                                                                                                                                       Q209
                                                                                                                                                              Q309

                                                                                                                                                                     Q409
                                                                                                                                                                            Q110
                                                                                                                                                                                   Q210




Source: ODS-Petrodata, Credit Suisse estimates.




Macondopendium                                                                                                                                                                                     23
                                                                                                                                          14 June 2010


Reduction in Dayrates and Contract Lengths
Exhibit 33 illustrates contract activity in the ultra-deepwater market since 2008. Note the
decline in the number of new contracts, dayrates, and contract lengths. According to ODS-
Petrodata, there were 33 ultra-deepwater contracts signed in 2008 at an average dayrate
of $520K and an average term of 4.1 years. In 2009, there were only 12 contracts signed
at an average dayrate of $469K (down 10% from 2008 levels) and an average term of 3.2
years. Year-to-date, the average contracted dayrate has declined to $407K or down 13%
from 2009 levels.

Exhibit 33: Recent Deepwater Fixtures
                  Rig Name         Fixture Date          Operator            Water Depth     Length     Day rate
  1   Pride Drsh Tbn3              24-Jan-2008    Petrobras                    10,000        5 years      $410,000
  2   Pride Drsh Tbn1              29-Jan-2008    BP                           10,000        5 years      $480,000
  3   Eirik Raude                   8-Feb-2008    Tullow Oil                   10,000        3 years      $637,000
  4   GSF Explorer                 15-Feb-2008    Marathon                      7,800        2 years      $510,000
  5   Deepwater Millennium         19-Feb-2008    Anadarko                     10,000        3 years      $535,000
  6   ENSCO 8503                    7-Mar-2008    Cobalt                        8,500        2 years      $510,000
  7   Deepwater Pathfinder         11-Mar-2008    Lukoil                        7,500         1 well      $630,000
  8   Deepwater Nautilus           27-Mar-2008    Shell                         8,000        3 years      $535,160
  9   Dhirubhai Deepwater KG2      31-Mar-2008    Reliance                     10,000        5 years      $510,000
 10   Noble Paul Wolff              1-Apr-2008    Petrobras                     9,200        5 years      $428,000
 11   Noble Roger Eason             1-Apr-2008    Petrobras                     7,200        6 years      $347,000
 12   MPF-01                       14-Apr-2008    Petrobras                    10,000        3 years      $575,000
 13   West Taurus                  14-Apr-2008    Petrobras                    10,000        6 years      $630,000
 14   West Eminence                14-Apr-2008    Petrobras                    10,000        6 years      $600,000
 15   West Orion                   14-Apr-2008    Petrobras                    10,000        6 years      $600,000     33 contacts @
 16   West Polaris                 16-Apr-2008    ExxonMobil                   10,000         1 year      $615,000   average dayrate of
 17   West Aquarius                16-Apr-2008    ExxonMobil                   10,000         1 year      $513,700    $519,844 and 4.1
 18   Pride Drsh Tbn2              1-May-2008     BP                           10,000        5 years      $539,000       year term
 19   Transocean Drsh Tbn5         6-May-2008     Reliance                     10,000        5 years      $557,000
 20   Sevan Brasil                  2-Jun-2008    Petrobras                     7,874        6 years      $406,000
 21   Scorpion Semi Tbn1            2-Jun-2008    Petrobras                     7,874        6 years      $416,000
 22   Delba V                       2-Jun-2008    Petrobras                     8,000        6 years      $382,000
 23   Delba VI                      2-Jun-2008    Petrobras                     8,000        6 years      $382,000
 24   GSF Development Driller II   19-Jun-2008    BP                            7,500        5 years      $580,000
 25   Petrobras 10000              23-Jun-2008    Petrobras                    10,000       10 years      $410,000
 26   Noble Jim Day                24-Jun-2008    Marathon                     12,000        2 years      $515,000
 27   West Sirius                  27-Jun-2008    Devon Energy                 10,000        2 years      $475,000
 28   Transocean Marianas           2-Jul-2008    Eni                           7,000        2 years      $565,000
 29   Deepwater Pathfinder          8-Jul-2008    Eni                           7,500        5 years      $650,000
 30   Deepwater Navigator          15-Jul-2008    Petrobras                     7,200        5 years      $382,000
 31   Deepwater Expedition         30-Jul-2008    Petronas Carigali            10,000        3 years      $640,000
 32   ENSCO 7500                   29-Aug-2008    Chevron                       8,000        1 years      $550,000
 33   Transocean HHI Drsh Tbn1     29-Oct-2008    ExxonMobil                   10,000        5 years      $640,000
 34   Noble Clyde Boudreaux         8-Jan-2009    Shell                        10,000      4 months       $605,000
 35   Platinum Explorer             2-Mar-2009    ONGC                         12,000        5 years      $585,000
 36   Titanium Explorer             2-Mar-2009    Petrobras                    12,000        8 years      $550,000
 37   Leiv Eiriksson               19-Mar-2009    Petrobras                     7,500        3 years      $540,000     12 contacts @
 38   Cajun Express                20-Jul-2009    Petrobras                     8,500        5 years      $490,000   average dayrate of
 39   Pride South Pacific          27-Jul-2009    Noble Energy                  6,500         1 year      $321,000    $468,550 and 3.2
 40   Sedco Express                25-Aug-2009    Noble Energy                  7,500      15 months      $530,000       year term
 41   Ocean Courage                16-Sep-2009    Petrobras                    10,000        5 years      $410,000
 42   Deepwater Horizon            29-Sep-2009    BP                            8,000        3 years      $496,800
 43   Noble Paul Romano            22-Oct-2009    Marathon                      6,000       4 months      $375,000
 44   Scarabeo 5                   11-Nov-2009    Statoil                       6,233        3 years      $399,800
 45   GSF Celtic Sea               18-Dec-2009    ExxonMobil                    5,750        3 years      $320,000
 46   West Gemini                  12-Feb-2010    N/A                          10,000        2 years      $445,000     11 contacts @
 47   Ocean Baroness                2-Mar-2010    Petrobras                     6,500        3 years      $280,000   average dayrate of
 48   Ocean Clipper                 2-Mar-2010    Petrobras                     7,875        5 years      $305,000    $407,136 and 3.3
 49   Ocean Valor                   2-Mar-2010    Petrobras                     7,500        3 years      $450,000       year term
 50   Alpha Star                    3-Mar-2010    Petrobras                     9,000        6 years      $416,000
 51   West Venture                  6-Apr-2010    Statoil                       5,906        5 years      $390,000
 52   Ocean Rover                  30-Apr-2010    Murphy                        6,500      6 months       $387,500
 53   West Phoenix                 30-Apr-2010    Total                        10,000        3 years      $445,000
 54   Pacific Santa Ana            6-May-2010     Pacific Drilling Service     10,000        5 years      $450,000
 55   Deepwater Frontier           7-May-2010     Transocean                   10,000        2 years      $475,000
 56   Discoverer Enterprise        7-May-2010     Transocean                    8,450       1.5 years     $435,000
      Average                                                                              3.7 years      $486,714

Source: ODS-Petrodata, Credit Suisse estimates.



Revising Utilization and Dayrate Trends
Exhibit 34 and Exhibit 35 illlustrate historical utilization and leading-edge dayrates trends
for the deepwater drillship and 4th/5th generation semisubmersible markets. Despite
nearly full utilization for both asset classes, leading-edge rates have begun to fall given the
lack of new contract activity and rising rig-on-rig competition.




Macondopendium                                                                                                                                     24
                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             14 June 2010


                                                                                                                                                                                                                                                                                                                                                                           th            th
Exhibit 34: WW Drillship Dayrates vs. Utilization                                                                                                                                                                                                                                     Exhibit 35: WW 4 /5 Gen Semi Dayrates vs. Utilization
                         $700,000                                                                                                                                                                                                                 100.00%                                                         $600,000
                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                100.00%


                                                                                                                                                                                                                                                  90.00%
                         $600,000
                                                                                                                                                                                                                                                                                                                  $500,000
                                                                                                                                                                                                                                                  80.00%                                                                                                                                                                                                                                                                        80.00%

                         $500,000
                                                                                                                                                                                                                                                  70.00%




                                                                                                                                                                                                                                                                                      WW 4th+ Gen SemiDayrates




                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         WW 4th+ Gen Semi Utilization
                                                                                                                                                                                                                                                                                                                  $400,000
WW Drillship Dayrates




                                                                                                                                                                                                                                                           WW Drillship Utilization
                                                                                                                                                                                                                                                  60.00%                                                                                                                                                                                                                                                                        60.00%
                         $400,000


                                                                                                                                                                                                                                                  50.00%                                                          $300,000


                         $300,000
                                                                                                                                                                                                                                                  40.00%                                                                                                                                                                                                                                                                        40.00%

                                                                                                                                                                                                                                                                                                                  $200,000

                         $200,000                                                                                                                                                                                                                 30.00%


                                                                                                                                                                                                                                                  20.00%                                                                                                                                                                                                                                                                        20.00%
                                                                                                                                                                                                                                                                                                                  $100,000
                         $100,000

                                                                                                                                                                                                                                                  10.00%


                               $0                                                                                                                                                                                                                 0.00%                                                                 $0                                                                                                                                                                                                      0.00%
                                    Jan-89


                                             Jan-90


                                                      Jan-91


                                                               Jan-92


                                                                        Jan-93


                                                                                 Jan-94


                                                                                             Jan-95


                                                                                                      Jan-96


                                                                                                               Jan-97


                                                                                                                        Jan-98


                                                                                                                                 Jan-99


                                                                                                                                           Jan-00


                                                                                                                                                     Jan-01


                                                                                                                                                              Jan-02


                                                                                                                                                                       Jan-03


                                                                                                                                                                                Jan-04


                                                                                                                                                                                            Jan-05


                                                                                                                                                                                                     Jan-06


                                                                                                                                                                                                              Jan-07


                                                                                                                                                                                                                       Jan-08


                                                                                                                                                                                                                                Jan-09


                                                                                                                                                                                                                                         Jan-10




                                                                                                                                                                                                                                                                                                                             Jan-90


                                                                                                                                                                                                                                                                                                                                      Jan-91


                                                                                                                                                                                                                                                                                                                                               Jan-92


                                                                                                                                                                                                                                                                                                                                                        Jan-93


                                                                                                                                                                                                                                                                                                                                                                 Jan-94


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                                                                                                                                                                                                                                                                                                                                                                                      Jan-96


                                                                                                                                                                                                                                                                                                                                                                                               Jan-97


                                                                                                                                                                                                                                                                                                                                                                                                         Jan-98


                                                                                                                                                                                                                                                                                                                                                                                                                  Jan-99


                                                                                                                                                                                                                                                                                                                                                                                                                           Jan-00


                                                                                                                                                                                                                                                                                                                                                                                                                                    Jan-01


                                                                                                                                                                                                                                                                                                                                                                                                                                             Jan-02


                                                                                                                                                                                                                                                                                                                                                                                                                                                      Jan-03


                                                                                                                                                                                                                                                                                                                                                                                                                                                               Jan-04


                                                                                                                                                                                                                                                                                                                                                                                                                                                                        Jan-05


                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  Jan-06


                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           Jan-07


                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    Jan-08


                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              Jan-09


                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       Jan-10
                                                                                          WW Drillship Dayrates                                                                          utilization                                                                                                                                                                      WW 4th or Higher Gen Semi Dayrates                                                                 Utilization


Source: ODS-Petrodata, Credit Suisse estimates.                                                                                                                                                                                                                                       Source: ODS-Petrodata, Credit Suisse estimates.

While there has been very limited contract activity, leading-edge dayrates for 5th
generation rigs have declined to the $410,000 to $450,000 range. We see the potential for
further deterioration given the dislocation of several rigs in the GOM following the
moratorium plus a meaningful number of uncontracted capacity additions. We believe
ultra-deepwater spot dayrates could decline to a range of $300,000 to $350,000 during
2011 given the meaningful number of uncontracted newbuilds, which will likely put rate
pressure on 4th generation and mid-water floaters.
We estimate dayrates will fall to $300,000 for a 5th generation semi and $350,000 for an
ultra-deepwater drillship in 2010 and 2011. We then looked at the long-term relationship
from 1990 to 2008 between 2nd, 3rd, and 4th generation floaters and 5th generation floaters
and applied the average ratio to each floater by geographic market. For example, dayrates
on 2nd generation floaters in the U.S. GOM have averaged 47% of the dayrate of a 5th
generation semi on a long-term basis. As a result, we used a dayrate of approximately
$135,000 for a 2nd generation floater in the U.S. GOM.
                                                               nd                                                                                                                                                                                                                                                                                       rd
Exhibit 36: 2                                                           Generation Semi Dayrates as a Percentage                                                                                                                                                                      Exhibit 37: 3 Generation Semi Dayrates as a Percentage
                          th                                                                                                                                                                                                                                                                                       th
of 5 Generation Semi Dayrates in the U.S. GOM                                                                                                                                                                                                                                         of 5 Generation Semi Dayrates in the U.S. GOM
     100%                                                                                                                                                                                                                                                                                  120%

                        90%                                                                                                                                                                                                                                                                110%
                                                                                                                                                                                                                                                                                           100%                                                                                                                                                       Average
                        80%
                                                                                                                                                                                                                                                                                                                 90%                                                                                                                                    74%
                                                                                                                                                    Average
                        70%
                                                                                                                                                      47%                                                                                                                                                        80%
                        60%                                                                                                                                                                                                                                                                                      70%
                        50%                                                                                                                                                                                                                                                                                      60%

                        40%                                                                                                                                                                                                                                                                                      50%
                                                                                                                                                                                                                                                                                                                 40%
                        30%
                                                                                                                                                                                                                                                                                                                 30%
                        20%
                                                                                                                                                                                                                                                                                                                 20%
                        10%                                                                                                                                                                                                                                                                                      10%
                        0%                                                                                                                                                                                                                                                                                       0%
                          1993                        1995                       1997                          1999                       2001                     2003                       2005                     2007                       2009                                                             1993                        1995                       1997                          1999               2001                       2003                       2005                2007                       2009

Source: ODS-Petrodata, Credit Suisse estimates                                                                                                                                                                                                                                        Source: ODS-Petrodata, Credit Suisse estimates




Macondopendium                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          25
                                                                                                                                                                                                                                                               14 June 2010



Exhibit 38: Revised Semisubmersible Dayrate Forecasts for 2011 and 2012
Asset Type                                                                                                                        Previous Dayrate Estimate                                                                                               Revised Estimate
2nd Gen Semi                                                                                                                                                                   $160,000                                                                          $135,000
3rd Gen Semi                                                                                                                                                                   $225,000                                                                          $175,000
4th Gen Semi                                                                                                                                                                   $275,000                                                                          $225,000
5th Gen Semi                                                                                                                                                                   $350,000                                                                          $300,000
North Sea Standard Semi                                                                                                                                                        $225,000                                                                          $200,000
Norwegian High Spec Semi                                                                                                                                                       $350,000                                                                          $300,000
Source: Company data, Credit Suisse estimates

Exhibit 39: Revised Drillship Dayrate Forecasts for 2011 and 2012
Asset Type                                                                                                                        Previous Dayrate Estimate                                                                                                Revised Dayrate
Conventionally Moored Drillship                                                                                                                                                $250,000                                                                          $200,000
Drillship (5,001 to 7,000’)                                                                                                                                                    $350,000                                                                          $300,000
Drillship (>7,000’)                                                                                                                                                            $390,000                                                                          $350,000
Source: Company data, Credit Suisse estimates

We have also reduced our utilization assumptions to reflect the knock-on effect of more
capacity in international markets. For floaters, we used 85% utilization for 5th and 6th gen
rigs (from 90%), 80% for 4th gen rigs (from 85%), 70% for 3rd gen rigs (from 80%), and
60% for 2nd gen assets (from 70%). On a long-term basis, the average utilization for
semisubmersibles has been 84% as shown in Exhibit 40.

Exhibit 40: WW Semi Historical Dayrates & Utilization
                    $440,000                                                                                                                                                                                                 100%
                                                                                                                                                      Average = 84%
                    $400,000                                                                                                                                                                                                 90%

                    $360,000
                                                                                                                                                                                                                             80%

                    $320,000
                                                                                                                                                                                                                             70%

                    $280,000
                                                                                                                                                                                                                                    WW Semi Utilization
 WW Semi Dayrates




                                                                                                                                                                                                                             60%
                    $240,000
                                                                                                                                                                                                                             50%
                    $200,000
                                                                                                                                                                                                                             40%
                    $160,000

                                                                                                                                                                                                                             30%
                    $120,000

                                                                                                                                                                                                                             20%
                     $80,000


                     $40,000                                                                                                                                                                                                 10%


                         $0                                                                                                                                                                                                  0%
                               Jan-90

                                        Jan-91

                                                 Jan-92

                                                          Jan-93

                                                                   Jan-94

                                                                            Jan-95

                                                                                     Jan-96

                                                                                              Jan-97

                                                                                                       Jan-98

                                                                                                                Jan-99

                                                                                                                         Jan-00

                                                                                                                                  Jan-01

                                                                                                                                           Jan-02

                                                                                                                                                    Jan-03

                                                                                                                                                             Jan-04

                                                                                                                                                                      Jan-05

                                                                                                                                                                                Jan-06

                                                                                                                                                                                         Jan-07

                                                                                                                                                                                                  Jan-08

                                                                                                                                                                                                           Jan-09

                                                                                                                                                                                                                    Jan-10




                           WW Semisubmersible Dayrates                                             WW Semisubmersible Utilization                                       WW Avg. Semisubmersible Utilization


Source: ODS-Petrodata, Credit Suisse estimates

Exhibit 41 illustrates our revised earnings for the offshore drillers in our coverage group
compared to our prior forecasts. On average, we estimate the earnings power of the group
will be down 7% and 16% in 2010 and 2011 versus our prior forecasts. As a result of our
earnings revisions, we are lowering our DCF-derived 12-month target prices by an
average of 19%, with the largest reductions to RIG (-32% from $92 to $63), DO (-27%
from $78 to $57), ESV (-23% from $52 to $40), NE (-23% from $52 to $40) and HERO (-
23% from $6.50 to $5.00).




Macondopendium                                                                                                                                                                                                                                                          26
                                                                                                                                                    14 June 2010



Exhibit 41: New EPS estimates vs. Old EPS estimates
Company                         Ticker Old 2010 New 2010                          % Old 2011 New 2011                %             Old        New          %
Name                           Symbol Earnings Earnings                       Change Earnings Earnings           Change             TP         TP      Change
Atwood Oceanics                      ATW             $4.13         $4.11          0%        $4.32        $3.90       -10%    $34.00    $29.00               -15%
Diamond Offshore                      DO             $8.07         $6.88        -15%        $7.40        $5.33       -28%    $78.00    $57.00               -27%
ENSCO                                ESV             $3.85         $3.79         -2%        $4.28        $3.90        -9%    $52.00    $40.00               -23%
Hercules Offshore                   HERO           ($0.49)       ($0.46)          nm        $0.07      ($0.26)         nm     $6.50     $5.00               -23%
Noble Corp                             NE            $5.21         $4.16        -20%        $5.23        $4.00       -23%    $52.00    $40.00               -23%
Pride International                  PDE             $1.77         $1.80          2%        $3.46        $3.20        -8%    $38.00    $33.00               -13%
Rowan                                RDC             $2.40         $2.43          1%        $1.70        $1.67        -2%    $24.00    $24.00                 0%
Seadrill                            SDRL             $2.61         $2.60          0%        $3.06        $3.03        -1% kr 144.00 kr 131.00                -9%
Transocean                            RIG            $8.00         $7.60         -5%        $9.00        $7.49       -17%    $92.00    $63.00               -32%
TOTAL                                                                            -7%                                 -16%                                   -19%
Source: FactSet, Company data, Credit Suisse estimates

Exhibit 42 illustrates our 2010 and 2011 EPS and CFPS estimates versus consensus. On
average, our revised EPS estimates are 11% below consensus for 2010 and 21% below
consensus in 2011. Despite robust oil prices and rising international upstream spending
trends, we believe the drilling stocks will likely lag other sub-sectors given the risk for
downward estimate revisions over the next 12 months.

Exhibit 42: Credit Suisse estimates vs. Consensus
                                                       Earnings                                                      Cash Flow per Share
                                         Credit Suisse        First Call Mean             % Chg      % Chg    Credit Suisse     First Call Mean     % Chg    % Chg
Company                     Ticker      2010E      2011E       2010E     2011E             2010       2011   2010E    2011E     2010E      2011E     2010     2011
Offshore Drillers
 Atwood Oceanics            ATW          4.11            3.90          4.10       4.59     0.3%     -15.0%   4.72      4.67       4.65     5.38      1.5%   -13.2%
 Diamond Offshore            DO          6.88            5.33          8.21       8.33   -16.2%     -36.0%   9.79     8.34       11.31    11.53    -13.4%   -27.7%
 Ensco International        ESV          3.79            3.90          3.95       4.68    -4.1%     -16.6%   5.43      5.83      6.51      7.78    -16.7%   -25.1%
 Hercules Offshore         HERO         (0.46)          (0.26)       (0.59)     (0.50)      nm        nm     1.29      1.45      1.31      1.27     -1.4%    14.1%
 Noble Corp                  NE          4.16            4.00          5.36       5.20   -22.4%     -23.0%   6.06      6.02      7.43      7.49    -18.5%   -19.6%
 Pride International        PDE          1.80            3.20          1.82       3.22    -1.1%      -0.7%   2.81      4.46      2.81      4.41     -0.1%    1.1%
 Rowan Companies            RDC          2.43            1.67          2.56       2.03    -5.0%     -17.9%   4.07      3.44      3.75      4.30      8.6%   -19.9%
 Seadrill                  SDRL-NO       2.60            3.03          2.79       3.26    -6.7%      -7.2%   4.03      4.47      4.30      4.80     -6.3%    -6.9%
 Transocean                 RIG          7.60            7.49          8.78       9.90   -13.4%     -24.4%   12.42    12.81      15.50    15.52    -19.9%   -17.4%
Offshore Driller Average                32.92           32.26        36.98      40.71    -11.0%     -20.7%   50.62    51.50      57.57    62.49    -12.1%   -17.6%


Land Drillers
 Helmerich & Payne           HP             2.33         2.50          2.38      2.57    -2.1%       -2.7%   4.79      5.08      4.86      5.25    -1.5%     -3.2%
 Nabors Industries          NBR             1.01         1.70          1.03      1.64    -1.9%        3.9%   3.49      4.24      3.55      4.26    -1.7%     -0.7%
 Patterson-UTI Energy       PTEN            0.24         0.24          0.23      0.47    4.0%       -48.4%   2.34      2.72      2.41      2.68    -2.7%     1.3%
Land Driller Average                        3.58         4.45          3.64      4.68    -1.7%       -5.0%   10.62    12.03      10.82    12.20    -1.8%     -1.3%


Offshore Transportation
 Tidewater                    TDW           3.80         4.40          3.99       5.42   -4.9%      -18.7%   6.47     7.20       6.45     8.26      0.3%    -12.8%
 Bristow                      BRS           3.05         3.50          3.18       3.63   -4.2%       -3.5%   5.22     4.89       5.51     6.16     -5.2%    -20.7%
Offshore Transportation Average             6.84         7.91         7.17       9.05    -4.6%      -12.6%   11.69    12.09      11.96    14.42    -2.3%    -16.2%
Source: FactSet, Company data, Credit Suisse estimates




Petrobras is no longer a catalyst
In the aftermath of the credit crisis, our analysis indicated 9 contracted rigs under Phase I
& II of PBR’s deepwater rig expansion program were at risk owing to financing issues. Our
work suggests this gap has been largely bridged through 5 new term contracts by PBR
plus the apparent restart of construction on 4 rigs as credit conditions have normalized. In
addition, it appears that Delba may receive financing that could enable the
commencement of construction on 2 to 3 previously stalled floaters. We believe Petrobras’
insatiable thirst for deepwater rigs might be satisfied following recent awards and the shift
toward a newbuild strategy emphasizing local content. This would add to our concerns
regarding the 2011 outlook, as we expect PBR to be much less active in the market as
they focus on locally built newbuilds.




Macondopendium                                                                                                                                                27
                                                                                                                                                                                                                                                                 14 June 2010


Last week PBR received bids from nine shipyard groups for the much anticipated and 2-
1/2 month delayed 28-floater packages. The bids are for the purchase of the rigs by PBR
(or a special purpose entity). Part 1 of the tender included two packages of one
semisubmersible each; part 2 was four packages of seven drillships each. We have heard
that bids are to be opened in a matter of weeks. Contract drillers are to submit bids on
June 9 for leasing arrangements on 12 floaters in four-rig packages. Note that contract
drillers were initially envisioned to supply up to 19 floaters.
PBR has been transparent in its expectations that bids for these in-Brazil-manufactured
rigs should be $700 MM each. But yards' and drillers' appetite or perceived ability to
deliver that remains unknown, particularly since seven out of the nine shipyard/fabrication
bidders do not have operating yards in Brazil. And, as it relates to the contract driller
tenders, our anecdotal inquiries with driller management teams indicate hesitance from
several drillers to participate in the tender given contractual language that apparently
provides PBR with early termination rights. In short, we continue to expect commercial and
Terms & Conditions pressure on PBR and thus we expect delays in awards until perhaps
by the end of 2010 or 2011.
Last week the trade press reported that Brazilian rig company Queiroz Galvao (QGOG)
has stepped in as a partner to Delba (60% equity stake was reported) to build at least two,
and possibly three, of the floaters that Petrobras had awarded to Delba in the prior upcycle.
This would appear to solve the financing challenges Delba has experienced since being
awarded the six floaters (four semis and two drillships) in 2007-8 and reduce the potential
need for Petrobras to tap the spot market for rigs.


Replacement Cost Analysis
We are lowering our replacement cost estimates for the offshore drillers to reflect lower
construction costs. Exhibit 43 and Exhibit 44 illustrate the recent trend in jackup and floater
orders. Note the significant decline since Q308. As a result of this slowdown in new order
activity and the appreciation of the U.S. dollar versus foreign currencies, the replacement
cost for rigs has declined from peak levels. On average, our replacement cost estimates
for jackups and floaters declined by 16% and 11%, respectively. As a result, we reduced
our normalized dayrate assumptions for all rig types (14% on average) that are utilized in
our DCF analysis.

Exhibit 43: Historical Jackup Orders                                                                                                                             Exhibit 44: Historical Semi Orders
  16                                                                                                                                                              16


  14
                                                                                                                                                                  14


  12
                                                                                                                                                                  12


  10
                                                                                                                                                                  10

   8
                                                                                                                                                                   8
                                   14                                                                                                                                                                                                   15
   6   12
              11                                                                                                                                                   6
                                                                                                                                     10
                     9                    9                                                       9      9
   4                                                                  8      8                                                                                                             10        10

                                                                                    6                                                                              4                                                                          8
                                                                                           5                                                                                                     7                   7    7
   2                        4                           4      4                                                                                                                                                                    6
                                                                                                                                                                             5    5                             5              5
                                                                                                                2      2                    2                      2
                                                 1                                                                                                 1                                   3                                                                               3
   0                                                                                                                                                                                                       2                                       2
                                                                                                                                                                                                                                                                            1
       Q105

              Q205
                     Q305

                            Q405
                                   Q106

                                          Q206
                                                 Q306
                                                        Q406

                                                               Q107
                                                                      Q207
                                                                             Q307

                                                                                    Q407
                                                                                           Q108

                                                                                                  Q208
                                                                                                         Q308

                                                                                                                Q408
                                                                                                                       Q109

                                                                                                                              Q209
                                                                                                                                     Q309
                                                                                                                                            Q409

                                                                                                                                                   Q110
                                                                                                                                                          Q210




                                                                                                                                                                   0
                                                                                                                                                                       Q105 Q205 Q305 Q405 Q106 Q206 Q306 Q406 Q107 Q207 Q307 Q407 Q108 Q208 Q308 Q408 Q109 Q209 Q309 Q409 Q110 Q210


Source: ODS-Petrodata, Credit Suisse estimates, Company data                                                                                                     Source: ODS-Petrodata, Credit Suisse estimates, Company data

Asset deflation is evident in secondary rig values as shown in Exhibit 45. Since the peak
year of 2008, secondary rig values have decreased by 20%, with a more notable fall-off
seen among lower spec jackups and floaters, but a notable decrease nonetheless in




Macondopendium                                                                                                                                                                                                                                                                   28
                                                                                                                                                        14 June 2010


higher spec rigs (-22% for 350’ ILC jackups and -9% to -11% for 5th gen semis and
drillships).

Exhibit 45: Changing Rig Values
                                                                                                                                         Peak


                                                 Dec      Dec       Dec      Dec       Dec       Dec      Dec    Dec     Dec      Dec    Dec    Dec    Apr    % change
                                                 1992     1999      2000     2001      2002      2003     2004   2005    2006     2007   2008   2009   2010   since peak
Jackups built after 1980
150 feet ind cantilever                            3       15       20-22     16       10         10       19    35      35       40      40    13      13          -68%
200 feet mat cantilever                            6       18        25       20       20         22       25    50      50       55      50    21      21          -58%
250 feet mat slot                                  1       14       20-22     19       17         16       22    40      40       45      45    17      17          -62%
250 feet ind cantilever                          12-15     26        35       30       40         32       47    75      75       100     95    55      45          -53%
300 feet ind cant international                   18       45        55       50       55         50      62.5   90      90       130    130    90      60          -54%
300 feet ind cant N Sea                           25       45        55       50       60         50       65    100     100      150    145    100     95          -34%
New 350 feet IC                                   n/a      n/a       n/a      133      133       135      130    150     150      210    205    160    160          -22%

Semisubmersibles
Aker H-3 North Sea                                 5      35-40     35-40      45       30        25      27.5   90      90       225    270    200    200          -26%
3rd gen North Sea                                 40      85-90     85-90    90-100     80        65       60    140     140      250    320    255    255          -20%
4th generation                                    90     170-180   170-180    200       200     160-175   140    250     250      320    390    330    330          -15%
5th generation                                    n/a      n/a       n/a       n/a    300-350   280-300   270    400     400      500    640    600    580           -9%
6th generation                                    n/a      n/a       n/a       n/a      n/a       n/a     n/a    500     500      675    675    635    610          -10%

Drillships
Conventional mid 1970s                           1-2      15-20     15-20     25        25        21      17     60      60        200   230     230   125          -46%
DP 5,000 ft.+ (older generation, not newbuild)   8-10    100-110   100-110    120       95        70      55     150     150       285   290     225   225          -22%
5th generation                                    n/a      n/a       n/a      n/a     300-350   280-300   265    400     400       500   640     605   590           -8%
6th generation                                    n/a      n/a       n/a      n/a       n/a       n/a     n/a    500     500       675   700     645   620          -11%
Total                                                                                                                             3685   4165   3536   3326         -20%

Source: ODS-Petrodata, Credit Suisse estimates, Company data

Exhibit 46 illustrates the decrease in our replacement cost estimate by asset type. We
estimate that the cost of a 400’ ILC ultra-premium newbuild jackup such as the Keppel
FELS MOD V B has decreased by 16% to $167 MM from $199 MM, while the shipyard
cost of a newbuild 5th+ gen semi or drillship has decreased by 9% to 11%.

Exhibit 46: Adjusted Replacement Cost by Asset Type
                                                                                                                        Percent
Asset Type                                               Old Replacement Cost          New Replacement Cost             Change
250' Slot Jackup - GOM Mat Supp.                                  $104,256,000                   $86,946,675             -16.6%
250' Slot Jackup - Ind. Leg                                       $131,475,000                  $108,721,875             -17.3%
250' Cantilever Jackup                                            $147,275,000                  $124,521,875             -15.4%
300' Cantilever Jackup                                            $177,629,688                  $149,005,625             -16.1%
400' Cantilever Jackup                                            $199,220,000                  $167,306,250             -16.0%
2nd Gen. Semi                                                     $324,788,750                  $273,011,600             -15.9%
3rd Gen. Semi                                                     $433,707,250                  $389,306,344             -10.2%
4th Gen. Semi                                                     $521,233,375                  $464,704,203             -10.8%
5th Gen Semi                                                      $630,434,563                  $571,380,242              -9.4%
DP Drillship                                                      $642,987,000                  $571,730,344             -11.1%
Dual Activity DP Drillship                                        $737,671,600                  $655,829,369             -11.1%
Source: ODS-Petrodata, Credit Suisse estimates, Company data

In Exhibit 47, we have applied the decreases in estimated replacement costs to the
offshore drillers in our coverage group. On average, our replacement cost estimates for
the group declined by 13%. On an individual-company basis, the biggest swings in
replacement cost are attributable to ENSCO (-15%), Atwood (-14%), and Hercules (-14%).

Exhibit 47: Adjusted Replacement Cost by Company ($MM)
                                                                                                                        Percent
Company                                                  Old Replacement Cost          New Replacement Cost             Change
Atwood Oceanics                                                        $3,011                        $2,587              -14.1%
Diamond Offshore                                                      $16,020                       $14,038              -12.4%
ENSCO plc                                                             $10,153                        $8,620              -15.1%
Hercules Offshore                                                      $4,540                        $3,904              -14.0%
Noble Corp                                                            $14,872                       $12,829              -13.7%
Pride International                                                    $9,185                        $7,970              -13.2%
Rowan Companies                                                        $6,372                        $5,541              -13.0%
Transocean                                                            $48,007                       $41,980              -12.6%
Seadrill                                                              $12,347                       $11,124               -9.9%
Offshore Average                                                     $124,506                      $108,593              -12.8%
Source: ODS-Petrodata, Credit Suisse estimates, Company data

To quantify the potential impact on dayrates from asset inflation, we have calculated the
dayrates necessary to generate a 15% internal rate of return (IRR) under (1) our old



Macondopendium                                                                                                                                                       29
                                                                                                                                                                                                         14 June 2010


replacement cost estimates and (2) our newly adjusted replacement cost estimates. The
returns analysis in Exhibit 48 assumes 90% utilization, a 25-year useful life, and no
salvage value. We further assume a two-year construction period for jackups and three-
year period for floaters.
We derived the 15% normalized return assumption from our analysis of implied return
requirements for the last two major build cycles and the massive newbuild cycle from the
late 1970s adjusted for differences in inflation and real rates of return. Based on this
analysis, the required dayrate to justify construction of a new 400’ cantilever jackup in a
“normal” environment (dayrates are stable with good forward visibility, supply/demand in
balance, and demand rising) has declined by 7.2% to $135K, while the required dayrate to
justify construction of a new 5th gen semi has fallen by 5.9% to $422K.

Exhibit 48: Estimated Return on Replacement Cost at 15% IRR: Old vs. New
                                                                          Old Replacement Cost:                              New Replacement Cost:
                                                                        Required Dayrate for 15%                            Required Dayrate for 15%                                    Percent
Asset Type                                                                                   IRR                                                 IRR                                    Change
250' Slot Jackup - GOM Mat Supp.                                                         $83,797                                             $77,173                                     -7.9%
250' Slot Jackup - Ind. Leg                                                            $102,063                                              $92,580                                     -9.3%
250' Cantilever Jackup                                                                 $114,440                                            $107,430                                      -6.1%
300' Cantilever Jackup                                                                 $134,203                                            $125,425                                      -6.5%
400' Cantilever Jackup                                                                 $144,979                                            $134,506                                      -7.2%
2nd Gen. Semi                                                                          $248,753                                            $226,432                                      -9.0%
3rd Gen. Semi                                                                          $318,974                                            $299,858                                      -6.0%
4th Gen. Semi                                                                          $383,216                                            $353,500                                      -7.8%
5th Gen Semi                                                                           $448,679                                            $422,287                                      -5.9%
DP Drillship                                                                           $460,997                                            $422,385                                      -8.4%
Dual Activity DP Drillship                                                             $524,559                                            $496,173                                      -5.4%
Source: ODS-Petrodata, Credit Suisse estimates, Company data

Based on our revised estimates, the group is trading at 66% of replacement cost vs. an
average of 52% at cyclical troughs and the absolute trough of 41% in early 1999 when oil prices
fell to $10 per bbl. A potential reversion to trough level valuations on replacement cost would
cause us to revisit our cautious thesis.

Exhibit 49: Historical Offshore Driller EV/Replacement Cost
180.0%
                                     Maximum =
160.0%                                 166%


140.0%

120.0%                                                                                                                                                                             Current =
                                                                                                                                                                                     66%
100.0%

 80.0%

 60.0%

 40.0%
                                                   Minimum =
 20.0%                                                41%

  0.0%
         Q197

                Q397

                       Q198

                              Q398

                                     Q199

                                            Q499

                                                   Q200

                                                          Q400

                                                                 Q201

                                                                        Q401

                                                                               Q202

                                                                                      Q402

                                                                                             Q203

                                                                                                    Q403

                                                                                                           Q204

                                                                                                                  Q404

                                                                                                                         Q205

                                                                                                                                Q405

                                                                                                                                       Q206

                                                                                                                                              Q406

                                                                                                                                                     Q207

                                                                                                                                                            Q407

                                                                                                                                                                   Q208

                                                                                                                                                                          Q408

                                                                                                                                                                                 Q209

                                                                                                                                                                                        Q409

                                                                                                                                                                                               Current




Source: FactSet, Credit Suisse estimates, Company data

Exhibit 50 illustrates the historical EV/replacement cost trading ranges for the companies
in our coverage group.




Macondopendium                                                                                                                                                                                                    30
                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         14 June 2010



Exhibit 50: Weekly Offshore Driller EV/Replacement Cost by company
                                                               ATW Weekly Enterprise Value to Replacement Cost                                                                                                                                                                                               DO Weekly Enterprise Value to Replacement Cost
                                  180%                                                                                                                                                                                                                       180%
                                                    Average EV/RC =                                                                                                                                                                                                                                                       Average EV/RC = 79.9%
                                  160%                                                                                                                                                                                                                       160%
                                                         66.2%
   EV/Replacement Cost




                                  140%                                                                                                                                                                                                                       140%




                                                                                                                                                                                                                                EV/Replacement Cost
                                  120%                                                                                                                                                                                                                       120%

                                  100%                                                                                                                                                                                                                       100%

                                  80%                                                                                                                                                                                                                            80%

                                  60%                                                                                                                                                                                                                            60%
                                  40%                                                                                                                                                                                                                            40%
                                  20%                                                                                                   Current EV/RC = 67.4%                                                                                                    20%                                                                                                                                                             Current EV/RC = 66.1%
                                   0%                                                                                                                                                                                                                             0%
                                         Jan-97

                                                    Jan-98

                                                                 Jan-99

                                                                            Jan-00

                                                                                        Jan-01

                                                                                                    Jan-02

                                                                                                                Jan-03

                                                                                                                            Jan-04

                                                                                                                                        Jan-05

                                                                                                                                                     Jan-06

                                                                                                                                                                   Jan-07

                                                                                                                                                                                Jan-08

                                                                                                                                                                                              Jan-09

                                                                                                                                                                                                            Jan-10




                                                                                                                                                                                                                                                                        Dec-96

                                                                                                                                                                                                                                                                                          Dec-97

                                                                                                                                                                                                                                                                                                              Dec-98

                                                                                                                                                                                                                                                                                                                                Dec-99

                                                                                                                                                                                                                                                                                                                                                  Dec-00

                                                                                                                                                                                                                                                                                                                                                                    Dec-01

                                                                                                                                                                                                                                                                                                                                                                                       Dec-02

                                                                                                                                                                                                                                                                                                                                                                                                         Dec-03

                                                                                                                                                                                                                                                                                                                                                                                                                           Dec-04

                                                                                                                                                                                                                                                                                                                                                                                                                                              Dec-05

                                                                                                                                                                                                                                                                                                                                                                                                                                                                Dec-06

                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  Dec-07

                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     Dec-08

                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       Dec-09
                                                                ESV Weekly Enterprise Value to Replacement Cost                                                                                                                                                                                            HERO Weekly Enterprise Value to Replacement Cost

                                  200%                                                                                                                                                                                                                   140%
                                  180%                          Average EV/RC = 95.1%                                                                                                                                                                                                                                                                                       Average EV/RC = 69.4%
                                                                                                                                                                                                                                                         120%
                                  160%




                                                                                                                                                                                                                           EV/Replacement Cost
       EV/Replacement Cost




                                  140%                                                                                                                                                                                                                   100%

                                  120%                                                                                                                                                                                                                           80%
                                  100%
                                                                                                                                                                                                                                                                 60%
                                   80%
                                   60%                                                                                                                                                                                                                           40%
                                   40%
                                                                                                                                                                                                                                                                 20%                                                                                                                                                    Current EV/RC = 32.6%
                                   20%                                                                                        Current EV/RC = 51.4%
                                   0%                                                                                                                                                                                                                            0%    Oct-05

                                                                                                                                                                                                                                                                                         Feb-06

                                                                                                                                                                                                                                                                                                            Jun-06

                                                                                                                                                                                                                                                                                                                              Oct-06

                                                                                                                                                                                                                                                                                                                                                Feb-07

                                                                                                                                                                                                                                                                                                                                                                  Jun-07

                                                                                                                                                                                                                                                                                                                                                                                    Oct-07

                                                                                                                                                                                                                                                                                                                                                                                                      Feb-08

                                                                                                                                                                                                                                                                                                                                                                                                                        Jun-08

                                                                                                                                                                                                                                                                                                                                                                                                                                          Oct-08

                                                                                                                                                                                                                                                                                                                                                                                                                                                            Feb-09

                                                                                                                                                                                                                                                                                                                                                                                                                                                                              Jun-09

                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                Oct-09

                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  Feb-10
                                         Dec-96

                                                    Dec-97

                                                                  Dec-98

                                                                             Dec-99

                                                                                         Dec-00

                                                                                                     Dec-01

                                                                                                                  Dec-02

                                                                                                                              Dec-03

                                                                                                                                          Dec-04

                                                                                                                                                       Dec-05

                                                                                                                                                                      Dec-06

                                                                                                                                                                                   Dec-07

                                                                                                                                                                                                 Dec-08

                                                                                                                                                                                                                Dec-09




                                                                NE Weekly Enterprise Value to Replacement Cost                                                                                                                                                                                     PDE Weekly Enterprise Value to Replacement Cost

                                  180%                                                                                                                                                                                                                     120%
                                                    Average EV/RC =
                                                                                                                                                                                                                                                                                                              Average
                                  160%                   92.5%
                                                                                                                                                                                                                                                           100%                                               EV/RC =
                                  140%                                                                                                                                                                                                                                                                         68.3%
                                                                                                                                                                                                                          EV/Replacement Cost
       EV/Replacement Cost




                                  120%                                                                                                                                                                                                                           80%

                                  100%
                                                                                                                                                                                                                                                                 60%
                                  80%

                                  60%                                                                                                                                                                                                                            40%

                                  40%
                                                                                                                                                                                                                                                                 20%
                                                                                                                                                                                                                                                                                                                                                                                                                                      Current EV/RC = 61.1%
                                  20%
                                                                                                                                        Current EV/RC = 52.1%
                                   0%                                                                                                                                                                                                                             0%
                                                                                                                                                                                                                                                                        Dec-96

                                                                                                                                                                                                                                                                                          Dec-97

                                                                                                                                                                                                                                                                                                              Dec-98

                                                                                                                                                                                                                                                                                                                                Dec-99

                                                                                                                                                                                                                                                                                                                                                  Dec-00

                                                                                                                                                                                                                                                                                                                                                                    Dec-01

                                                                                                                                                                                                                                                                                                                                                                                       Dec-02

                                                                                                                                                                                                                                                                                                                                                                                                         Dec-03

                                                                                                                                                                                                                                                                                                                                                                                                                           Dec-04

                                                                                                                                                                                                                                                                                                                                                                                                                                             Dec-05

                                                                                                                                                                                                                                                                                                                                                                                                                                                               Dec-06

                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  Dec-07

                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    Dec-08

                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      Dec-09
                                         Dec-96

                                                    Dec-97

                                                                 Dec-98

                                                                            Dec-99

                                                                                        Dec-00

                                                                                                    Dec-01

                                                                                                                Dec-02

                                                                                                                            Dec-03

                                                                                                                                         Dec-04

                                                                                                                                                      Dec-05

                                                                                                                                                                    Dec-06

                                                                                                                                                                                 Dec-07

                                                                                                                                                                                               Dec-08

                                                                                                                                                                                                             Dec-09




                                                                  RDC Weekly Enterprise Value to Replacement Cost                                                                                                                                                                                                     RIG Weekly Enterprise Value to Replacement Cost

                                  180%                                                                                                                                                                                                                           250%
                                                                                                                                                                                                                                                                                                                                       Average EV/RC =
                                  160%                          Average EV/RC =                                                                                                                                                                                  225%
                                                                                                                                                                                                                                                                                                                                           116.8%
                                                                     78.8%                                                                                                                                                                                       200%
                                  140%
                                                                                                                                                                                                                                           EV/Replacement Cost
            EV/Replacement Cost




                                                                                                                                                                                                                                                                 175%
                                  120%
                                                                                                                                                                                                                                                                 150%
                                  100%
                                                                                                                                                                                                                                                                 125%
                                   80%
                                                                                                                                                                                                                                                                 100%
                                   60%                                                                                                                                                                                                                            75%
                                   40%                                                                                                                                                                                                                            50%
                                                                                                                                                                                                                                                                                                                                                                                                                                               Current EV/RC =
                                   20%                                                                                                                            Current EV/RC =                                                                                 25%
                                                                                                                                                                                                                                                                                                                                                                                                                                                    64.3%
                                                                                                                                                                       54.1%                                                                                       0%
                                    0%
                                                                                                                                                                                                                                                                                Dec-96

                                                                                                                                                                                                                                                                                                  Dec-97

                                                                                                                                                                                                                                                                                                                     Dec-98

                                                                                                                                                                                                                                                                                                                                       Dec-99

                                                                                                                                                                                                                                                                                                                                                         Dec-00

                                                                                                                                                                                                                                                                                                                                                                           Dec-01

                                                                                                                                                                                                                                                                                                                                                                                             Dec-02

                                                                                                                                                                                                                                                                                                                                                                                                               Dec-03

                                                                                                                                                                                                                                                                                                                                                                                                                                 Dec-04

                                                                                                                                                                                                                                                                                                                                                                                                                                                   Dec-05

                                                                                                                                                                                                                                                                                                                                                                                                                                                                     Dec-06

                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       Dec-07

                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         Dec-08

                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           Dec-09
                                           Dec-96

                                                      Dec-97

                                                                   Dec-98

                                                                               Dec-99

                                                                                           Dec-00

                                                                                                       Dec-01

                                                                                                                   Dec-02

                                                                                                                               Dec-03

                                                                                                                                            Dec-04

                                                                                                                                                         Dec-05

                                                                                                                                                                       Dec-06

                                                                                                                                                                                     Dec-07

                                                                                                                                                                                                   Dec-08

                                                                                                                                                                                                                 Dec-09




Source: FactSet, Company data, Credit Suisse estimates




Macondopendium                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      31
                                                                                                  14 June 2010



Integrated Oils: BP - Macondo – Shoreline Oil Impact
Now Potentially Falling (June 4th, 2010)
Conclusion: On the conference call, BP reiterated its pledge to deal with all the financial
consequences of the oil spill as the “responsible party” under OPA.
The company is confident that it has sufficient firepower to deal with all costs and
commitments. It appears partners Anadarko/Mitsui may have to bear their share of clean-
up costs and claims under the Oil Pollution Act. Perhaps as important, if the LMRP cap
has an efficiency of above 73% and assuming BP is skimming around 5kbd per day from
the surface, we are now moving into a phase where the volume of oil that could hit shore
will start FALLING from this point on and not rising (see table). The net impact of lower
clean up costs (due to LMRP success) and the sharing of liabilities with partners is worth
approximately $3.3/ADR (38p/sh) offset by a slightly greater impact on US Gulf of Mexico
volumes of 50kbd (3% of EPS) in 2011.
As expected, BP deferred a decision on the dividend, and said it would take into
account the balance between commitment to shareholders, capex, gearing and the costs
of the oil spill response. We continue to forecast a flat dividend for now, although we see
risks of a temporary dividend cut, with a commitment to raise the dividend once the
liabilities become clear.
Too early for clarity on liabilities despite turning the corner on volumes : Although,
with the right LMRP efficiency and surface skimming response, we may have turned the
corner on shoreline oil spill volumes, uncertainty about clean up costs, claims, and punitive
damages remains. We will likely have a better understanding at BP’s 2Q results when
provisions will be taken with a best estimate of future liabilities.
Update on sub-sea response
BP is currently pursuing three containment options:
    1)   Lower Marine Riser Package (LMRP), which has started to capture some oil
         leaking from the well. It will be another 48 hours before the LMRP is fully
         optimised,
    2)   enhanced production system, in parallel with LMRP (mid-June),
    3)   “overshot tool” by July, a more permanent system that can be quickly hooked up
         and disconnected in a hurricane (48 hours instead of 10 days)
Clean-up costs & liabilities

■   BP's CEO highlighted that this has been a complex accident, that it is too early to say
    where the fault lies and that the whole chain operations including cement, casing,
    pressure testing, BOP operation, emergency control of the BOP, failure to disconnect
    the BOP from the riser, ability of ROV's to intersect with the BOP are all potential
    contributing factors. BP's CEO did reiterate that the well design has been used in 30-
    40% of the last 80 wells drilled in the Gulf and that all procedures were pre-approved
    by the MMS before operation.

■   Clearly it is up to the courts to decide whether gross negligence or wilful misconduct
    has taken place, but if the investigation cannot point the finger at a single decision, the
    risks of punitive damages might have been lowered by these statements and it seems
    APC and Mitsui may have to bear their share of clean up costs and claims under OPA.
    In our June-02 report, we assumed that BP would have to bear 100% of the costs of
    clean-up and of the liabilities.

■   BP has spent well over $1bn in gross costs so far, of which the bulk of costs is spent
    on the containment efforts rather than clean-up. The rate of spend on the subsea
    response is expected to drop off after completion of the two relief wells in August. The



Macondopendium                                                                                             32
                                                                                                   14 June 2010


    vast majority of containment and clean-up costs will be incurred by the end of 2010.
    Fines, penalties and litigation costs are impossible to determine and expected to be
    spread over many years, but will be “sizeable”. BP expects to have more clarity on
    costs by 2Q results on 27 July. Oil-spill related costs will be treated as identifiable non-
    operating items.

■   We now estimate gross clean-up costs of between $6-14.8bn (including fines levied
    under the Clean Water Act of potentially $0.6-5bn) and claims liabilities of $14bn
Dividend

■   BP did not commit to a flat quarterly dividend given the uncertainty surrounding
    the containment efforts, clean-up costs and potential litigation. When making the
    dividend decision (to be announced on 2Q results on 27 July), the Board will take into
    account the balance between the costs of the oil spill response, obligations to
    shareholders, capex for future growth and gearing levels.

■   Gearing (BP definition: Net Debt to Capital Employed) stood at 19% at end-1Q10,
    below BP’s target range of 20-30%. Including $30bn of gross costs over 2010-11, we
    estimate gearing will stay below BP’s target ceiling - rising to 27% at end 2010,
    then decreasing to 23% at end 2012.

■   BP management highlighted the company’s significant financial firepower to deal
    with the oil spill costs: BP generates c.$37bn of operating cash flow per year at
    $80/bbl (vs $21.5bn of capex and $10.5bn of dividend commitments), and has $5bn of
    cash on balance sheet and committed bank facilities.

■   Capex: BP is making no change to its capex programme for the moment, as it is
    generating enough operating cash flow to cover all its needs (dividends, capex, oil
    spill-related costs)

■   Beyond cash flow and gearing considerations, BP’s Board will also take into account
    political sensitivities. Clearly political heat the US is rising, with some Senators calling
    for the dividend to be cut.
Impact on GoM volumes

■   BP expects an impact on GoM volumes of up to 50kbd in 2011 and up to 75kbd by
    2015. The 2011 impact is unexpected, as BP’s volume growth in the GoM is back-end
    loaded (2015+) – we think this must reflect the impact on in-fill drilling (decline
    mitigation). We estimate a 50kbd reduction in GoM production in 2011 will have a
    c.3% incremental negative impact on EPS.




Macondopendium                                                                                              33
                                                14 June 2010



Exhibit 51: Clean up cost estimates




Source: Company data, Credit Suisse estimates




Macondopendium                                           34
                                                                                                14 June 2010



US OFS: Insight Downhole – Still Cautious but
Risk/Reward Skews Favorably (June 3rd, 2010)
Exhibit 52: Estimated Near Term Risk/Reward in Select Svc./Equip. Shares

    60%
                                    Downside   Upside
    50%
    40%
    30%
    20%
    10%
     0%
    -10%
    -20%
    -30%
    -40%
           BHI      HAL       SLB         WFT           CAM   FTI   NOV    OII

Source: Bloomberg, Company data, Credit Suisse estimates



■    Risk/Rewards skewing positively: The potential for significant activity and order
     delays in the Gulf of Mexico (GoM) and elsewhere keeps us on the sidelines for our
     group. But risk/rewards are skewing positively, in our view. We maintain our relative
     preference for CAM, HAL and SLB and, now, NOV.
■    We think service and equipment names may have 15% downside: We derive 15%
     average downside if we apply what we think are conservative multiples—in other words
     not lows set on the verge of the ’08 crash, but well below prior cycle averages—to our
     2011 EPS estimates pro-forma-ed for a GoM deepwater hiatus (see Exhibit 52Exhibit
     53 and Exhibit 54). Note we have not lowered estimates yet as the outlook for 2011 in
     the GoM is continuing to take shape.
■    And we see nearer-term upside averaging 30%: Similarly, we see 30% average
     upside if we apply our current target multiples to the aforementioned pro-forma 2011
     EPS estimates. Our 9-12 month Target Prices allow for more upside (see Exhibit 56)
     as these look through the crisis.
■    Most attractive “skews” in HAL, CAM, NOV and SLB: These favorable skews come
     from a combination of share underperformance, relatively less GoM exposure and
     higher prior cycle multiples.
■    NOV: more limited downside from limited GoM exposure and catalysts emerging;
     we upgraded to OP: We see catalysts from floating rig orders for the first time in 18
     months—these are for Brazil but this list may broaden to Norway by year end. Please
     see our separate note out this morning Catalysts Re-emerge and It’s Defensive.


Discussion
What are the stocks telling us?
For this exercise we have focused on the eight stocks in our coverage with meaningful
deepwater exposure and tried to determine possible downside.
To establish downside risk for shares, we need to set both earnings, say for 2011, and
multiples to be applied to those earnings. There is clearly significant uncertainty regarding
earnings, given the many variables including that it is unclear when the GoM moratorium
gets lifted, the length of new permit approvals post lifting of the moratorium, the demand
impact of additional safety regulation, any impact outside of the GoM if/as safety
procedures are impacted elsewhere, etc.



Macondopendium                                                                                           35
                                                                                                 14 June 2010


We set a scenario which yields 12% EPS downside for our coverage
To set earnings, we have fleshed out a scenario that has a consistent EPS impact of that
which we have spoken to in recent notes. We assume:
     •    80% of deepwater activity is impaired for 2011
     •    10% degredation in pricing in the shallow waters of the GoM given additional
          capacity
     •    60% decremental EBIT margins for the GoM in total (we had been using 50% but
          if we factor (a) pricing erosion in shallow water and (b) only 30% of the cost basis
          being labor, it suggests to us decrementals may be higher)
And we have taken initial steps to estimate the earnings impact of this “scenario” for our
equipment coverage. The EPS impact is summarized in Exhibit 53.

Exhibit 53: Cursory Estimates of GoM Slowdown Scenario for 2011

                                                 2011       2011 Cons.   Est. GoM
                     CS         06/03/10       Consensus     Less GoM    2011 EPS
                    Rating       Price             EPS       Est. EPS     Impact
           BHI        N         $39.38            $3.22       $2.66        -17%
           HAL        O         $23.63            $2.11       $1.81        -14%
           SLB        O         $56.63            $3.90       $3.50        -10%
           WFT        O         $13.72            $1.20       $1.05        -13%

           CAM        N         $34.62            $2.80       $2.66        -5%
           FTI        N         $50.52            $3.22       $2.96        -8%
           NOV        O         $35.67            $3.22       $3.09        -4%
           OII        N         $43.57            $4.09       $2.99        -27%
Source: Bloomberg, Company data, Credit Suisse estimates



To determine stock price downside, we set a conservative multiple to apply to this
GoM-affected EPS
With a stake set in the ground on EPS, we can then consider how investors are, or would
view the group in light of this extended slowdown in activity. Prior cycle forward 12-month
P/E multiples range widely, from the mid-single digits set at the end of ’08 before
estimates were taken lower to the mid-20s set generally earlier on in the recent upcycles.
Forward multiples have averaged in the high teens.
 We presume that with a prolonged period of uncertainty, investors will be unwilling to
apply even prior cycle average multiples to 2011. To try to set downside, we have tried
using the average of prior cycle low and average multiples. Why? As we mentioned, prior
cycle lows were set as we looked over the precipice into severe economic downturn, so to
speak. Thus it seems an excessively low multiple to consider for the current situation (at
least if we consider the Macondo disaster in isolation). But it also seems as though
applying prior cycle averages is too optimistic given the uncertainty.
For a measure of conservatism, we deduct 1 multiple point across all of the companies to
this average.


Applying this adjusted average multiple yields 16% downside for shares
Putting the pieces together, we apply these “discounted” multiples to Consensus 2011
EPS estimates that are lowered by our estimates for GoM impact to derive target prices.
These are 16% lower than current.




Macondopendium                                                                                            36
                                                                                                      14 June 2010



Exhibit 54: Implied Downside from Lower EPS and Multiples

                                        Prior Cycle       2011
                                        Low- Ave.         Cons.                           Implied
                 CS       06/03/10       Multiples      Less GoM          Implied        Up/Dn side
              Rating        Price        (Adjusted)      Est. EPS          Price          to Price
     BHI        N          $39.38           11.3          $2.66           $30.07           -24%
     HAL        O          $23.63           10.9          $1.81           $19.81           -16%
     SLB         O         $56.63           12.5           $3.50          $43.86           -23%
     WFT         O         $13.72           10.8           $1.05          $11.32           -17%

     CAM         N         $33.34           11.5           $2.66          $30.54            -8%
     FTI         N         $50.52           12.4           $2.96          $36.71           -27%
     NOV         O         $35.67           9.8            $3.09          $30.27           -15%
     OII         N         $43.57             12.6         $2.99          $37.56           -14%
     Notes:
     "low-Ave." = the average of prior cycle low and average multiples.
        Prior cycle lows were consistent with the start of downturns and so we believe
        is "excessive". We lower by 1 generally for conservatism
Source: Bloomberg, Company data, Credit Suisse estimates



Near term upside may be weighed down by Macondo impact as well, but skews
positively
The upside reflected in Exhibit 52 is derived by taking our 2011 EPS estimates less our
current scenario for GoM impact and applying the same multiples (or effective multiples for
the equipment names, for which we use a DCF to derive Target Prices). We believe this
understates the 9-12 month upside, which is lifted by a recovery in activity and a focus on
2012 and beyond.
For published ratings, target prices and estimates, please see Exhibit 56 and Exhibit 57.




Macondopendium                                                                                                 37
                                                                                     14 June 2010



Exhibit 55: Stock Performance Since the Macondo Incident and from the 2010 Peak
             6/3/10     4/20/10   1/8/10                 6/3/10   4/20/10   1/8/10
 #    Tkr     Price      Perf     Perf       #    Tkr    Price     Perf      Perf
 1   SWSI    $16.60      12%      (8%)       36 CKH     $70.49    (17%)      (9%)
 2   CPX     $13.78      4%       (5%)       37 SLB     $56.63    (17%)     (20%)
 3   NR      $6.66       4%       48%        38 GIFI    $17.57    (17%)     (19%)
 4   TTES    $28.51      3%       (1%)       39 SII     $37.97    (17%)      22%
 5   NBR     $20.59      1%       (23%)      40 TDW     $41.27    (19%)     (19%)
 6   HP      $40.87      1%       (15%)      41 MDR     $22.50    (19%)     (14%)
 7   WEL     $2.94       (0%)     70%        42 NOV     $35.67    (19%)     (24%)
 8   PTEN    $14.63      (1%)     (20%)      43 WFT     $13.72    (20%)     (33%)
 9   CLB    $141.94      (2%)     13%        44 BHI     $39.38    (22%)     (16%)
 10 OYOG     $48.41      (3%)     15%        45 GLBL     $5.19    (22%)     (33%)
 11 DRC      $33.34      (4%)     (1%)       46 OSX     $169.27   (23%)     (22%)
 12 EPX     $386.48      (4%)     (5%)       47 ACGY    $14.99    (25%)     (11%)
 13 LUFK     $41.98      (4%)     (43%)      48 CAM     $34.62    (25%)     (23%)
 14 KEG      $10.06      (4%)      (3%)      49 FTI     $50.52    (25%)     (17%)
 15 PKD      $4.81       (5%)     (13%)      50 RDC     $23.79    (25%)      (6%)
 16 XNG     $526.32      (7%)     (7%)       51 DWSN    $22.00    (26%)     (12%)
 17 RES      $11.70      (7%)     (6%)       52 ESV     $34.89    (28%)     (22%)
 18 KBR      $21.89      (7%)      3%        53 ATW     $26.87    (28%)     (33%)
 19 SPX     $1,102.83    (9%)     (4%)       54 HOS     $14.76    (29%)     (40%)
 20 CRR      $69.88      (9%)     (3%)       55 HAL     $23.63    (29%)     (31%)
 21 NGS      $16.17      (9%)     (19%)      56 PDE     $23.16    (30%)     (32%)
 22 TESO     $11.17      (9%)     (21%)      57 ALY      $2.69    (31%)     (39%)
 23 EXH      $25.87     (10%)       9%       58 DVR      $5.18    (32%)     (35%)
 24 TS       $37.25     (12%)     (18%)      59 CGV     $21.47    (32%)     (14%)
 25 BRS      $32.49     (14%)     (19%)      60 TTI      $9.10    (32%)     (28%)
 26 MTRX     $9.94      (14%)     (13%)      61 WG       $8.76    (32%)     (51%)
 27 TGE      $3.36      (15%)     (20%)      62 DO      $60.49    (33%)     (43%)
 28 FTK      $1.48      (15%)     (8%)       63 OII     $43.57    (33%)     (32%)
 29 XOI     $955.74     (15%)     (14%)      64 HERO     $2.92    (33%)     (49%)
 30 PDC      $6.28      (16%)     (35%)      65 DRQ     $44.00    (33%)     (25%)
 31 SPN      $20.30     (16%)     (23%)      66 NE      $27.73    (34%)     (38%)
 32 OIS      $39.51     (16%)     (7%)       67 HLX     $10.63    (36%)     (20%)
 33 BRNC     $4.05      (16%)     (33%)      68 GOK      $4.66    (44%)     (55%)
 34 BAS      $8.33      (16%)     (16%)      69 RIG     $51.11    (44%)     (45%)
 35 IO       $5.15      (16%)     (25%)

Source: Bloomberg




Macondopendium                                                                                38
                                                                                                                                                                                                                                    14 June 2010



Exhibit 56: Credit Suisse U.S. Oilfield Services Valuation
                Credit                                                                        P/E                   P/CF            EV/EBITDA         Relative P/E                                Prior Cycle                             FCF Yie ld
                       (1)
                Suisse       6/3/10        Market                  Target           Curr on Ests    @ Tgt Curr on Ests       Curr on Ests     @ Tgt      2011E                P/E             P/CF        EV/EBITDA Relative P/E
                Rating       Price        Cap (MM)          Price           Up/Dn    '10E    '11E    '11E     '10E '11E       '10E     '11E   '11E     Curr @ Tgt      Low   Ave    High   Ave    High    Ave    High   Ave        High   '10E   11E
BHI                N         $39.38       $12,326            $58            47%      17.9    12.4   18.2      8.5     4.7     6.7      5.1      7.5   104% 151%        5.4   19.2   27.8   8.8    11.3    9.1    12.0   109%   168%       -1%    5%
HAL                O         $23.63       $22,162            $42            78%      15.3    11.3   20.0      8.9     7.1     6.8      5.5      9.5   95% 168%         5.2   18.7   26.3   12.7   17.7    9.1    14.1   107%   144%       -4%    3%
SLB                O         $56.63       $68,805            $86            52%      18.9    14.5   22.1     11.7     9.4     10.2     8.1    12.3    122% 185%        8.3   22.8   30.4   15.0   20.9    11.7   14.6   134%   163%       1%     4%
SII                N         $37.97        $8,838            $33            (13%)    31.6    18.5   16.1     13.0     9.9     9.8      7.3      6.4   155% 134%        5.4   19.3   29.2   12.6   18.3    9.9    13.9   114%   158%       0%     2%
WFT                O         $13.72       $10,124            $20            46%      23.0    11.5   16.7      6.8     5.0     8.4      6.3      8.1   96% 140%         4.2   17.5   25.6   11.1   15.9    8.6    12.2   102%   141%       -1%    1%
  Large-Cap Service Average                                                          21.3    13.6   18.6      9.8     7.2     8.4      6.5      8.8   114% 156%        5.7   19.5   27.9   12.0   16.8    9.7    13.4   113%   155%       -1%    3%

CPX                N         $13.78        $1,035            $19            38%       NM     16.2   22.3      5.2     4.3     5.9      4.8      6.0   136%        NM   3.2   8.6    13.6   4.7     6.9    6.9    13.0   60%    104%       6%     6%
OIS                N         $39.51        $1,984            $45            14%      16.4    12.0   13.6      8.0     6.6     6.5      5.3      6.0   100% 114%        3.4   11.2   16.1   7.8    10.2    6.3    8.9    72%        98%    -2%    6%
GGS                O         $9.69          $80              $13            34%      33.3    21.4   28.7      0.6     0.5     1.4      1.3      1.4   179% 241%        0.0   0.0    0.0    0.0     0.0    0.0    0.0    0%         0%     -29% -11%
  Small to Mid Cap Services Average                                                  24.9    16.5   21.5      4.6     3.8     4.6      3.8      4.4   138% 177%        3.3   9.9    14.9   6.3     8.6    6.6    10.9   66%    101%       -8%    0%

BRS                N         $32.49        $1,174            $41            26%      10.3     9.3   11.7      5.8     5.0     6.6      5.7      6.7   78%     98%      5.2   12.1   15.7   8.6    19.2    5.9    7.3    69%        89%    3%     6%
CAM                N         $34.62        $8,620            $48            39%      14.7    13.3   18.4     11.1     10.1    7.9      7.4    10.4    112% 155%        6.3   18.7   27.0   15.3   22.7    9.8    13.8   108%   141%       4%     8%
EXH                N         $25.87        $1,618            $30            16%       NM     37.2   43.1      4.3     3.7     8.2      6.8      7.2    NM         NM   5.1   NM     NM     9.9    13.5    8.7    15.3   NA         NA     14% 17%
FTI                N         $50.52        $6,295            $65            29%      19.5    17.5   22.5     14.3     13.0    10.5     9.6    12.4    146% 188%        7.8   19.0   25.4   14.5   19.4    10.5   15.0   124%   176%       4%     4%
GLBL               N         $5.19          $587             $7             35%      8.7      6.9    9.3      4.1     3.0     4.6      3.4      5.2   58%     78%      3.9   16.8   33.4   19.6   34.6    8.5    15.9   124%   206%       -31% 19%
NOV                O         $35.67       $14,874            $49            37%      9.3     12.5   17.2      7.0     8.7     4.6      5.7      8.1   105% 144%        4.1   19.5   28.6   16.0   24.7    9.3    13.8   110%   158%       5%     10%
OII                N         $43.57        $2,397            $68            56%      13.0    10.4   16.2      7.4     6.5     5.6      4.8      7.6   87% 136%         7.8   19.4   30.1   10.3   15.1    7.0    10.0   107%   142%       8%     7%
TDW                N         $41.27        $2,133            $47            14%      10.9     NA    10.7      6.4     NA      6.7      NA       NA     NA         NA   4.5   14.2   28.4   8.6    13.5    6.9    11.5   79%    155%       9%     -4%
  Equipment, Support & Infrastructure Average                                        12.3    15.3   18.6      7.5     7.2     6.8      6.2      8.2   98% 133%         5.6   17.1   26.9   12.8   20.3    8.3    12.8   103%   152%       2%     8%


ATW                N         $26.87        $1,733            $34            27%      6.5      6.2    7.9      5.8     5.3     5.1      4.5      5.7   52%     66%      3.0   18.0   36.1   11.1   27.2    9.2    12.0   115%   350%       1%     -4%
DO                 U         $60.49        $8,414            $78            29%      7.5      8.2   10.5      5.5     5.8     4.7      5.0      6.3   69% 88%          5.1   20.3   57.9   10.9   18.7    10.3   15.8   232%   232%       13% 14%
ESV                N         $34.89        $4,902            $52            49%      9.1      8.2   12.2      6.4     5.6     4.6      4.1      6.6   68% 102%         3.1   15.5   29.6    9.8   19.3     9.7   13.3   116%   189%       -2% 4%
HERO               O         $2.92          $284             $7             123%      NM      NM     NM       2.3     1.6     5.8      3.7      4.9    NM         NM   2.6   8.9    16.5   6.6    12.1    5.6    13.3   60%    121%       8%     41%
NE                 O         $27.73        $7,179            $52            88%      5.2      5.3    9.9      3.8     3.9     3.4      3.5      6.5   44%     83%      3.1   15.3   28.0   9.9    17.0    9.6    13.2   106%   145%       13% 18%
PDE                O         $23.16        $4,030            $38            64%      13.1     6.7   11.0      8.3     4.9     7.4      4.2      6.9   56%     92%      3.7   16.9   39.7   9.8    19.5    6.9    9.8    120%   317%       -18% -4%
RDC                U         $23.79        $2,702            $24             1%      9.9     14.0   14.2      5.9     6.8     4.8      5.8      5.8   118% 119%        3.1   16.5   53.6   10.3   23.8    12.7   20.4   154%   323%       -3%    7%
RIG                N         $51.11       $16,406            $92            80%      6.4      5.7   10.2      3.9     3.6     5.0      4.6      6.9   48%     86%      3.9   17.7   37.4   11.0   16.4    9.4    12.2   124%   280%       21% 23%
  Offshore Driller Average                                                           8.2      7.8   10.8      5.2     4.7     5.1      4.4      6.2   65%     91%      3.5   16.1   37.3   9.9    19.2    9.2    13.8   128%   245%       4%     12%

HP                 N         $40.87        $4,359            $43             5%      17.5    16.3   17.2      8.5     8.0     7.0      6.4      6.7   137% 144%        4.4   18.1   34.6   8.3    15.2    8.0    9.3    103%   168%       5%     8%
NBR                O         $20.59        $5,834            $30            46%      20.3    12.1   17.6      6.0     5.0     5.4      4.7      6.0   101% 148%        3.8   12.9   20.1   7.6    10.9    10.2   13.0    60%   82%         9%    11%
PTEN               U         $14.63        $2,225            $17            16%       NM      NM     NM       6.2     5.4     5.7      4.9      5.7    NM NM           4.8   15.4   30.7   8.1    16.2    10.5   18.9   106%   190%       -5%    0%
  Land Driller Average                                                               18.9    14.2   17.4      6.9     6.1     6.0      5.3      6.2   119% 146%        4.3   15.4   28.5   8.0    14.1    9.6    13.7   90%    147%       3%     6%

US Coverage Universe Average                                                41%      13.9    12.4   16.2      7.1     6.1     6.4      5.5      7.4   95% 125%         4.6   16.5   29.5   10.8   17.7    8.8    13.1   109%   177%       2%     8%
OSX                     169.27                                                       12.1    9.9
SPX                             1,103                                                13.6    11.9
(1)
      Credit Suisse ratings: O=Outperform, N=Neutral, U=Underperform, R=Restricted
(2)
      For the basis and risks to the valuation range for each company in our coverage universe, please see the end of this report. Targets for BHI, HAL, SLB, SII, WFT and BJS based on normalized earnings.
(3)
      Prior periods = average of meaningful earnings period of prior cycle (1996 to mid-1998), where availa ble, and mid-2002 to mid-2004; trough is since 1996




Source: Bloomberg, Company data, Credit Suisse estimates




Macondopendium                                                                                                                                                                                                                                    39
                                                                                                                                                                                                                                            14 June 2010



Exhibit 57: Credit Suisse U.S. Oilfield Services Coverage Estimates
                                    EPS                        Q1 2010E EPS                     EPS Growth            Oilfld Rev ($MM)     Revenue Growth      EBITDA ($MM)      Oilfld Mrgns(1)      Incrm'l Mrgns     ROCE      Nt Dbt/ Bk Cp   10E Capex/
                     2009E         2010E       2011E         CS/Act       Cons.         2009E     2010E      2011E    2010E    2011E     2009E 2010E 2011E     2010E   2011E   2009E 2010E 2011E     2010E   2011E    2010E 2011E 2010E 2011E     D&A    Rev
BHI                  $1.92         $2.20       $3.19         $0.46        $0.42         (64%)      14%        45%     10,527 16,508      (19%)   9%     57%    1,894   3,393   13%    13%     14%    14%       16%     7%   9%     6%     4%      150%    11%
HAL                  $1.32         $1.55       $2.10         $0.28        $0.25         (54%)      17%        35%     16,932 19,066      (20%) 15%      13%    3,437   4,250   15%    15%     17%    14%       34%    10%   13%   13%     10%     182%    12%
SLB                  $2.79         $3.00       $3.90         $0.62        $0.61         (38%)      8%         30%     24,679 28,535      (16%)   9%     16%    6,854   8,607   20%    20%     22%    16%       37%    14%   18%    4%     (4%)    125%    11%
SII                  $0.82         $1.20       $2.05         $0.18        $0.17         (78%)      47%        71%      7,253    8,244    (20%) 12%      14%    1,020   1,380   12%    13%     16%    17%       38%     3%   6%    13%     11%     98%      5%
WFT                  $0.55         $0.60       $1.20         $0.06        $0.09         (73%)      10%       100%     10,166 11,959      (8%)    15%    18%    1,992   2,657   11%    12%     15%    14%       33%     3%   5%    38%     36%     110%    11%
  Large-Cap Service Average                                                             (62%)      19%        56%                        (16%) 12%      23%                    15%    15%     17%    15%       31%     8%   10%   15%     11%     133%   10%

CPX                  ($0.87)       $0.24       $0.85         ($0.04)      ($0.12)       (137%) (128%)        252%      1,386    1,587    (44%) 31%      14%    268     331     (3%)   6%      10%    37%       33%     NA   NA    37%     31%     39%      5%
OIS                  $2.86         $2.41       $3.30         $0.78        $0.68         (51%)     (16%)       37%      2,095    2,409    (29%) (1%)     15%    316     392     10%    9%      11%    208%      22%     NA   NA     7%     (0%)    178%    11%
GGS                  $0.02         $0.29       $0.45         $0.40          NA          (101%)     NM         56%       316       375    (17%)   1%     19%    168     184     16%    24%     24%     NM       23%     3%   5%    46%     50%     31%     13%
  Small to Mid Cap Services Average                                                     (96%)     (72%)      115%                        (30%) 11%      16%    251     302      8%    13%     15%    122%      26%     3%   5%    30%     27%     83%     10%

BRS                  $3.07         $3.15       $3.50         $0.72        $0.69          1%        3%         11%      1,212    1,310     3%     4%     8%     266     309     15%    14%     13%    11%       (5%)    NA   NA    21%     15%     193%    14%
CAM                  $2.31         $2.35       $2.60         $0.51        $0.51         (14%)      2%         11%      6,194    6,315    (11%) 19%      2%     1,049   1,111   18%    16%     16%     4%       41%    11%   11%   (15%) (22%)     93%      3%
EXH                  $0.98         ($0.01)     $0.70         ($0.02)      ($0.01)       (61%)      NM         NM       2,453    2,832    (13%) (11%) 15%       449     543      8%    5%      7%     36%       17%     0%   1%    51%     50%     67%     10%
FTI                  $2.87         $2.60       $2.90         $0.80        $0.64          5%       (10%)       12%      4,200    4,716    (3%)    (5%)   12%    598     651     14%    13%     13%    29%       9%     20%   21%   (7%)   (11%)    119%     3%
GLBL                 $0.75         $0.60       $0.75         ($0.08)      $0.04          NM       (20%)       26%       839       946    (16%) (6%)     13%    181     243     15%    15%     16%    11%       26%     6%   7%     8%     3%      379%    35%
NOV                  $3.93         $3.84       $2.85         $1.10        $0.86         (23%)      (2%)      (26%)    12,062 10,622      (5%)    (5%) (12%)    2,879   2,316   22%    21%     19%    31%       40%    10%   7%    (14%) (21%)     59%      2%
OII                  $3.40         $3.35       $4.20         $0.77        $0.74          (5%)      (2%)       25%      1,833    2,063    (8%)    1%     13%    424     488     20%    20%     21%    (81%)     29%    13%   15%   (15%) (21%)     101%     8%
TDW                  $5.20         $3.80       $4.40         $1.01        $0.95         (34%)     (27%)       16%      1,115    1,185    (16%) (5%)     6%     332     382     23%    17%     20%    139%      63%     NA   NA     1%      NA     274%    34%
  Equipment, Support & Infrastructure Average                                           (19%)      (8%)       11%                        (9%)    (1%)   7%                     17%    15%     16%    22%       28%    10%   10%    4%     (1%)    161%   14%


ATW                  $3.88         $4.13       $4.32         $0.95        $1.01          16%       6%         5%        658       727    11%     12%    10%    358     398     53%    48%     48%    14%       43%    20%   NA     NA      NA     681%    41%
DO                   $9.86         $8.07       $7.40         $2.09        $1.98          (2%)     (18%)      (8%)      3,633    3,555     2%     0%     (2%)   2,055   1,904   52%    45%     54%     NM       NM     34%   NA     NA      NA     125%    14%
ESV                  $5.44          $3.85      $4.28          $1.11       $1.04          (34%)    (29%)        11%     1,708    1,841    (21%) (12%) 8%        878     975     48%    38%     51%     NM       NM     14%   NA     NA      NA     340%    45%
HERO                 ($0.78)       ($0.49)     $0.07         ($0.19)      ($0.33)       (173%)    (37%)      (113%)      693      894    (33%) (7%) 29%        173     274     (9%)   (4%)    (7%)    NM       NM     -4%   -2%    NA      NA      30%     9%
NE                   $6.45         $5.34       $5.23         $1.43        $1.22          12%      (17%)      (2%)      3,348    3,425     6%     (8%)   2%     2,054   2,042   56%    47%     45%     NM       NM     19%   18%    NA      NA     203%    30%
PDE                  $2.23         $1.77       $3.46         $0.42        $0.31         (23%)     (21%)       96%      1,524    2,028    (8%)    (5%)   33%    548     961     29%    24%     36%     NM       73%     5%   NA     NA      NA     620%    72%
RDC                  $2.98         $2.40       $1.70         $0.77        $0.67         (26%)     (19%)      (29%)     1,779    1,825    (20%)   0%     3%     603     506     28%    23%     17%     NM       NM      9%   NA     NA      NA     266%    28%
RIG                  $11.38        $8.00       $9.00         $2.28        $1.82         (19%)     (30%)       13%     10,745 11,161      (8%)    (7%)   4%     5,242   5,680   42%    34%     35%     NM       85%     8%   NA    25%     20%     86%     13%
  Offshore Driller Average                                                              (31%)     (21%)      (4%)                        (9%)    (3%)   11%                    38%    32%     35%    14%       67%    13%   8%    25%     20%     294%   31%

HP                   $3.18         $2.33       $2.50         $0.61        $0.58         (26%)     (27%)       7%       1,749    1,949    (8%)    (7%)   11%    668     724     30%    23%     23%    124%      21%     9%   NA     NA      NA     125%    19%
NBR                  $1.29         $1.01       $1.70         $0.21        $0.18         (57%)     (22%)       68%      3,738    4,248    (33%)   NA     NA     1,653   1,908   18%    16%     19%     NM       42%     7%   NA     NA      NA     71%     13%
PTEN                 ($0.17)       $0.24       $0.24         $0.03        $0.01         (107%)     NM         NM        862     1,202     4%     NA     NA     384     444     (2%)   7%      5%     (7%)      1%      2%   NA     NA      NA     135%    51%
  Land Drille r Average                                                                 (63%)     (24%)       38%                        (12%) (7%)     11%                    15%    NA      NA     58.4%    21.5%    6%   NA     NA      NA     110%   28%

US Coverage Universe Average                                                            (45%)     (12%)       37%                        (14%)   2%     13%                    21%    19%     21%    31%       33%    10%   9%    11%     6%
OSX             44.65        42.00             51.17                                    -57%       -8%        51%
SPX                  61.70         81.02       92.50                                    -11%       31%        14%
(1)
      Segment margin s only.
(2)
      BJS and ATW refle ct calendar year.
Note: Oilfield Margins for International Service Coverage reflect total EBIT margins.
  Source: Blo omberg; Company accounts; Credit Suisse estimates

Source: Company data, Credit Suisse estimates




Macondopendium                                                                                                                                                                                                                                            40
                                                                                                14 June 2010



Integrated Oils: BP - Potential value; but no visibility
(June 2nd, 2010)
■   Top kill failed, LMRP option not a permanent solution: After the failure of the top-
    kill last weekend, the best hope for a permanent solution now appears the two relief
    wells that will not reach target depth until early August, and these are not without risk
    either. We cut our TP to 560p.

■   Revising potential clean-up costs and liabilities upwards: At the higher flow rate
    of 12-19kbd, by early August when relief wells are drilled, Macondo could have spilled
    45-72million gallons of oil into the Gulf (4-7x ExxonValdez). Clean-up costs could total
    $15-23bn plus $14bn of claims. This would absorb 3 years of BP’s free cashflow after
    dividends and capex (at $80/bbl oil) and require a 10% rise in gearing; raising dividend
    risk.

■   3 containment options offer some hope: Importantly, BP plans 3 containment
    options, (1) the LMRP cap, (2) reversing the manifold that BP used for the top-kill and
    (3) an "overshot tool" with a separate floating riser that, most importantly, can quickly
    be released and re-connected in the event of a hurricane. Given the limited success
    thus far, confidence in these solutions will be low until proven otherwise. However,
    were these containment solutions to work, the amount spilt could be capped at around
    35million gallons (3x ExxonValdez), potentially capping clean up at ~$13bn.

■   Cutting target price to 560p/sh ($49/sh ADR): We lower our target price to
    560p/share ($49/sh ADR) to reflect 1) the additional clean-up cost liability ($5/ADR)
    given flow rate of 12-19kbd for 90days, and 2) a lower target multiple now at an 8%
    discount to supermajor peers RDS and Total ($4/ADR). Our new TP of 560p leaves
    upside of c.33%, more than some peers though other Big Oils also offer value. After
    today’s 15% share price drop ($20bn), BP is now trading on 5.5x 2012 P/E (a 30%
    discount to peer group avg), a 8.9% dividend yield and a 9.8% FC yield in 2011.
Clean up - by the numbers

■   While the path of clean up costs and liabilities remains uncertain, this note includes
    analysis of the current run rate of activity and costs to suggest a framework for both
    cleanup costs and claims.

■   Skimming is providing a partial offset but hurricane risk is rising: Clearly, BP will
    want to fight this battle offshore. Based on BP's data, there are now 1,600 vessels
    currently involved in the surface operation (up from 1,100 two weeks ago). BP has
    skimmed some 321,000 barrels so far. This is equivalent to around 18% of the
    Macondo spill based on a skimming efficiency of 40%. At an 18% capture rate,
    skimming should reduce the shore clean up costs by around $4bn over 90 days.
    Skimming will continue for as long as practicable. Capturing oil using the LMRP should
    also help reduce the clean-up costs, if successful. Some 700 miles of protective boom
    have been deployed. However, without a permanent solution, we note that much of
    these spill mitigation efforts are vulnerable to hurricanes – booms and skimmers only
    work in calm water.

■   Cost run rate suggests our c.$16bn clean-up cost estimate would last
    approximately one year. In this short note, we have created a table of the operational
    metrics and cost run rate of the response from information released on BP's website.
    So far $990m has been spent (including claims and grants to the affected states), with
    a further $500m pledged for research into the impact of the spill. At the most recent
    cost run rate for clean-up alone of between $14-30m per day, BP would spend around
    $11-17bn over 12 months. However, unless the flow of oil is curtailed (via LMRP or
    otherwise) we believe the cost run rate will rise for 3 reasons (1) more skimmers will
    be required (2) as more oil hits shore, the number of personnel involved will rise from



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                                                                                                 14 June 2010


    its current level of 22,000, and (3) there will be further costs for onshore clean-up
    equipment. Currently, we believe our revised $16bn clean-up cost estimate would last
    approximately one year. Based on potential spill volumes compared with
    ExxonValdez, the clean-up costs could be anywhere between $15-23bn over several
    years.

■   Three containment options could reduce this potential liability and offer
    hurricane solution. BP is working on three separate containment options (1) the
    LMRP cap, which will aim to capture flowing oil and its efficiency will depend on the
    seal with the cut riser, (2) reversing the flow via the top-kill manifold and importantly
    (3) an "overshot tool" with a separate floating riser that can quickly be released and re-
    connected in the event of a hurricane. Given the limited success thus far, confidence
    in these solutions will be low until proven otherwise. However, were these containment
    solutions to work, the amount spilt would be capped at around 35million gallons (3x
    ExxonValdez) and potentially capping clean up costs in the $13bn range.

■   Risk of dividend cut is rising. On our $80 oil price assumption, we forecast annual
    free cash flow of $6bn on average over 2010-13 after capex of $21.5bn and dividends
    of $10.5bn. We have included $15.6bn of clean-up costs in the P&L (which should be
    tax deductible) and $14.4bn of claims liabilities in the cash flow statement. Taken
    together, this $30bn pre-tax outgoing is some $13bn higher than our previously
    published forecasts of clean-up costs and claims liabilities in our 28-May note (“Top
    Kill Ongoing, Liabilities to Rise”), an increase that is equivalent to 10% of BP's market
    cap. Based on these numbers and a $80/bbl oil price, BP’s gearing (net debt to equity)
    should still actually fall from 25.9% at end-2009 to 23% at end-2013, providing some
    headroom in the event clean-up costs and/or claims are higher than our assumptions,
    but dividend risks are clearly rising. We note that our balance sheet forecasts exclude
    any punitive damages which would require gross negligence to be proven.

Exhibit 58: Installing a Lower Marine Riser Package (LMRP) Cap




Source: Company data, Credit Suisse estimates




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                                                                 14 June 2010



Exhibit 59: Installing a Lower Marine Riser Package (LMRP) Cap




Source: Company data, Credit Suisse estimates



Exhibit 60: Clean-up costs estimates




Source: Company data, Credit Suisse estimates




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                                                           14 June 2010



Exhibit 61: Estimate of liabilities for economic damages




Source: Company data, Credit Suisse estimates




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                                                                                              14 June 2010



US E&P: Delays in the Deepwater GOM, Reduce
Targets (June 1st, 2010)
■   Oil Spill Moratorium Brings Delays, Uncertainty. We are reducing Gulf of Mexico
    project values for Anadarko Petroleum (APC), Noble Energy (NBL), Plains Exploration
    & Production (PXP), Murphy Oil (MUR) and Newfield Exploration (NFX) following the
    Executive Order released last Thursday (May 27) for a 6-month suspension on
    deepwater Gulf of Mexico (GOM) drilling activity (including 33 'active' wells). The
    Department of Interior's new directives (see below) also signal more uncertainty on
    project start ups and costs (both time and money) associated in adhering to new
    regulations.

■   Reduce Price Targets. Following the Executive Order released last Thursday, we are
    reducing our target price on APC to $71 from $77, NBL falls to $91 from $96, PXP falls
    to $29 from $37, MUR falls to $63 from $64 and NFX falls to $63 from $65.
Anadarko Petroleum (APC)

■   We reduce our target price to $71 from $77, which is based on parity to our 'PD Plus'
    NAV run at $80 oil and $7 gas long-term. Our revised NAV includes $3.70 per share of
    value tied to unbooked discoveries in the Gulf of Mexico (5% of total value) versus
    $6.70 per share prior; a reduction of 45%. Key projects that were deferred include
    Caesar-Tonga ($1.50 per share vs. $2.10 prior), Lucius ($0.70 per share vs. $1.30
    prior), Heidelberg, ($0.90 per share vs. $1.30 prior), Vito ($0.60 per share vs. $0.90
    prior), Shenandoah (removing value from our NAV vs. $0.70 prior) and Samurai
    (removing value from our NAV vs. $0.40 prior). Current appraisal activity which must
    be halted per the Executive Order include Heidelberg (44.25% APC WI) and Lucius
    (50% APC WI). Our 2010, 2011 and 2012 production estimates fall 1%/3%/4% putting
    yr/yr organic growth at 6%/0%/5% (assuming Caesar/Tonga start-up is pushed to
    2012). Per latest available data, the Gulf of Mexico represented 12% of reserves and
    26% of production.
Plains Exploration & Production (PXP)

■   We reduce our target price to $29 from $37, which is based on parity to our 'PD Plus'
    NAV run at $80 oil and $7 gas long-term. Our revised NAV includes $3.20 per share of
    value tied to unbooked discoveries in the Gulf of Mexico (11% of total value) versus
    $11.30 per share prior; a reduction of 72%. Key projects that were deferred include
    Friesian (removing value from our NAV vs. $1.90 prior), Vicksburg (removing value
    from our NAV vs. $2.40 prior), Lucius ($1.70 per share vs. $3.00 prior) and Blueberry
    Hill ($0.80 per share vs. $1.00 prior). We are also removing value for Davy Jones from
    our NAV ($1.80 prior) and while we recognize Davy Jones is in shallow water, we
    presume the higher pressures and innovation associated with the ultra-Deep Shelf will
    put that play under heavy regulatory scrutiny. Current appraisal activity which must be
    halted per the Executive Order includes the APC-operated Lucius discovery (33.3%
    PXP WI). Our 2010, 2011 and 2012 production estimates fall 0%/1%/7% putting yr/yr
    organic growth at 7%/11%/10%. Per latest available data, the Gulf of Mexico
    represented 4% of reserves and 10% of production.
Noble Energy (NBL)

■   We reduce our target price to $91 from $96, which is based on parity to our 'PD Plus'
    NAV run at $80 oil and $7 gas long-term. Our revised NAV includes $1.60 per share of
    value tied to unbooked discoveries in the Gulf of Mexico (2% of total value) versus
    $6.20 per share prior; a reduction of 74%. Key projects that were deferred include
    Galapagos - Isabela, Santa Cruz, Santiago ($1.60 per share vs. $2.20 prior) and
    Gunflint (removed all value from NAV vs. $4.00 prior). Current exploration activity
    which must be halted per the Executive Order include a sidetrack at Deep Blue (34%



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    NBL WI) while the Gunflint appraisal well (37.5% NBL WI) will likely be pushed back to
    2011 (from Q2’10 spud). Our 2010, 2011 and 2012 production estimates fall
    0%/3%/1% putting yr/yr organic growth at - 2%/6%/18% (assuming Galapagos
    development is pushed out to 2012). Per latest available data, the deepwater Gulf of
    Mexico represented 4% of reserves and 10% of production.
Murphy Oil (MUR)

■    We reduce our target price to $63 from $64, which is based on parity to our 'PD Plus'
    NAV run at $80 oil and $7 gas long-term. Our revised NAV includes $0.70 per share of
    value tied to unbooked discoveries in the Gulf of Mexico (1% of total value) versus
    $2.10 per share prior; a reduction of 67%. Key projects that were deferred include
    Samurai (removed all value from NAV vs. $0.90 prior) and DC 4 (removed all value
    from NAV vs. $0.30 prior) while development drilling at Thunder Hawk (37.5% MUR
    WI) will be delayed as well. Current exploration activity which must be halted per the
    Executive Order include a sidetrack at the NBL-operated Deep Blue (9.375% MUR
    WI). Our 2010, 2011 and 2012 production estimates fall 0%/2%/2% putting yr/yr
    organic growth at 23%/9%/5%.
Newfield Exploration (NFX)

■   We reduce our target price to $63 from $65, which is based on parity to our 'PD Plus'
    NAV run at $80 oil and $7 gas long-term. Our revised NAV includes $0.80 per share of
    value tied to unbooked discoveries in the Gulf of Mexico (1% of total value) versus
    $1.60 per share prior; a reduction of 50%. Key projects that were deferred include
    Pyrenees ($0.80 per share vs. $1.60 prior) where drilling is currently finishing up. Our
    2010, 2011 and 2012 production estimates fall 0%/0%/3% putting yr/yr organic growth
    at 12%/8%/11%. Per latest available data, the deepwater Gulf of Mexico represented
    5% of reserves and 11% of production.

The Department of Interior Directives for Offshore Drilling:
Related specifically to the Gulf of Mexico

■   A moratorium on drilling of new deepwater wells until the Presidential Commission
    investigating the BP oil spill has completed its six-month review.

■   Permitted wells currently being drilled in the deepwater (not counting the emergency
    relief wells being drilled) in the Gulf of Mexico will be required to halt drilling at the first
    safe stopping point, and then take steps to secure the well.

■   The pending August Gulf of Mexico lease sale has been canceled.

■   BOPs must be re-inspected and receive independent recertifcation to insure any
    modifications/upgrades will not compromise the BOP functionality.

■   BOPs will require a second blind shear ram (most only have one) within a year.

■   Tougher requirements on well control, construction and flow intervention (including
    cement in drill casings) design and processes, which will require expert review and
    verification Department of Interior working groups are to be established to further
    develop measures and recommendations.
Other

■   The proposed offshore Virginia lease sales were cancelled and exploratory drilling in
    the Arctic was suspended, including Shell’s proposal to drill up to five Arctic
    exploration wells this summer.




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                                                                             14 June 2010



Exhibit 62: Target Price Changes to Companies with Gulf of Mexico Projects




Source: Company data, Credit Suisse estimates




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US OFS: Macondolypse Now Means Now – Initial
Safety Rules and the 6-month Pause (May 30th, 2010)
■   6 month drilling pause: The Department of Interior (DOI) has ordered a pause to
    assess what changes to safety regulations are required. Existing drilling activity is to
    pause as soon as safe/practicable.
■   Some specific BOP directive; others subject to further study: Two sets of blind
    shear rams, spaced at least 4 feet apart, will be required. Other directives buy more
    time to bolster existing rules—e.g. the DOI must develop new deepwater well control
    procedures within 120 days. See Exhibit 64.
■   We cannot readily assess capital requirements for BOPs: Although we can access
    the number of rams on a floating rig, we cannot distinguish between shear, pipe and
    blind. The DOI is requiring this detail within 15 days.
■   Refining our earnings impact analysis for diversified service from our original
    Macondolypse Now note (dated May 18) to focus on H2 2010; this lowers the
    relative impact on WFT: There are still a lot of guesswork involved, but specifically
    for H2 2010, we think the negative EPS impact on diversified services if there is no
    deepwater activity is BHI: 17%, HAL: 14%, WFT: 12% and SLB 6% (for oilfield only
    and perhaps 10% including seismic). The most dramatic change from our earlier
    comments if for WFT as 2H10E worldwide EPS is much higher than 1H10E. See
    Exhibit 63.
■   We can start to consider the impact for other segments as well: Deepwater
    support (boats, helicopters) is negatively impacted. Drilling support ROVs are impacted
    as well; we would expect OII to have customers try to at least “get out of” the labor
    portion of their rates. In that case, the earnings impact for OII would depend on how it
    can manage its workforce, although it is somewhat limited regardless given the size of
    its total fleet.
■   As rules become more concrete, we expect to see other countries consider
    adoption: Thus far we have seen only African independent oil and gas company Afren
    say it had experienced a 7-8% increase in costs for a project in Ghana following rule
    changes by Ghanian authorities. But we understand the European Union has said it
    would analyze the findings of the U.S. safety review to determine if its members should
    toughen regulations. And Canada has, like the U.S., delayed Beaufort Sea exploration.
■   We are still cautious on the group: Despite OSX underperformance, the risk to
    offshore activity keeps us cautious on the group. Within the group, we prefer onshore
    oily exposure, although shallow water drillers/service, BOP providers and onshore oil-
    exposed also appear better positioned. Big cap service falls in between given
    diversified exposure.


Refining Earnings Sensitivity for specifically H2 2010 for Diversified Services
Included in our recent Macondolypse Now note was a frame of reference to consider
earnings impact on diversified service names. That was a more general exercise. Today
we refine this, although we still include many estimates (more in fact), to get more specific
regarding ceasing deepwater GoM activity for the second half of 2010 (the exercise
assumes all work has stopped by mid-June and is 0 through year end). Please note we
are not changing estimates at this time. On this basis, the estimated big 4 exposure:
(see Exhibit 63)
■   BHI: 17% of 2H10 EPS. This is modestly lower than the 20% we reflected earlier due
    to lower estimated proportional deepwater exposure
■   HAL: 14% of 2H10 EPS. Consistent with prior 15% comment



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■     WFT: 12% of 2H10E EPS. Lower than the 20% we reflected earlier due to higher
      overall earnings (international contribution) in 2H10 versus 1H10. This is more
      consistent with 2011 exposure as well.
■     SLB: Oilfield only: 6%, in line with prior comments. But, factoring in possible declines
      in WesternGeco (multi-client) sales, the impact could be closer to 10%.
Exhibit 63: EPS % Impact of Deepwater GoM Stoppage
                                                                 H2 2010
                                                  SLB             HAL            WFT             BHI
Revenues
Half of Annual GoM Revenue                         500            500             250            550
    Deepwater Est of Total GoM                    75%             65%            50%             50%
    Reduction                                   ($375)          ($325)         ($125)          ($275)

WesternGeco (all Multi-Client)                   $715
    Reduction (primarily lost late sales)       ($250)

Decremental EBIT Margin                           50%             50%            50%             50%

Lost EBIT
GoM Oilfield                                    ($188)          ($163)          ($63)          ($138)
W-G                                             ($113)
    Total                                       ($300)          ($163)          ($63)          ($138)

Tax Impact                                       ($90)           ($49)          ($19)           ($41)


Net Income Reduction                            ($210)          ($114)          ($44)           ($96)

Shares Outstanding                              1,215             906            741             429
Original EPS                                      1.70           0.92           0.48            1.32
EPS Delta                                        (0.17)         (0.13)          (0.06)         (0.22)
    EPS Decline (%)                              -10%            -14%           -12%            -17%
Source: Company data, Credit Suisse estimates

Note: We do not apply the 50% decrementals to W-G. And we do not assume any forced amortization is
required. Instead we estimate foregone revenue at 45% margin




Exhibit 64: U.S. Department of Interior Recommendations for Increased Safety in Offshore Drilling
 Recommendations                                              Key Components (with implementation plan)
 Blowout Preventer (BOP) Equipment and                         • Order re-certification of subsea BOP stacks
 Emergency Systems                                                (immediately)
                                                               • Order BOP equipment compatibility verification
                                                                  (immediately)
                                                               • Establish formal equipment certification
                                                                  requirements (rulemaking)




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                                                                                                                              14 June 2010


 New Safety Equipment Requirements and Operating                • Develop new BOP and remote operated vehicle
 Procedures                                                       (ROV) testing requirements (immediately)
                                                                • Develop new inspection procedures and reporting
                                                                  requirements (immediately)
                                                                • Develop secondary control system requirements
                                                                  (emergency rulemaking)
                                                                • Establish new blind shear ram redundancy
                                                                  requirements (emergency rulemaking)
                                                                • Develop new ROV operating capabilities
                                                                  (rulemaking)

 Well-Control Guidelines and Fluid Displacement                 • Establish new fluid displacement procedures
 Procedures                                                       (immediately)
                                                                • Establish new deepwater well-control procedure
                                                                  requirements (emergency rulemaking)
 Well Design and Construction – Casing and                      • Establish new casing and cementing design
 Cementing                                                        requirements – two independent tested barriers
                                                                  (immediately)
                                                                • Establish new casing installation procedures
                                                                  (immediately)
                                                                • Develop formal personnel training requirements for
                                                                  casing and cementing operations (rulemaking)
                                                                • Develop additional requirements for casing
                                                                  installation (rulemaking)
                                                                • Enforce tighter primary cementing practices
                                                                  (rulemaking)
                                                                • Develop additional requirements for evaluation of
                                                                  cement integrity (immediately)
                                                                • Study Wild-Well intervention techniques and
                                                                  capabilities (immediately)
 Increased Enforcement of Existing Safety                       • Order compliance verification for existing
 Regulations and Procedures                                       regulations and April 30, 2010, National Safety
                                                                  Alert (immediately)
                                                                • Adopt safety case requirements for floating drilling
                                                                  operations on the Outer Continental Shelf
                                                                  (emergency rulemaking)
                                                                • Adopt final rule to require operators to adopt a
                                                                  robust safety and environmental management
                                                                  system for offshore drilling operations (rulemaking)
                                                                • Study additional safety training and certification
                                                                  requirements (rulemaking)

Source: U.S. Department of Interior, Increased Safety Measures For Energy Development On The Outer Continental Shelf, May 27, 2010

Notes to category of recommendation/rule:
    •    Immediately: expect implementation within 30 days
    •    Emergency rulemaking: the Department is to issue interim final rules to implement these recommendations. Such rules will become
         effective immediately upon issuance, but will also be opened for public review and comment
    •    Rulemaking: related to recommendations requiring further study and, therefore, will be addressed through notice and comment


Longer term, the report hints at a new regulatory approach; we’re interested to see
the implications.
The DOI report mentions that other countries        rules regimes are more performance
                                                      ’
based versus our current more prescription-weighted basis. And it implies that
performance based systems allow more fluid adoption of best practices. Thus, while the
report’s response seems to be more prescription, it also seems to be advocating a shift to
performance-based oversight.



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Integrated Oils: BP - Top Kill Ongoing, Liabilities to
Rise (May 28th, 2010)
■   Raising spill flow rates and liabilities: Over the last 37 days and using the upwardly
    revised range of 12-19kbd, the Macondo well has now spilt some 23.3mn gallons of oil
    into the Gulf at midpoint compared with the ExxonValdez at 10.8mn gallons, the worst
    spill in US history. BP has already incurred some $850mn in costs. Higher flow rates
    result in a raised estimate of clean up costs to a range of $4 - $9.8bn (from $2.5-
    8.5bn). Our estimate of the present value of claims liability remains ~$8.6bn, with
    upside risks given the affected revenues in the region. Total liability could therefore
    add up to $17.6bn. Operational anomalies prior to the explosion raise concerns over
    punitive damages also, though there remains legal debate concerning the interplay of
    OPA and maritime law.

■   Adjustments to earnings and capex: We have lowered earnings for BP by 14% in
    2010, 10% in 2011, and by 3% in 2012 and 2013. This reflects clean up expenses,
    claims paid out, lower back-end Gulf of Mexico production and at this stage $300M of
    additional regulatory upstream capex per year. It does not include punitive damages at
    this stage.

■   Adjustments to Target Price: Prior to Macondo, we felt the higher reinvestment
    returns across BP's portfolio and the improved focus on operational excellence under
    CEO Tony Hayward would drive BP to a premium vs. IOC peers. Macondo raises
    questions regarding BP's futureability to win licenses as a reliable global operator,
    arguing for a higher discount rate versus peers. Despite BP’s higher portfolio returns,
    we havelowered our target multiples to be in-line with peer averages. As a result of
    changes to earnings, capex and target multiples, our ADR TP falls to $57.8/sh
    (660p/sh at current GBP FX) from $64.4.
BP – Revising Liabilities Higher

■   Although BP may stop the Macondo well from spilling with this top-kill, the uncertainty
    over the shares will remain for several months. The focus is now on collecting as
    much of the spill offshore, and cleaning the onshore coastline that will be affected.
    Higher well flow rates that have been revised upwards to 12-19kbd drive up the clean-
    up and claims liability that we published several weeks ago from $16bn to circa
    $17.6bn, assuming a higher flow rate AND a successful top-kill. It also raises the need
    for this “top-kill” to work. Waiting a further two months at this higher flow rate does not
    look a good prospect for the Gulf or BP shareholders.
Adjusted Valuation Methodology

■   In the table below we adjust our Blended Target Price for BP to reflect the present
    values of various scenarios for clean up costs and liabilities that are shown in more
    detail in the Appendix. In Scenario 1, BP pays 65% of claims, its partners share the
    remainder, In scenario 2, BP pays the full amount because partners are somehow
    able to avoid claims under the yet to be seen partner agreement due to some form of
    negligence on BP’s behalf. In Scenario 3, BP pays the full amount of claims and clean
    up as well as incurring punitive damages (the basis for which is not currently known).
Reduce Target Price

■   We have lowered our ADR TP from $64.4/sh to $57.8/share. The implied liability in
    this target price would correspond most closely to the scenario where BP is liable for a
    100% of clean-up costs/claims but it does not include punitive damages. We stress
    that this scenario (and target price) remains subject to both positive and negative
    uncertainties in this flexible situation, and in light of the higher flow rates released
    yesterday.




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                                                                                             14 June 2010



Exhibit 65: Scenarios for BP Valuation Ranges




Source: Company data, Credit Suisse estimates



BP Remains Financially Strong

■   On our current $80/bbl oil price forecast, BP generates ~$6.0bn of free cashflow after
    capex and dividends on average over 2011 to 2013. We have included outflows of
    $11.5bn for clean up costs and claims in our model. Based on this level of cash
    outflow, gearing actually still falls from current levels of 19.6% in 1Q10 to 17.7% in
    2012, allowing some head room if claims and damages are greater than our forecasts
    to maintain business reinvestment capex and to maintain the dividend.

■   These are large numbers and only a company with strong free cash generation and
    delivered balance sheet such as BP could withstand their burden. These estimates are
    also subject to considerable uncertainty. We note that the share prices of other
    companies in the group have also fallen, some almost as much as BP. We would
    continue to highlight that concern over the Euro area and the fall in oil prices has
    opened up value across the group, and in companies with considerably less
    unforecastable event risk. In particular we highlight onshore names to avoid 2nd
    derivative offshore growth and cost impacts on EPS.

Exhibit 66: Blended Target Prices – Integrated Oils (Post-Liability for BP)




Source: Company data, Credit Suisse estimates




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Exhibit 67: Recent share price movements since Macondo well impact




Source: Company data, Credit Suisse estimates



Industry Impacts
The President has announced four new actions in response to the Macondo spill:
1) to suspend exploration off two locations in Alaska
2) to defer upcoming GoM and Atlantic Coast lease sales
3) to continue the existing moratorium on new deepwater permits for 6 months
4) to suspend drilling on 33 wells in progress in the GoM currently ()
As we have published in recent notes since Macondo, this spill has demonstrated
verypowerfully that deepwater oil exploration and production has risks that policymakers
(and some in the industry) were previously unaware. In particular, the subsea response
and the 100% failsafe nature of Blowout Preventers (BOPs) has been called into question.
Now that full environmental audits will be applied for Gulf of Mexico drilling, we believe
there remains a chance that this moratorium is extended. This has positive impacts for the
oil price – circa 1.6MBD of 2017 growth projects in Non-OPEC are in GoMexico deepwater
– but raises concern over the growth prospects of the offshore levered oils. We show the
percentage reserves exposure to the offshore and to the US Gulf of Mexico in the charts
below. We will likely need to make further adjustments to peer group companies as the
Macondo impacts become more fully known. In the meantime, we stress onshore oil
names that continue to offer value.




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                                                                                                              14 June 2010



Exhibit 68: Offshore reserves as % of 2P reserves             Exhibit 69: Deepwater GoM as % of 2P reserves




Source: Company data, Credit Suisse estimates                 Source: Company data, Credit Suisse estimates



Exhibit 70: Current operated deepwater activity (# of rigs)




Source: Company data, Credit Suisse estimates




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Exhibit 71: A Framework for Indicative Revenues and Potential Liabilities




Source: Company data, Credit Suisse estimates




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Integrated Oils: Macondo Big Oil - Gulf of Mexico
Project Delays (Part 2) (May 28th, 2010)
■   Production forecasts: In our note this morning, we outlined the EPS impacts from a 1
    year delay to US Gulf of Mexico startup dates for new projects. In this note, we include
    two tables of production growth which contain - (1) our pre-Macondo forecasts, (2)
    New forecasts with a 1 year delay and (3) in response to investor queries we lay out a
    worse case with no new projects on-stream before 2015. As we highlighted with our
    EPS changes, the impacts on production are relatively muted, with the exception of
    HES who is bringing on the Pony field which would account for 7.1% of production in
    2015. At this stage, we still expect this field to come on stream, so the impact on value
    is time value rather than loss.

■   New MMS Regulations: Secretary of Interior Ken Salazar issued several directives
    regarding offshore drilling yesterday, amplifying on President Obama.s statements in
    the press conference. Some of these directives will be immediately sent in Notices to
    Lessees, and a final interim rule will be issued within 120 days. The most onerous
    appear to be the requirement to have two shear rams on BOP’s and tougher well
    control, construction and flow intervention regulations. Our services team will follow up
    on the likely time-frame that it would take for BOP manufacturers to comply with this
    directive.

■   Related specifically to the Gulf of Mexico:
    o     A moratorium on drilling of new deepwater wells until the Presidential
          Commission investigating the BP oil spill has completed its six-month review.
    o     Permitted wells currently being drilled in the deepwater (not counting the
          emergency relief wells being drilled) in the Gulf of Mexico will be required to halt
          drilling at the first safe stopping point, and then take steps to secure the well.
    o     The pending August Gulf of Mexico lease sale has been cancelled.
    o     BOPs must be re-inspected and receive independent recertification to insure
          any modifications/upgrades will not compromise the BOP functionality.
    o     BOPs will require a second blind shear ram (most only have one) within a ear.
    o     Tougher requirements on well control, construction and flow intervention
          (including cement in drill casings) design and processes, which will require
          expert review and verification Department of Interior working groups are to be
          established to further develop measures and recommendations.




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Exhibit 72: Scenario 1: Assuming a 1-yr delay in new GoM project start-ups




Source: Company data, Credit Suisse estimates




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Exhibit 73: Scenario 2: Assuming an indefinite delay in new GoM project start-ups




Source: Company data, Credit Suisse estimates




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Integrated Oils: Delaying Gulf of Mexico projects
(May 28th, 2010)
■   Gulf of Mexico projects delayed: We have delayed all new Gulf of Mexico projects
    by 1 year today. This reduces growth rates and EPS across the Big Oil group; though
    delays mainly affect the back-end of our 2015 forecast period. We have maintained
    capex for the group because we understand that force majeure might be difficult to
    enforce on offshore rigs. BP is most impacted; XOM and COP the least. Note that we
    have published a separate note on BP today titled .Top Kill Ongoing, Liabilities to
    Rise.

■   Exploration value creation deferred; Reduce BP and Hess TPs: Part of our Big Oil
    Fights Back thesis reflected a renewed focus on exploration spend as a route to higher
    returns, with the Gulf of Mexico being a key contributor. With the current uncertainty,
    investors may be unwilling to price exploration upside from Gulf of Mexico discoveries
    until the new operating environment is more fully known. As a proxy for this
    exploration value, we show the possible reserves in the US Gulf of Mexico as a
    percentage of Total 3P reserves. CVX and HES appear to have a greater exposure
    than average at 4-5%, other companies <1% on this measure. Our target prices had
    already incorporated a 10% "skepticism" cushion relative to theoretical valuations. Gulf
    of Mexico delays have eroded some of this. We have reduced BP and HES target
    prices by 10% and 3% respectively.

■   In adversity, comes opportunity: At this stage we cannot gauge the full regulatory
    response to Macondo - however, this incident could shake-up the players who
    currently have exposure to this high value region, which could offer opportunities to
    companies like COP, Statoil, and Total who have expressed interest in greater
    exposure.

■   Higher oil prices, all things being equal: The market is currently digesting several
    competing crosswinds. Delays in US Gulf drilling (33 wells are suspended today) and
    reports of a well suspension in India are competing with Euro debt crisis contagion
    fears. On balance we believe oil prices look oversold within our $65-90/bbl range,
    given the 1.6 MBD of growth projects in the US GoMexico by 2017 and 8MBD of
    offshore growth globally.

■   Onshore preferred; Big Oil still offers value: Although, we like onshore oil plays, we
    flag that as a result of Euro concerns, and some Macondo influence, Big Oil looks
    undervalued (MRO in particular). While the exploration thesis is deferred, Big Oil
    trades on 7.6x 2011 P/E which looks too low.

Gulf of Mexico Impact
■   Today we have run a 1yr delay and higher costs through the US Gulf of Mexico
    production of the Big Oils to reflect policy responses to the Macondo Spill.
    Considerable policy uncertainty remains while the bipartisan commission evaluates
    the implementation of what the President calls .aggressive new operating standards
    and requirements for offshore energy companies. and .why it.s so important that this
    commission moves forward and examines, why did this happen; how should this
    proceed in a safe, effective manner; what.s required when it comes to worst-case
    scenarios to prevent something like this from happening again.

■   Both in the design/operation of wells (cementing and BOP.s) and in the response to a
    subsea deepwater blowout (a three month relief well does not seem to be an
    acceptable response) improvements look required in order to satisfy this commission.
    The likely impact on Big Oil.s value will be higher upstream costs, project delays and
    an unwillingness for investors to price exploration upside from Gulf of Mexico




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    discoveries until the new operating environment is more fully known. As a proxy for
    this exploration value, we show the possible reserves in the US Gulf of Mexico as a
    percentage of Total 3P reserves. CVX and HES appear to have a greater exposure
    than average at 4-5%, other companies <1% on this measure.

Exhibit 74: US Deepwater Possible reserves as % of Total Reserves (3P)




Source: Company data, Credit Suisse estimates



Exhibit 75: US GoM acreage (mn acres)                       Exhibit 76: Arctic acreage (mn acres)




Source: Company data, Credit Suisse estimates               Source: Company data, Credit Suisse estimates



Change to Earnings
■  On average, integrated oils. earnings for 2011 decrease by 2.2%, 2012 and 2013
   decrease by ~1%, while 2014 EPS decreases by 1.8% as a result of project delays
   and higher costs.

Exhibit 77: Credit Suisse Old vs, New EPS




Source: Company data, Credit Suisse estimates




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Change to Target Price
■  Our target prices had already incorporated a 10% "scepticism" cushion relative to
   theoretical valuations. Gulf of Mexico delays have eroded some of this. We have
   reduced BP and HES target prices by 10% and 3%, respectively. MRO continues to
   look more attractively valued than peers.

Exhibit 78: Blended Target Prices . Integrated Oils (Post-Liability for BP)




Source: Company data, Credit Suisse estimates




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Credit Suisse Energy Team Goes to D.C. – Two
Positives; But Remain Cautious on Group (May 27th,
2010)
CS Energy spent a day in Washington discussing the Macondo disaster and hydraulic
fracturing with Congressional staffers and industry experts.

■   We are still cautious on the group: As we all watch for the outcome of the top kill
    effort, the risk to offshore activity keeps us cautious on the group. But our day in DC
    yielded positives on the margin: (1) Gulf of Mexico (GoM) shallow water permitting
    may resume shortly and (2) Congress seems to understand that excessive liability
    caps may choke off development activity.

■   Differentiating within the group: We continue to see risk in deepwater exposure
    while shallow water drillers/service, BOP providers and onshore oil-exposed appear
    better positioned. Big cap service falls in between given blended exposure, with SLB
    relatively less GoM exposed than peers.

■   Slowdown in deepwater activity seems likely: Our contacts expect either the
    Obama administration or Congress to extend the deepwater drilling moratorium as
    investigation/solution-crafting continues. This could include allowing the MMS up to 90
    days to process permits versus 30 currently.

■   But Congress “gets” a distinction between deep and shallow water: our contacts
    expect permitting to resume for shallow water soon, perhaps as early as the initial May
    28 deadline.

■   Liability caps to rise, but perhaps less than feared: This issue clearly still has
    populist overtones, but we heard an understanding of the risk of “pricing out” smaller
    oil companies of the GoM with $10B+ caps. One source suspected the shallow water
    cap could be lifted, but to only $150MM.

■   Cementing still getting BP scrutiny—now it’s the “equipment”: We sensed that
    BP’s internal investigations are progressing more slowly than it expected. But BP’s
    new information included that the float collar used in the cement job did not function
    properly initially and that the float test “may not have been definitive”. We have
    established HAL did not provide the float collar or perform the float test.

■   More regulation expected: There was a general expectation that (1) offshore
    development would be subject to more regulation and (2) some BOP
    upgrade/redundancy requirements would be imposed.

■   Which comes first, inquiry or legislation? The answer seems likely to be a
    balancing act with inquiry continuing but perhaps pressure to show action yielding
    legislative proposals (out of committee?) by summer.
Congress Looks at Shallow Versus Deepwater

■   We are encouraged by what appears to be broad-based commentary distinguishing
    shallow water from deepwater hydrocarbon development. It seems clear there is an
    appreciation that much of the challenge of handling the spill relates to the water depth.
    (There may also be the perception that shallow water is dominated by natural gas,
    although the recovery in the GoM rig count, and thus the shallow water rig count, has
    been oil-directed). There is also appreciation for the more limited financial resources of
    several of the shallow water-exposed oil companies versus the integrateds that
    dominate deepwater development.

■   As a result, we heard confidence that the moratorium on shallow water drilling could
    be lifted soon, perhaps as early as May 28. Further Congressmen appear to be



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    considering proposing lower liability caps associated with shallow water wells, to be
    more commensurate with the industry perception of risk. The liability caps are related
    to the Oil Pollution Act of 1990, in which they were set at $75MM per well. One
    lobbyist we spoke with said he had heard at least one bill proposing a $150MM cap for
    shallow water wells.
    We heard an understanding of the country’s current need for offshore
    hydrocarbon development

■   We clearly expect some continued calls for multi-$B liability exposure in light of the
    Macondo disaster. But our conversations suggested that lower liability caps were a
    distinct possibility. We heard some appreciation that setting $10B, or for that matter,
    an unlimited, liability cap on a deepwater well would likely choke off some oil company
    interest in deepwater development. And we heard that this result was not desired,
    considering that the GoM was going to remain an important source of domestically-
    produced hydrocarbons.
    Diversified Service Company Implications

■   Trying to get closer to calibrating GoM Deepwater exposure for service companies
    Last week, in our note Macondolypse Now dated May 18, we offered an illustration of
    the potential earnings impact on our diversified services (and other OFS) coverage of
    a pullback in service activity. We illustrated that we thought a a 50% revenue decline
    in the GoM (say in 3Q10 or 4Q10) and 50% decremental margins could result in an
    EPS decline of 20% for BHI and WFT, 15% for HAL and closer to 5% for SLB. We
    refer you to that note for further discussion.

■   Ideally, we would modify that analysis to account for these service companies’
    exposure to deepwater versus shallow water. The mix, however, is elusive and so is it
    hard for us to quantify the benefit if/as the shallow water drilling moratorium is lifted, as
    is expected. We roughly think of revenues as an even split. But it is plausible to us that
    BHI’s exposure may be more shallow water than deep given our perception that HAL
    and SLB have stronger market share in the deepwater completions, cementing and
    fluids (i.e. versus M-I). Conversely we have a bias that SLB’s exposure to the GoM is
    weighted to deepwater. We are frankly most unsure about HAL or WFT’s exposures.
    Profitability impacted with deepwater moratorium, but perhaps decrementals
    can be mitigated

■   Note that lower demand can be presumed to be temporary, as with a moratorium, or
    more permanent, the result of higher costs associated with additional regulation or
    oversight, or less capital/fewer participants being willing to participate in deepwater
    drilling as a function of higher liability caps imposed on oil companies.

■   We submit that the source (and duration) of lower deepwater development can greatly
    impact the earnings loss. Short extensions to the moratorium may lead service names
    to make little change to their cost base and thus very high decremental margins.
    However, with some visibility on an extended moratorium or visibility on more
    structural demand loss, it may also allow the diversified service names to adjust GoM
    exposure to some degree.

■   As we also noted in Macondolypse Now, we would suspect the service companies to
    try to shift personnel to either onshore U.S. or perhaps other markets. They would also
    perhaps work to move tools out of the region.
    Hydraulic fracturing disclosure is nipped in the bud

■   Our other avenue of conversation related to potential federal regulation of hydraulic
    fracturing. We have addressed this issue at length in prior notes, including Frac Attack
    dated June 22, 2009. Our contacts generally suspected no action, but were uncertain



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   about the fate of a pending proposal in the House Energy & Commerce Committee to
   to add chemical disclosure requirements for frac companies. Yesterday, Congressman
   Waxman nixed the proposal in Committee, calling for the EPA to do its study first. The
   Congressionally funded study is designed to be a two year effort and kicked off about
   a month ago. Mr. Waxman’s move suggests to us that any risk to regulating frac’ing
   abates for some time.




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US OFS: Macondolypse Now - Earnings Implications
from Potential GoM Delays (May 18th, 2010)
■   We are still cautious on the group given risks to offshore post Macondo: There
    is enough earnings risk in the Gulf of Mexico (GoM) alone to step to the side, in our
    view, although we wonder if the disaster leads to delays or higher costs elsewhere that
    could also impact offshore activity.

■   New well permits in GoM paused until late May; we can easily imagine the pause
    continues: The Department of Interior (DOI) has suspended the approval of new
    offshore drilling permits for the Outer Continental Shelf (OCS) until the DOI completes
    a safety review by May 28. Drilling permits issued prior to April 20 (the date of the
    blow-out at Macondo) are not affected by the moratorium and the DOI order does not
    impact wells in progress.

■   Ironically, the moratorium could be worse for shallow water drillers than
    deepwater drillers: 18 jackups, or 42%, of the contracted fleet, would be off contract
    by mid-year 2010 without the approval of new permits. For EPS illustration purposes,
    in a scenario in which all rollovers are idle until the end of August, HERO, has the
    largest negative EPS impact to 2010 under our offshore driller coverage, down 14%.

■   Deepwater has protection in contract duration and language: The permit freeze
    could have modest EPS implications for floater focused companies in 2010 given
    limited contract rollovers. And although E&Ps could attempt to invoke ‘force majeure’
    clauses in contracts, the deepwater drillers believe these are not applicable as
    deepwater rigs can be used by E&Ps outside of the GoM. The bigger challenge for the
    deepwater drillers is the potential for regulatory changes that meaningfully increase
    the cost of drilling in the GOM.

■   GoM delays can significantly impact BHI, WFT and HAL: Service companies are
    likely ‘stuck” with maintaining overheads as they wait for activity to resume. Again for
    illustration, the earnings impact with a 50% revenue decline in the GoM (say in 3Q10)
    and 50% decremental margins could be 20% for BHI and WFT, 15% for HAL and
    closer to 5% for SLB.

■   Prefer onshore oily exposure; but within the group we favor CAM and PDE and
    to a lesser degree HAL and SLB: Within our cautious stance on the group, we favor
    onshore oily exposed names that can benefit from higher oil prices (we remain wary
    very near term of U.S. onshore low end natural gas exposure). For relative
    performance within our coverage, we see opportunities from share underperformance
    in CAM and HAL and relatively smaller GoM position for SLB. Among drillers, we stay
    to the sidelines on RIG pending a better sense of liability as operating details continue
    to emerge. We remain aggressive buyers of PDE given strong earnings visibility,
    discounted valuation, and potential near term contract catalysts as well as M&A
    optionality.
Summary

■   New well permits in GoM paused until late May. In the aftermath of the Macondo oil
    spill, the Department of Interior (DOI) announced on May 6th that it was halting new
    approval of offshore drilling permits for the Outer Continental Shelf (OCS) until the DOI
    completed a safety review by May 28. Drilling permits issued prior to April 20 (the date
    of the blow-out at Macondo) are not affected by the moratorium and the DOI order
    does not impact wells in progress. Since the spill, 18 permits have been approved, but
    the pace has declined as only 2 permits were approved in the past week.

■   We can easily imagine the pause continuing, creating the basis for meaningful
    negative earnings impact in 2010. The DOI’s action could potentially be very limited



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    in scope and permitting activity could resume in June. But frankly we find it easier to
    imagine that the DOI (or Congress or other parties) continues the pause as it
    recommends some combination of further study and procedural changes. This is
    particularly true, in our opinion, in light of the various alleged “issues” potentially
    related to the Macondo well disaster, including Blowout Preventer (BOP) maintenance,
    time allowed post cement work (to allow the cement to set) and when to remove the
    drilling mud weight.

■   Ironically, the moratorium could be worse near-term for shallow water drillers
    than deepwater drillers. As illustrated in Exhibit 80 and Exhibit 81, the moratorium
    would likely have bigger near-term implications for the GOM jackup focused drillers
    than the GOM deepwater focused drillers given the well-to-well nature of shallow
    water drilling. Historically, shallow water permits have been submitted by operators on
    a near real-time basis, which could prove problematic given the permit freeze. Our
    analysis indicates that 6 jackups could be impacted by the moratorium given the lack
    of permits (3 HERO rigs, 1 ENSCO rig, 1 RDC rig, and 1 HAWK rig). Meanwhile, there
    are 4 floaters (2 DO rigs, 1 Noble rig, and 1 Maersk rig) with availability in 2010, but
    none of these rigs have availability until the back half of 2010.

■   Extended moratorium would be a bigger issue for both shallow and deepwater.
    An extended moratorium on drilling could have meaningful implications for the GOM
    jackup market as 18 jackups, or 42%, of the contracted fleet would be off contract by
    mid-year 2010 without the approval of new permits. While the moratorium could have
    more limited EPS implications for the floater focused companies in 2010 given the
    small number of contract rollovers, we believe the E&Ps could attempt to invoke ‘force
    majeure’ clauses in contracts. Drillers could argue that ‘force majeure’ clauses would
    not be applicable to floating rigs as the rigs could be used by operators in international
    markets outside of the GOM. That said, an extended moratorium would likely be
    unsettling and support the flow of capital to domestic onshore markets or international
    markets. The timing of this could not be much worse given our expectation that an ‘air
    pocket’ is likely in the deepwater market next year given signs of demand saturation
    and uncontracted newbuild additions.

■   GoM delays may also have a significant impact on Service Companies: Service
    companies, which lack the protection of volume minimums in their contracts, are
    subject to maintaining overheads as they wait for activity to resume. Under coverage,
    the earnings impact with a 50% revenue decline in the GoM (say in 3Q10) and 50%
    decremental margins could be 20% for BHI and WFT, 15% for HAL. SLB’s sensitivity
    is somewhat lower given smaller exposure (relative to its total revenues), even, we
    think, if seismic acquisition revenues are included. Clearly, any broadening of delays
    to other offshore markets, which we think is a possibility (see below), would raise the
    negative earnings impact.

■   Stock performance since the incident shows weight on those companies
    directly involved with the Macondo well and appears to reflect these GoM-based
    earnings concerns. The OSX is down 14% since the incident first occurred on April
    20 versus the S&P500 down 7%. HAWK (-30%), HERO (-29%) and RIG (-29%) are
    among the worst performers. CAM is down 20% and lags equipment stocks, HAL is
    down 17% and lags big cap services. Leaders in this period include small cap U.S.
    land service names CPX (+8%) and NR (+6%) as well as some GoM “repair” names—
    HOS and SPN are both down 1%. Land drillers NBR (-5%) and PTEN (-9%) also held
    up reasonably well, as did SLB (-7%). See cap services. Leaders in this period include
    small cap U.S. land service names CPX (+8%) and NR (+6%) as well as some GoM
    “repair” names—HOS and SPN are both down 1%. Land drillers NBR (-5%) and PTEN
    (-9%) also held up reasonably well, as did SLB (-7%). See Exhibit 79.

■   We are mindful that there is risk that delays or additional costs spread outside
    of the GoM. We understand the U.S. Department of Interior has also suggested it


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     would wait for safety reviews before signing off on permits to drill north of Alaska in the
     Chukchi and Beaufort seas. In terms of other government action, thus far we are only
     aware of Canada delaying activity (decisions) as a result of Macondo—Northwest
     Territories have deferred a relief well determination in the Beaufort Sea. But it is easy
     enough to imagine (1) a pause related to best practices applied more broadly and (2)
     greater costs leading to some culling of projects as the economics no longer “work” for
     some relatively higher cost projects.

■    Thus we remain cautious on the group. We believe the uncertainty and overhang of
     Gulf of Mexico—and potentially broader offshore—earnings risk is enough to keep us
     to the sidelines on oilfield services. The pullback in shares does create some attractive
     valuations, in our view. But we wait until we are better positioned to calibrate earnings
     impacts before moving aggressively to take long positions.

■    BOP retrofit/upgrade thesis may make sense, but here too we would prefer
     some sign of the opportunity. The retrofit/upgrade opportunities of BOPs, which
     would benefit CAM and NOV, actually seem a little less compelling today than
     previously given the revelations of apparent “flawed” maintenance that may have
     understated the pressure (if the annular was damaged it may have allowed leakage)
     and leaking hydraulic fluids accumulators. Nevertheless, we believe CAM’s “legal
     position” appears stronger following revelations of (1) modifications to the BOP and (2)
     the maintenance issues, both of which contribute to the sense that the BOP was not
     fully functioning at the time of the blowout.

■    We acknowledge the risk that we are being too negative. There are two basic
     arguments in favor of not shying away from the group, in our view.
1.   Perhaps most importantly, a GoM activity slowdown should help oil prices, helping to
     assuage concern that higher operating costs—a function, potentially, of more
     regulation or more/greater safety emphasis—undercut some of the more economically
     borderline developments.
2.   In addition, there is some chance the changes imposed on the oil industry (or that are
     self imposed) are not that dramatic. Several mistakes/flaws have seemingly been
     uncovered as more is learned about the drilling of the Macondo well. This may strike
     some as ironic, but the easier it is to identify what was done poorly, the more credibly
     the industry can say that established best practices are adequate and “simply” need to
     be followed.




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Exhibit 79: Share Performance Since the Macondo Blowout on 4/20/10
                     5/17/10    4/20/10    1/8/10                         5/17/10    4/20/10   1/8/10
        #     Tkr     Price      Perf       Perf            #      Tkr     Price      Perf      Perf
        1   CPX      $14.22      8%         (2%)           36 FTI         $60.00     (11%)     (1%)
        2   NR       $6.75       6%         50%            37 EXH         $25.51     (11%)      7%
        3   GIFI     $21.86      3%         1%             38 BHI         $44.80     (11%)     (5%)
        4   OYOG     $50.77      2%         21%            39 XOI        $1,000.51   (11%)     (10%)
        5   WEL      $2.96       0%         71%            40 WFT         $15.22     (12%)     (26%)
        6   KEG      $10.49      (0%)       1%             41 NOV         $38.78     (12%)     (18%)
        7   HOS      $20.60      (1%)      (16%)           42 TS          $37.11     (12%)     (19%)
        8   TESO     $12.21      (1%)      (14%)           43 CRR         $67.11     (12%)     (7%)
        9   SPN      $23.82      (1%)      (10%)           44 TTI         $11.78     (12%)     (7%)
        10 CLB      $140.27      (3%)       12%            45 BRNC        $4.23      (12%)     (30%)
        11 KBR       $22.71      (3%)       7%             46 ALY         $3.41      (13%)     (23%)
        12 TGE       $3.79       (4%)       (9%)           47 OII         $56.17     (13%)     (13%)
        13 SWSI      $14.30      (4%)      (20%)           48 DRQ         $57.17     (13%)     (2%)
        14 FTK       $1.68       (4%)       5%             49 OSX        $190.19     (14%)     (12%)
        15 TDW       $48.59      (4%)       (5%)           50 ACGY        $17.06     (14%)      2%
        16 PKD       $4.85       (4%)      (12%)           51 MDR         $23.70     (14%)     (9%)
        17 MTRX      $11.05      (5%)       (4%)           52 WG          $10.96     (15%)     (39%)
        18 NBR       $19.28      (5%)      (28%)           53 BAS         $8.39      (16%)     (16%)
        19 IO        $5.81       (6%)      (16%)           54 DWSN        $24.76     (17%)     (0%)
        20 NGS       $16.78      (6%)      (16%)           55 HAL         $27.55     (17%)     (19%)
        21 SPX      $1,136.94    (6%)       (1%)           56 NE          $34.16     (18%)     (24%)
        22 BRS       $35.46      (6%)      (11%)           57 ESV         $39.54     (19%)     (12%)
        23 XNG      $526.97      (6%)       (7%)           58 DVR         $6.16      (19%)     (23%)
        24 RES       $11.72      (6%)       (6%)           59 PDC         $6.02      (19%)     (38%)
        25 DRC       $32.47      (7%)       (3%)           60 CGV         $25.17     (20%)      0%
        26 SLB       $63.38      (7%)      (10%)           61 CAM         $36.72     (20%)     (18%)
        27 TTES      $25.75      (7%)      (10%)           62 PDE         $26.30     (20%)     (22%)
        28 SII       $42.50      (7%)       37%            63 HLX         $13.29     (21%)      0%
        29 EPX      $372.07      (8%)       (9%)           64 DO          $71.16     (21%)     (33%)
        30 OIS       $42.83      (9%)       0%             65 RDC         $25.15     (21%)     (0%)
        31 PTEN      $13.47      (9%)      (27%)           66 ATW         $29.04     (23%)     (27%)
        32 LUFK      $78.84     (10%)       6%             67 GOK         $6.24      (25%)     (40%)
        33 HP        $36.57     (10%)      (24%)           68 RIG         $64.99     (29%)     (30%)
        34 GLBL      $5.99      (10%)      (23%)           69 HERO        $3.09      (29%)     (46%)
        35 CKH       $75.70     (10%)       (3%)           70 HAWK        $13.06     (30%)     (45%)
Source: Bloomberg




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OFS Segment Discussion - Offshore Drillers
42% of GoM jackups off contract by the end of August
As shown in Exhibit 80, we estimate there are 6 jackups scheduled to be off contract by
May 28 per ODS-Petrodata (the day the DOI is expected to complete its safety review),
including Hercules 253, which recently completed contract work, as well as 2 other HERO
rigs (Hercules 201 and Hercules 257), RDC’s Rowan Alaska, ESV’s ENSCO 87, and
HAWK’s Seahawk 2504. Between now and the end of August, there are 32 rigs or 74% of
the contracted fleet set to roll off contract. This includes 9 HAWK jackups, 8 HERO
jackups, 4 ESV jackups, and 3 jackups each from RDC and DO.

Exhibit 80: GOM Jackup Rollover Schedule
Rig Name              Rig Manager                 Water Depth (ft)   Available date
Hercules 253          Hercules Offshore                  250 MS            Stacked
Rowan Alaska          Rowan                              350 ILS      19-May-2010
                                                                                       Jackups rolling
ENSCO 87              Ensco                               350 ILC      22-May-2010       off during
Hercules 257          Hercules Offshore                   250 MS       24-May-2010
                                                                                        moratorium
Hercules 201          Hercules Offshore                   200 MC       26-May-2010
Seahawk 2504          Seahawk Drilling                    250 MS       28-May-2010
Hercules 204          Hercules Offshore                   200 MC       30-May-2010
Spartan 202           Spartan Offshore Drilling           225 MS        1-Jun-2010
Hercules 205          Hercules Offshore                   200 MC        3-Jun-2010
Spartan 303           Spartan Offshore Drilling           262 MS        5-Jun-2010
Ocean Titan           Diamond Offshore                    350 ILC      11-Jun-2010
ENSCO 99              Ensco                               250 ILC      13-Jun-2010
Ocean Spartan         Diamond Offshore                    300 ILC      17-Jun-2010
ENSCO 90              Ensco                               250 ILC      20-Jun-2010
Seahawk 2600          Seahawk Drilling                    250 MC       22-Jun-2010
Spartan 151           Spartan Offshore Drilling           150 ILC      23-Jun-2010
Spartan 208           Spartan Offshore Drilling           250 MC       26-Jun-2010
Tuxpan                Perforadora Central                 375 ILC      27-Jun-2010
Ocean Columbia        Diamond Offshore                    250 ILC      29-Jun-2010
Seahawk 3000          Seahawk Drilling                    300 MC         1-Jul-2010
Cecil Provine         Rowan                               300 ILC        3-Jul-2010
Seahawk 2004          Seahawk Drilling                    200 MC        11-Jul-2010
Seahawk 2001          Seahawk Drilling                    200 MC        14-Jul-2010
Seahawk 2602          Seahawk Drilling                    250 MC        15-Jul-2010
Hercules 251          Hercules Offshore                   250 MS        19-Jul-2010
Hercules 200          Hercules Offshore                   200 MC        26-Jul-2010
ENSCO 86              Ensco                               250 ILC       1-Aug-2010
Rowan Gorilla II      Rowan                               450 ILC       1-Aug-2010
Seahawk 2601          Seahawk Drilling                    250 MC        9-Aug-2010
Seahawk 2500          Seahawk Drilling                    250 MS       10-Aug-2010
Seahawk 2007          Seahawk Drilling                    200 MC       19-Aug-2010
Hercules 202          Hercules Offshore                   200 MC       28-Aug-2010

Source: ODS-Petrodata, Credit Suisse estimates
Note: Some rigs may have pending options



Floater market much tighter
Not surprisingly, availability in the floater market in the U.S. GOM is much tighter (Exhibit
81). There are no rigs with availability before May 28, and only 4 floaters with availability
before the end of August. Specifically, DO’s Ocean Voyager completes its current term at
the end of June (the rig has a 1-month option thereafter), while DO’s Ocean Victory has an
open contract window in its current contract from mid-July until early-November. NE’s Paul
Romano semi is expected to complete its contract in late-July, while the Maersk Developer
semi has an available sublet window at the end of August.



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Exhibit 81: GOM Floater Rollover Schedule
Rig Name                 Rig type                               Rig Manager             Water Depth (ft)     Available date
Ocean Voyager            Semi                                   Diamond Offshore                 3,000         30-Jun-2010
Ocean Victory            Semi                                   Diamond Offshore                   5,500          15-Jul-2010
Noble Paul Romano        Semi                                   Noble                              6,000          22-Jul-2010
Maersk Developer         Semi                                   Maersk Drilling                   10,000         30-Aug-2010
Source: ODS-Petrodata, Credit Suisse estimates



HAWK and HERO lead in GoM exposure
As shown in Exhibit 82, HAWK and HERO have the greatest exposure to the GOM market,
as all 20 HAWK jackups are in the U.S. GOM and 22 (73%, of HERO’s 30 rig jackup fleet)
are in the domestic market. Among the other companies we cover, RDC has 9 jackups in
the U.S. GOM, ESV has 8, DO has 7, and PDE has 2.
Exhibit 83 shows the breakdown of domestic vs. international floaters on a company basis.
In comparing floaters, RIG has the most floaters in the U.S. GOM with 14 rigs, (19% of its
total floater fleet). DO and NE each have 6 floaters in the U.S. GOM, while ESV has 3.
SDRL and PDE each have 1 floater in the U.S. GOM.

Exhibit 82: Jackup Fleet Profile: U.S. GOM vs.                                              Exhibit 83: Floater Fleet Profile: U.S. GOM vs.
International                                                                               International
 70                                                                                          80


                                                                                             70
 60

                                                                                             60
 50
                                                                                             50

 40                                                                                                 58
                                                                                             40
       65
 30                                                                                          30
                            8
                    31
             43                                                                              20             27
 20
                                     15
                                                                                             10                                       9
 10                         22                20           6                                        14                13                            11         1
                                                                                                            6                         6         1          3              4
                    8                 9                            5                          0
                                                           7              6




                                                                                                                                                                          ATW
                                                                                                                                                    SDRL
                                                                                                                       PDE




                                                                                                                                      NE




                                                                                                                                                               ESV
                                                                                                    RIG




                                                                                                            DO




                                                                   2               3
  0
       RIG   NE   ESV      HERO      RDC     HAWK          DO     PDE   SDRL.OL   ATW

                                  US GOM   International                                                                     US GOM    International

Source: ODS-Petrodata, Credit Suisse estimates                                              Source: ODS-Petrodata, Credit Suisse estimates

On a percentage of revenue basis using 2009 data, we estimate 35% of HERO’s revenues
came from the GOM, followed by 34% for DO, 22% for NE, 20% for RDC (excluding
LeTourneau), 19% for RIG, and 14% for ESV. Companies with modest exposure to the
region include ATW and PDE, which derived only 3% of revenue from the GOM each, and
SDRL at 6% (excluding Well Site Services).

Exhibit 84: Offshore Driller GOM Revenue Exposure in 2009
Company Name                                                    % GOM Revenue
HERO                                                                              35%
DO                                                                                34%
NE                                                                                22%
RDC                                                                               20%
RIG                                                                               19%
ESV                                                                               14%
SDRL                                                                              6%
ATW                                                                               3%
PDE                                                                               3%
Average                                                                           17%
Source: Company data, Credit Suisse estimates



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Offshore Driller Earnings Sensitivity
Exhibit 85 shows the potential impact to earnings for the companies under our coverage
group that have rigs rolling off before the end of August. Under the following scenario, we
assume that rigs are idle between the respective contract end-dates and September 1. Not
surprisingly, the company that would incur the biggest impact on a percentage of earnings
basis would be HERO, where EPS could fall by $0.07 from ($0.49), or 14.3%. Our
estimates do not assume lower costs from idle time or stacking.

Exhibit 85: Offshore Driller Earnings Sensitivity
Company                           Ticker        2010E EPS         EPS impact       % EPS impact
Hercules Offshore                 HERO              ($0.49)            ($0.07)            -14.3%
Rowan Companies                    RDC                $2.40            ($0.06)             -2.5%
ENSCO                              ESV                $3.85            ($0.07)             -1.8%
Diamond Offshore                    DO                $8.07            ($0.12)             -1.5%
Noble Corp                          NE                $5.34            ($0.03)             -0.6%
Total                                               $19.17             ($0.29)             -1.5%
Source: Company data, Credit Suisse estimates

Diversified Services
We estimate GoM revenues should be 15-20% of NAM revenues in 2010
Although our coverage universe is intentionally vague about GoM revenues, we believe
the GoM should comprise approximately 15-20% of the big 4’s North America (NAM)
oilfield revenue in 2010. We believe the GoM used to constitute a higher percentage, but
we assume the strength of the last upturn in U.S. activity (and the partial recovery in 2010)
and the fall-off in GoM rig count—the working rig count has declined from an average of
100 rigs in 2004 to 63 currently (albeit with a modest increase in more lucrative deepwater
rigs) has taken its toll.
Earnings impact of a 50% reduction in GoM activity could be 20% for BHI and WFT;
nearly 15% for HAL; perhaps closer to 5% for SLB
Using this “revenue range” as a basis, we consider the earnings impact if the GoM suffers
from activity delays. The degree of activity pull back clearly depends on several factors,
including (1) deepwater versus shallow water restrictions; (2) the extent to which only new
wells are suspended versus sidetracks, workovers, etc; and, as we consider potential
delays specifically in 3Q10, (3) the impact of seasonal caution related to hurricane season.
For purposes of illustration, we consider the impact of a 50% reduction in revenue.
With this dramatic a reduction of revenue, we believe the decremental margins in
temporary reduction in the GoM would be very high (over 50%). Service infrastructure,
labor and even tools are likely to be left in place to allow for activity resumption, although it
is possible companies might try to reallocate some personnel into the U.S. onshore
markets if demand warrants.
Using 50% decremental margins, we calculate EPS reduction of 20% for BHI and WFT;
nearly 15% for HAL; perhaps closer to 5% for SLB
If/as delays broaden, so too would negative service impact
We have estimated that SLB, HAL and BHI (including BJS) have approximately 40% of
their revenues (and a higher proportion of their profits) sourced from offshore, while WFT
has an estimated 25%. See Exhibit 86. As we discussed in the summary, as it relates to
the potential for delays to spread, we have as yet only heard about potential delays in
approvals in the Chukchi and Beaufort Seas. However, we believe broader delays are a
risk.




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Exhibit 86: Estimated Offshore Revenue as % of Total, 2008 & 2011


               45%
               40%
               35%
               30%
               25%
               20%
               15%
               10%
                 5%
                 0%
                       SLB        SII      SLB-pf       BHI-pf   HAL   WFT

                                                2008E   2011E

Source: Company data, Credit Suisse estimates

Equipment
Modest 2010 impact; potentially weakens longer term OEM sales
The EPS impact for equipment/subsea manufacturers is far more modest than potential
impacts for offshore drillers or diversified services, given relatively small proportions of
GoM service-related (as opposed to backlog-driven) revenue. Yet a pause in equipment
orders, perhaps driven also by additional regulation related to the safety of production
equipment, could have longer-lasting implications for these companies. And a longer
lasting pause in activity in the GoM, and perhaps slower moving development programs,
could potentially lessen the demand for incremental drilling rigs.
CAM as relative trade strikes a balance
Thus in highlighting a relative opportunity for CAM we are weighing (1) recent share
underperformance, (2) what appears to be very limited logical culpability related to the
Macondo disaster and (3) some potential for retrofit/upgrade opportunities on BOPs (and
possible subsea equipment and deepwater valves as well) against potentially slowed
equipment orders. We conclude that CAM is attractive relative to other subsea equipment
manufacturers, although not relative to onshore oily exposed service names.




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US E&P: Anadarko Petroleum Corp. – Good Value
Despite Likely Costs (May 17th, 2010)
■   Macondo Oil Spill Bites, APC Looks Good Value. With a 22% ($8.2B) decline in
    APC’s market cap since the Macondo oil spill, we believe the potential costs of the
    incident (clean up costs and civil lawsuits) and the impact of tighter regulations for
    operating in the Gulf of Mexico look more than priced in. We reiterate our Outperform
    rating and with a $77 per share risked NAV (down from $84), we believe APC looks
    like a good value today even under a harsh scenario.

■   Reduce Target to Incorporate Potential Costs. Post Q1 results, we are raising our
    2010/2011/2012 EPS by 48%/11%/10% to $1.94/$2.93/$4.00. Our target price, which
    is based on parity or our PD-Plus NAV, falls to $77 (from $84) as we are pushing out
    the development calendar for some of APC’s Gulf of Mexico discoveries and including
    $963MM for potential clean up costs (net of insurance) and $2.0B as a provision for
    potential litigation costs. While difficult to assess, APC will likely need to keep a
    substantial amount of non-productive cash on the balance sheet for the foreseeable
    future. Despite these additional liabilities, there is still substantial upside to our target
    as APC is trading at a 27% discount to our PD-Plus NAV.

■   APC Can Weather This Storm. While it appears inevitable that lawsuits will be
    directed against the Macondo operating group (BP, APC and Mitsui) as there are
    contracts in place that indemnify service providers from above ground risk (civil and
    environmental claims), APC has moderate insurance coverage, significant current
    financial resources, a myriad of saleable assets and strong shareholder support (if
    equity issuances should be needed) to fund potential liabilities. Additionally, while the
    operating group is clearly liable for above ground costs, APC may be in the position to
    counter-sue BP should it be deemed that BP acted without diligence. Furthermore,
    progress is being made at controlling the oil spill as it was announced yesterday that
    BP has successfully inserted a tube from a drillship into the damaged riser, which is
    currently capturing an estimated 20% of the 5.0 MBbl/d leak rate.

■   Total Costs Will Be Large, APC’s Share Expected to be Manageable. The total
    cost of the Macondo oil spill is likely to be fairly large as clean up costs now look to be
    running $14MM per day (up from $6MM per day earlier). Depending on the amount of
    time it takes to clean up the oil, total clean up costs may amount to $3.0-6.0B with
    APC footing 25% of the bill ($750-1,500MM to APC given its 25% interest in the well),
    while additional costs related to civil damages paid to local businesses in the affected
    area will likely be in the courts for many years. We believe APC is in a strong financial
    position to fund these liabilities as it has $177.5MM of insurance coverage for clean up
    costs ($15MM deductible), a cash balance of $3.7B, an undrawn $1.3B revolver and is
    set to generate $160MM of free cash flow in 2010 on capital spending of $5.45B. For
    now, we are reducing our NAV by ~$3.0B, which represents the mid-point of our clean
    up cost estimate net of the insurance coverage post deductibles and additional costs
    related to civil lawsuits.

■   Estimate APC’s Gulf of Mexico Exposure Equates to $15 per Share. Indeed, the
    Gulf of Mexico is an important operating area for APC as it represents 12% of APC’s
    current reserve base (275 MMBoe) and is expected to act as a source of growth going
    forward on the back of numerous discoveries announced over the past several years.
    However, assuming an extreme scenario where all operations in the Gulf of Mexico
    are suspended indefinitely, we estimate only $15 per share of value would be removed
    from APC’s NAV (leaving $62 per share remaining or 10% above APC’s current share
    price), highlighting its diverse asset base. We are currently assigning $8 per share of
    value to APC’s Gulf of Mexico proved reserves (assuming $15 per Boe) and $7 per
    share for unproved potential in its Caesar/Tonga project and its Heidelberg,
    Shenandoah, Samurai, Lucius and Vito discoveries. In reality, this is a very unlikely


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     scenario in our view given the importance of the Gulf of Mexico to U.S. energy
     independence and as a funding source to the U.S. government through royalty
     payments. To be sure, we believe APC will be impacted by potentially longer
     permitting times, increased regulation, higher insurance costs and greater risk
     premiums for Gulf of Mexico operations, and as such, we have pushed out the
     expected start dates for APC’s discoveries.

Exhibit 87: APC Net Asset Value (NAV) Summary
 Anadarko Petroleum (APC)                                                                                         OUTPERFORM


 Net Asset Value Summary

                                                                                                       Shares Out. (MM)        496

 Proved Developed Reserves                        Liquids       Gas         Total                            Asset Value
 Oil & Gas Properties                            (MMbbls)       (Bcf)     (MMBoe)     % Gas       ($/Boe)      ($MM)     ($/Share)
 United States                                        499        5,884       1,480       66%        $16.20      $23,966     $48.30
 International (Algeria & Other International)        144             -        144        0%        $18.84       $2,713      $5.50

     Total Proved Developed Properties                643        5,884      1,624         60%       $16.43      $26,679     $53.80

 Other Assets                                                                                                  ($MM)      ($/Share)
 UPR Land Grant and Minerals                     10.3MM acres                 -                                    $515       $1.00
 WES Midstream MLP (58.2% APC LP + 2% GP)                                     -                                    $737       $1.50
 APC Midstream (7.0x EBITDA)                                                  -                                  $1,050       $2.10
 Deepwater GOM Blocks (618, 3.5MM gross acres)                                -                                      $0       $0.00
 West Africa Blocks (8.8MM acres)                                             -                                    $500       $1.00

     Total Other Assets                                                                                          $2,802      $5.60

 Liabilities                                                                                                   ($MM)     ($/Share)
 Long-Term Debt                                                                                                 $12,937     $26.08
 Cash & Equivalents                                                                                             ($3,692)    ($7.44)
 Provision for Macondo Oil Spill Related Costs                                                                   $2,963      $5.97

     Total Liabilities                                                                                          $12,208     $24.60

 Proven Developed Net Asset Value                                                                               $17,273     $35.00

 Undeveloped / Unproven Reserves                  Liquids       Gas         Total                            Asset Value
 Oil & Gas Properties                            (MMbbls)       (Bcf)     (MMBoe)     % Gas       ($/Boe)      ($MM)     ($/Share)

 U.S. - Greater Natural Buttes                         92        1,476        338         73%        $7.32       $2,477      $5.00
 U.S. - Wattenberg                                    107          740        230         54%        $9.88       $2,271      $4.60
 U.S. - Marcellus Shale (250k net acres)                -        1,340        223        100%       $14.14       $3,157      $6.40
 U.S. - Haynesville Shale (80k net acres)               -          226         38        100%        $5.82         $220      $0.40
 U.S. - Eagle Ford Shale (260k net acres)              41           83         55         25%       $11.77         $649      $1.30
 GOM - Caesar-Tonga Complex (APC 33.75%)               89            -         89          0%       $12.00       $1,063      $2.10
 GOM - Heidelberg (APC 44.25%)                         97            -         97          0%        $6.50         $629      $1.30
 GOM - Vito (APC 20%)                                  70            -         70          0%        $6.50         $455      $0.90
 GOM - Shenandoah (APC 30%)                            79            -         79          0%        $4.50         $354      $0.70
 GOM - Lucius (APC 50%)                                79          158        105         25%        $6.00         $630      $1.30
 GOM - Samurai (APC 33.33%)                            29            -         29          0%        $6.00         $175      $0.40
 Ghana - Jubilee (23.5% APC) - Mahogany WCTP
 (31% APC) / Hyedua Deepwater Tano (18% APC)          259            -        259          0%       $18.27       $4,723      $9.50
 Ghana - Odum (30.9% APC)                              18            -         18          0%       $15.00         $276      $0.60
 Ghana - Tweneboa (APC 18%)                            41          243         81         50%        $7.00         $567      $1.10
 Mozambique - Windjammer (APC 43%)                      -          645        108        100%        $1.50         $161      $0.30
 Brazil - Wahoo (APC 30%) / Itaipu (APC 33.3%)        253            -        253          0%        $7.00       $1,772      $3.60
 Algeria - El Merk (APC 22%)                          121            -        121          0%       $10.00       $1,210      $2.40



     Total Undeveloped / Unproven                   1,374        4,911      2,192         37%        $9.48      $20,789      $41.90

 Total 'PD Plus' Net Asset Value                    2,017       10,795      3,816         47%        $9.97     $38,062     $77.00

                                                                                     Last Price                              $56.46
                                                                                     Price - to - PD Plus NAV                  73%
                                                                                     Price - to - Proved Developed Only       161%

Source: Company data, Credit Suisse estimates




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Global Energy Insights: (May 12th, 2010)
■   In this report, we discuss the implications of the Macondo oil spill:

■   Commodity Implications: The Deepwater Horizon platform disaster poses specific
    risks to Gulf of Mexico shipping and raises the potential likelihood of tighter safety
    regulations and restrictions on offshore drilling access. The potential for shipping
    disruptions appears to be increasing; however, we don’t expect any near-term impact
    on commercial operations. With regard to the short-term regulatory response, we
    expect tighter safety regulations and at least a six-month moratorium on drilling. BP’s
    ability to get the spill under control will be a determining factor in the development of
    longer-term offshore drilling policies. In the end, we think that the Obama
    administration and Congress are likely to adopt a more restrictive stance on offshore
    resource access.

■   Equity Implications: We highlight CLH for its exposure to clean-up costs. Higher oil
    prices should support oil leveraged names – in particular, we favour onshore oil plays
    such as WLL and BEXP. While it’s too early to buy natural gas E&Ps, RRC and
    Petrohawk could be beneficiaries of any demand stimulation and could still prosper in
    the low nearterm gas price environment. Until the causes and effects are known,
    trading the group of spill-related companies carries high risk. CAM, WFT and HAL may
    eventually benefit from indemnities likely worded into their contracts. The $29bn
    knocked off BP, APC and Mitsui (relative to market) leaves potential headroom for
    claims, leaving BP and APC discounted versus core value, but with much uncertainty.
Commodities
The “Macondo” Spill-over Effects
The Deepwater Horizon platform disaster poses specific risks to Gulf of Mexico shipping
and raises the potential likelihood of tighter safety regulations and restrictions on offshore
drilling access.

■   With oil from the spill now reaching land and spreading within the Gulf, potential
    disruption to shipping within the heart of the U.S. refining industry is increasing.
    However, we don’t foresee any near-term impact on commercial operations. And if
    there is any, the U.S. Strategic Petroleum Reserve system is available and is capable
    of meeting almost any contingency.

■   What will likely be the short-term regulatory response to the ongoing safety
    inspections? At a minimum, we expect tighter safety regulations and a six-month
    moratorium on drilling. On a go-forward basis, we believe “self-regulation” based on
    best practices is likely to be replaced by a series of set requirements administered by
    MMS or possibly a newly created safety board.

■   What are the longer-term policy scenarios that are likely to unfold as a result of this
    environmental disaster? BP’s ability to get the spill under control will be a determining
    factor in the development of longer-term offshore drilling policies, in our view.
    However, we also think that the U.S. is likely to adopt its own unique form of resource
    “nationalism” in response to this environmental disaster.
Crossroads for US Deepwater E&P

■   With oil flows from the Macondo well still gushing and the oil slick in the Gulf of Mexico
    growing, an early assessment of the political and regulatory implications of perhaps
    the largest environmental disaster in the history of offshore drilling is challenging at
    best.

■   So while we acknowledge that this event is still unfolding, we believe that two trends
    are likely to emerge: first, in the minds and hearts of many Americans, the oil and gas



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    industry looks likely to nudge out the banking sector as “public enemy number one.”
    And second, access to deepwater resources is almost certainly going to confront
    significant obstacles on a go-forward basis. Yet, how any new regulatory trends might
    develop will remain difficult to depict as long as remedial action to cap the prolific
    Macondo well remains elusive.

■   In this section of our report we will examine the operational risks that a disruption in
    shipping might pose, the short-term regulatory response to the safety inspections
    currently underway, as well as the longer-term policy scenarios that will likely unfold as
    a result of this environmental disaster.
Navigating murky waters

■   With oil from the spill now reaching land and spreading within the Gulf, potential
    disruption to shipping within the heart of the US refining industry is increasing. The
    Gulf of Mexico represents a critical gateway for oil imports that feed the largest
    concentration of refineries in the United States (see Exhibit 88), with the top 11
    refineries within the region having a combined throughput capacity of 3.85-m b/d and
    the remaining a capacity of 2.64-m b/d. And although so far there has been little more
    than a slowdown of deliveries from abroad, we believe that preventative measures to
    contain the massive oil slick will inevitably disrupt waterborne traffic within the region.

Exhibit 88: Nearest refineries to the spill




Source: Company data, Credit Suisse estimates



■   While virtually all of the Gulf’s 1.6-m b/d of oil production flows to land via pipeline and
    is therefore not subject to disruption, the PADD III region of the Gulf is where the
    preponderance of US crude oil and product imports occur and from which some
    intercoastal product distribution takes place.1 As shown inExhibit 89, PADD III imports
    have been averaging about 5.8-m b/d over the past few weeks, well above the 5.2-m
    b/d of a year ago but also far short of the occasional 7-m b/d reached in the past.
    Given the relative scale of imports versus regional production, shipping disruptions in
    the Gulf present a much more serious supply risk than the potential shut-in of Gulf
    production.




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Exhibit 89: PADD III crude oil imports, 2005-present (in m b/d)




Source: Company data, Credit Suisse estimates



■   There are two receiving terminals that we believe are most vulnerable to disruptions.
    The first and largest receiving terminal is the Louisiana Offshore Oil Port (LOOP)
    (https://www.loopllc.com). Located 18 miles south of Grand Isle Louisiana and sitting
    in 110 feet of water, it is the only port in the US that can offload Ultra-Large Crude
    Carriers (ULCCs) and Very-Large Crude Carriers (VLCCS). It can also offload smaller
    tankers.

■   LOOP is connected to over 50% of the U.S. refinery capacity and it handles up to 1.5-
    mb/d of crude from foreign and domestic sources (including via pipeline from offshore
    production). LOOP’s storage facilities are vast and include eight underground caverns
    leached out of salt domes that can store up to 50-m bbls of oil, and six above-ground
    tanks with total capacity of 3.6-m bbls. Storage can and does segregate different
    crude oil streams, including one large cavern that is dedicated to MARS production
    from the deepwater Gulf of Mexico.

■   LOOP’s strategic location involves its connection to four pipelines that connect its
    storage to refineries in Louisiana and along the Gulf Coast. In addition, LOOP
    operates the LOCAP pipeline connecting LOOP to Capline 53-miles away, with
    capacity to move crude oil into the U.S. Mid-Continent and refineries in PADD II.

■   What’s important about LOOP is its huge storage capacity that enables it to service
    refineries regardless of weather conditions in the Gulf. As can be seen below, the
    same pipelines can be served by tapping into the U.S. Strategic Petroleum Reserve
    (SPR).

■   The ports and inland cities receiving crude oil, partly through LOOP, partly through
    smaller ports, include, from West to East, in Texas: Corpus Christi (500-k b/d),
    Freeport (275-kb/d), Texas City (600-k b/d), Houston (1-m b/d); Beaumont (200-k b/d),
    and Port Arthur (630-k b/d); in Louisiana: Lake Charles (385-k b/d), Morgan City (1.6-
    m b/d), Baton Rouge (175-k b/d), New Orleans (335-k b/d), and Grammery/St. Rose
    (210-k b/d); and in Mississippi: Pascagoula (170-k b/d) and Mobile (80-k b/d).

■   In addition, the Southwest Pass, which is the main deepwater traffic route connecting
    the Mississippi River and the Gulf, might also be vulnerable to a slowdown or cut-off of
    waterborne deliveries, although to date it remains clear of oil from the spill. However, it
    has been suggested that vessels approach the Pass from the west to avoid the spill
    altogether. Ship-to-ship transfer of crude off Pascagoula, Mississippi has been halted



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    by one lightering company while others are shifting easily towards the Southwest
    Pass. The U.S. Coast Guard has not confirmed if the lightering zone had been shut in.
SPR acts as a temporary “release” valve

■   While shipments to the U.S. Gulf Ports have been inconvenienced by the spill,
    resulting in delayed deliveries and somewhat higher costs associated with scrubbing
    and cleaning operations to limit contamination into the port areas, we believe it is
    exceedingly unlikely that there will be any major impact on commercial operations.
    And if there is, the U.S. Strategic Petroleum Reserve system is available and is
    actually capable of meeting almost any contingency.

■   No volumes have been withdrawn from the SPR system since October 2008, when
    0.60-m bbls were temporarily loaned to refiners whose feedstock had been interrupted
    by Hurricanes Gustav and Ike. Since that time, 24.85-m bbls have been added to the
    reserve, with current inventory of the SPR at its 727-m bbls capacity. The four SPR
    distribution centers – Bryan Mound, Big Hill, West Hackberry, and Bayou Choctaw –
    can discharge oil directly into the Gulf Coast pipeline system and from there into the
    northern parts of the Mid-Continent and into the Southeast. And they can almost
    certainly do so at the maximum draw-down rate of 4.4-m b/d for 90 days. If the reserve
    draw-down were to occur, the SPR has the physical capability of drawing 1-m b/d for
    nearly a year and a half.

■   In terms of timing, it normally takes 13-days to effectuate a release and sale (or
    exchange) with a refiner following a presidential determination of emergency
    conditions. But together with the storage in place in the Gulf, including at LOOP, we
    believe there is little doubt that the SPR could be tapped to deal with any commercial
    disruption due to the spill.
In the meantime, what can the regulators do?

■   Beyond the problem of short-term supply disruption, due to a literal clogging of
    shipping channels, the most immediate question that begs asking is exactly what can
    regulators do in the very near-term to respond to this environmental disaster.
    Specifically, given the policies that are already in place, what will likely be the
    regulatory response to ongoing safety inspections?

■   The three plausible scenarios that we envision all entail the adoption of tougher safety
    procedures and to differing degrees higher costs and delays in offshore drilling. For
    us, the key to each scenario is whether the current inspections uncover material
    violations of the existing regulations:
    1)   A finding of “no violations” could result in tightened safety measures. It is
         very difficult to foresee the Interior Department making no recommendations for
         improved safety even if the current inspections find no material violations of
         existing regulations. Nonetheless, it may be some time before recommended
         measures are fully developed, made available for public hearing, and further
         reviewed. It would thus be likely that the current moratorium on new drilling would
         be retained for a minimum of six months, while the new measures are enacted,
         providing a setback to further development of the Gulf of Mexico deepwaters.
         Among the measures that could be expected are regulations requiring less
         selfenforcement and more rigorous active inspection by the Mineral Management
         Service (MMS). This would undoubtedly require more personnel and a
         mechanism would be needed to make sure that these added costs are paid by the
         industry, either through fees or taxes.
         Limitations on drilling liability are also likely to be lifted significantly in this
         scenario. Current law, passed in the aftermath of the Exxon Valdez spill in 1989,
         makes it clear that the drilling operator, in this case BP, is responsible for the
         costs of cleaning up the spill, but is limited in the case of other damages to $75


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        million in liabilities. While BP officials maintain that the company will cover all
        costs associated with the clean-up of the spill, the uncertainty around the payment
        for resulting damage claims has spurred a number of Democratic senators to
        propose legislation that would raise the limits of liability to $10 billion. While it
        seems doubtful that any new liability cap would be applied retroactively for this
        event, we believe there is bound to be an increase, not only in non-cleanup
        liabilities, but also in fees that are imposed on the industry to feed the Oil Spill
        Liability Trust Fund (which can provide up to $1 billion in payments for every
        incident).
        Whatever the outcome, it is hard to imagine that the industry will be exempt from
        additional taxes, while what is in question is whether the tax would be imposed on
        all production and imported crude oil or only on offshore production.
        Finally, a minimum change under tightened measures would include a likely
        significant increase in redundancy in back-up systems. This is particularly the
        case with respect to BOPs – blow-out preventers that are needed to cut oil flows
        in emergency conditions.5 The MMS had warned the industry that increased
        safety measures were necessary but deferred imposing specific requirements
        because the industry committed itself to undertaking best practices in this area.
        However, on a go-forward basis, this “self-regulation” based on best practices will
        likely be replaced by a series of set requirements administered by MMS or related
        safety board.
        In short, no matter what the result of the safety review, delays in drilling and
        higher costs will likely be a “best-case” outcome. We estimate that these
        incremental expenditures could increase drilling costs in the deepwater by as
        much as 10%. However, we would be quick to point out that such costs are likely
        to be countered over time by the general trend of drilling cost reductions. This is
        particularly the case with respect to day rates for drilling using specialized and
        expensive deep-water capable rigs.
        Costs increased significantly for these day rates during the 2003-07 period, when
        they rose by 350%-400%. That is the history of the offshore services sector – as
        soon as there is some competition with excess capacity in the deepwater offshore
        fleet, day rates are likely to come down. This has already been the case in
        deepwater semisubmersible drilling as shown below in Exhibit 90. Deepwater day
        rates peaked at $572,500 per day in December 2008 but have steadily decreased
        as more rigs have become available.




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                                                                                                 14 June 2010



Exhibit 90: GoM semisubmersible day-rate averages ($ thousands)




Source: Company data, Credit Suisse estimates



    2)   A finding of safety lapses? Expect more extensive delays and
         redundancies. A finding of significant safety lapses on a handful of drilling rigs or
         production platforms would be likely to result in a more urgent and deeper set of
         changes than those outlined in the first scenario. Under this scenario, the public
         and congressional pressures would certainly be higher than they already have
         been, and political distrust of the offshore industry would almost certainly rise.
         In this case, we would expect three additional impacts:
         First, we believe that congressional pressure would go beyond the industry itself
         to the regulators as well. It would appear that the existence of safety violations
         would turn congressional attention to the system of regulation and that the Obama
         administration, as has been the case with financial reform, would take an active
         role in regulatory reform of the offshore.
         In fact, the administration’s recent proposal, to split the safety enforcement from
         administrative duties of the issuance of leases and collection of royalties,
         seemingly already reflects the shift in attitude since the disaster occurred.6 Any
         evidence of material safety lapses within the industry would simply serve to
         further solidify greater regulatory oversight, which in turn would likely postpone
         new offshore drilling until new safety and oversight procedures could be put in
         place. This could effectively maintain a moratorium on drilling for another year to
         two years.
         It has generally been agreed that given the industry’s near inevitable move to cut
         corners, it is prudent from a regulatory perspective to separate the licensing and
         other licensing-related procedures from the monitoring of safety and
         environmental integrity. The establishment of a separate safety and
         environmental monitoring agency would be a politically important way to assure
         that relevant redundancies are required and in place, in our view.
         Second, it is likely that pressures would build to curtail exploratory drilling,
         perhaps for a three-month period of time to assure the public that the safety
         violations found in a few operations were not more frequent occurrences than was
         determined with the initial 30-day inspection effort. It would be unlikely that the
         government would suspend production operations under these circumstances.




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         Third, we believe an inevitable result of such a finding of safety lapses would also
         result in significant amendments to the five-year plan issued by the Department of
         Interior, with a further demarcation reducing the amount of acreage made
         available to the industry. Already under court pressure and political pressure to
         replace the prior five-year lease program, which had been delayed in the first few
         weeks after President Obama’s inauguration in early 2009, the U.S.
         administration unveiled a new five-year plan at the end of March 2010. This
         ambitious plan, reversing much of the policy antagonism toward offshore drilling,
         aimed to lift a moratorium on offshore drilling along the East Coast, including
         Florida and in the Gulf of Mexico, as well as Alaska. But already the Department
         of Interior announced an indefinite delay of oil and gas exploration off Virginia’s
         coast, as well as delays in hearings.
         It would appear that the discovery of safety violations would lead either to a crawl
         back on the full reopening of drilling off the East Coast or to significant restrictions
         on new drilling near the recreational areas of the shoreline. In short, the discovery
         of safety violations would almost inevitably lead to significant delays in the current
         program to find and develop offshore hydrocarbon resources, reducing the
         contributions that could be made from new discoveries and from additions and
         extensions to the current producing field. At this juncture it would appear as
         though such restrictive measures would be feasible only in the case of discoveries
         of extensive infringements and abuses of the safety regulations associated with
         the offshore.
    3)   Drastic curtailment of offshore activities. It is not difficult to conclude that even
         more restrictive and drastic measures could unfold under certain circumstances.
         For example, if there were not only a significant number of safety violations that
         were uncovered under the current inspection program, but if, in addition, flows for
         the spill could not be brought under control for three months and, in the interim, if
         significant environmental damage was inflicted on fisheries and vacation areas, a
         growing consensus could emerge for even more stringent restrictions on drilling
         and production.
         Further, in all likelihood. there would be significant spill-over impacts abroad.
         Representatives from Norway’s Petroleum Directorate and Brazil’s National
         Petroleum Agency (ANP) have publicly stated that the local authorities are closely
         watching what new measures are being adopted in the U.S. In Canada, where
         public opinion is as split as it is in the U.S. on the wisdom of offshore exploitation,
         officials from both the Northwest Territories and Nova Scotia have said that they
         question the safety of offshore operations in the northern Beaufort Sea and on
         Canada’s Outer Continental Shelf. Of particular concern is the lack of equipment
         available for drilling relief wells in case of a blow-out.
         President Obama, potentially seizing an opportunity for public support in the face
         of the environmental damages inflicted by the untamed oil flows, could reverse his
         recent decision to open up more acreage, including Atlantic basin acreage, to new
         exploration, could impose new safety procedures on current operations, delay or
         suspend currently planned drilling and redouble his efforts on renewables and on
         measures to improve the efficiency of oil and gas use. Under this drastic scenario,
         he might propose new taxes, including higher royalties, on offshore production,
         build support for his proposals to rescind tax exemptions for drilling and
         production, and to use the revenue for his broader energy agenda.
Where do we go from here? The U.S. is likely to adopt a unique form of resource
  “nationalism”

■   So where do we go from here? Specifically, what are the longer-term policy scenarios
    that will likely unfold as a result of this environmental disaster?




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■   Although attempts to halt the Macondo well oil spill have so far been unsuccessful, the
    level of public unrest has necessitated an immediate regulatory response to the
    disaster unfolding in the Gulf. And while Congress has been quick to schedule the
    initial slate of hearings on why the explosion occurred and how the oil spill might be
    halted, we think that there will be a significant lapse of time before new policies are
    actually adopted for offshore drilling. However, that is not to say that we think this
    problem will be swept under the carpet. On the contrary, in the end we think that the
    U.S. will likely adopt its own unique form of resource ”nationalism” in response to this
    environmental disaster.

■   The most important issue at stake for the industry is access to acreage. It is in this
    area that we think Congress and the administration will act most decisively. We expect
    that the administration is likely to revamp its five-year plan and that Congress will not
    seek expansive changes. Specifically, we expect a relatively restrictive stance on
    drilling in the Atlantic and Pacific, with a more cautious approach to the Gulf and
    Alaska. However, the level of governmental control and restrictions of these offshore
    resources is likely to be based largely on how quickly the current environmental
    disaster can be remedied.

■   Given that the industry is at the early stage of a pendulum shift back to a more
    restrictive environment, we will review some of the key events that have already
    unfolded or are about to unfold that will likely set the tone for the new policies.
What’s happened so far:

■   Very soon after the April 20th explosion on the Deepwater Horizon rig, the president
    convened a meeting in the White House (April 22) to discuss an Emergency
    Response. On April 25, Interior Secretary Ken Salazar instructed the MMS to
    complete the physical inspection of all deepwater rigs within two weeks (completed on
    May 9th), to be followed by physical inspection of all deepwater platforms.

■   On April 29, President Obama ordered Secretary Salazar to complete his report on
    safety measures for offshore drilling within 30 days – i.e., by May 29. And later, on
    May 7, Secretary Salazar implemented a moratorium on new drilling permits (except
    for the relief wells required to end the spill), pending the safety investigation.

■   In addition to placing a moratorium on new applications for OCS drilling permits, the
    MMS told Shell that it would make no final decision on further exploration in the
    Chukchi Sea and Beaufort Sea off Alaska. Further, the DOI has also put off public
    hearings on potential energy development in offshore Virginia, which had been
    included in the department’s new five-year leasing program.
Looking ahead this week:

■   Two Senate committee hearings took place earlier in the week (of May 10) on the oil
    spill. The Senate Energy and Natural Resources Committee, which had originally been
    scheduled to review the Interior Department’s new five-year offshore program, instead
    met on May 11 to listen to testimony from representatives from BP America,
    Transocean and Halliburton on the Macondo incident. This hearing was promptly
    followed by a separate meeting with the U.S. Senate Environment Committee, which
    conducted open hearings on the impacts of the spill on the environment of the coastal
    states, with senators and governmental representatives from the coastal states
    confronting the companies responsible for the spill.

■   On May 12, hearings will commence in the House Energy Subcommittee focusing on
    the spill.
These initial congressional hearings are of interest for several reasons. Perhaps most
importantly, they highlight that, unlike the congressional debates on financial reform, there
is no significant party divide on the multiple issues associated with energy production in


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the country. Quite to the contrary, energy production and use exposes ways in which
regional and local issues dominate party politics (these unique divisions are at the heart of
why we expect that policy formation will not happen overnight).7 We believe the regional
political imperatives surrounding energy in the United States point to the inevitability of
congressional support for significantly more intrusive safety regulations governing offshore
drilling. But they also point to long delays in getting the trade-offs just right between
access to the offshore and the public good. The situation that is currently unfolding in the
Gulf will play a very important role in shaping the longer-term policies that will affect
offshore drilling. Specifically, whether BP succeeds soon and the actual amount of
damages that result from this disaster are likely to determine how offshore drilling policies
will develop. A long and difficult containment would push matters politically over the longer
run toward the third scenario (“worse case”) outlined earlier. Good luck could make for a
patchwork solution. But more likely is a new higher-cost operation in the deep offshore
waters, restricted largely to the Gulf of Mexico, with a damping impact on deepwater
prospects globally.
Equities
Macondo Spill: Impact Analysis

■   After the Macondo spill, we look at 1) a framework for analysing the impact on global
    oil markets, 2) the liability impact for companies involved, 3) the potential impact on
    alternative energy policy and 4) the read across to other equity sectors.

■   Oil market Impacts: In the short term, the main potential impact on oil markets will
    likely be through disruptions to shipping lanes and existing production. In the longer
    term, offshore costs should have an upward bias, as will project lead times. The
    deepwater GoM represents around 15% of total non-OPEC growth projects to 2017,
    but only 5% of growth up to 2013. The surge in offshore projects is back-end loaded,
    and this may give the industry more time to adjust. However, the timeline on this
    adjustment could take several years if, for example, regulations require all Blow Out
    Preventers (BOP’s) to be replaced with higher specification units or to allow time for
    R&D into subsea blowout response. Using a 3 yr delay to Gulf of Mexico drilling could
    drive global spare capacity as low as 2.4MBD in 2015, consistent with an oil price
    spike and good for light-heavy differentials. While offshore costs will have an upward
    bias, our US$80/bbl LT oil price is set to accommodate the higher cost Canadian Oil
    Sands and as such leaves a cost cushion to accommodate regulatory inflation in the
    deepwater. On the whole, we believe peaking global IP momentum and falling but high
    spare capacity will act as a cap on near term oil prices. Fears around European
    contagion (less likely after the weekend) have reminded the market that downside
    risks also exist. We remain comfortable with a $65-90/bbl range and $80/bbl mid-point,
    watching Macondo policy impacts closely.

■   Cross-sectoral impacts: Coming on the heels of President Obama’s plans to open
    new tracts on the east coast for drilling, the incident is likely to bring talk of a complete
    review of US energy policy. However, comprehensive legislation still feels someway
    off. Smaller actions such as the extension of ITC’s in Wind may get through. 15%
    ethanol blends may also be closer but need a solution for consumer auto liabilities.

■   Stock Picks: We like CLH for its exposure to clean up costs. Higher oil prices should
    support oil levered names – in particular we favour onshore oil plays such as WLL and
    BEXP. While it’s too early to buy natural gas E&P’s, RRC and Petrohawk would be
    beneficiaries of any demand stimulation, and can still prosper in the low near term gas
    price environment. Until the causes and effects are known, trading the group of spill
    related companies carries high risk. CAM, WFT and HAL may eventually benefit from
    indemnities likely worded into their contracts. The $29bn knocked off BP, APC and
    Mitsui (relative to market) leaves potential headroom for claims, leaving BP and APC
    discounted versus core value, but with much uncertainty.



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FOCUS CHARTS AND TABLES

Figure 91: Growth projects vs. growth from GoM in base                              Figure 92: US GoM’s share of global supply growth
case
 (MMBD)                                                                              (MMBD)                                                                 (%)
 12                                                                                  12                                                                      15

 10                                                                                  10                                                                      13

  8                                                                                   8                                                                      11

  6                                                                                   6                                                                      9

  4                                                                                   4                                                                      7

  2                                                                                   2                                                                      5

   -                                                                                   -                                                                     3
       2010E    2011E   2012E    2013E   2014E   2015E     2016E   2017E                   2010E    2011E 2012E    2013E 2014E 2015E 2016E 2017E

          Cumulative growth from GoM      Cumulative growth from new projects                           Cumulative growth from GoM (LHS)
                                                                                                        Share of GoM growth to total growth (RHS)


Source: IEA, industry data, Credit Suisse estimates                                 Source: Company data, Credit Suisse estimates

Figure 93: Scenario Table – Demand, supply and spare capacity
                                                                      2010E     2011E         2012E     2013E       2014E        2015E       2016E      2017E
Base global demand assumption                                          86.7      88.7          90.2      91.5        92.8         94.3        95.8       97.3
GoM deepwater supply
Base assumption                                                        1.6          1.7       1.7        1.7         1.8          2.2          2.7       3.0
Potential Supply                                                       1.6          1.7       1.7        1.7         1.8          2.3          2.9       3.4
Macondo fallout                                                        1.6          1.6       1.7        1.7         1.7          1.8          2.0       2.4
GoM shallow water                                                      0.26         0.25      0.24       0.22        0.21         0.20         0.19      0.18

Non-OPEC Supply – Base                                                 52.1         52.2      51.6       51.3        51.6         52.3         53.2      54.3
Non-OPEC Supply – Potential                                            52.1         52.2      51.7       51.5        52.1         53.2         54.8      56.6
Non-OPEC Supply – Macondo fallout*                                     52.1         52.1      51.6       51.3        51.5         51.9         52.5      53.7
Spare capacity – Base                                                  5.9          5.1       3.7        3.0         2.7          3.2          3.6       3.6
Spare capacity – Potential                                             5.9          5.3       4.0        3.7         4.1          5.0          6.5       7.5
Spare capacity – adjusted for Macondo                                  5.9          5.0       3.8        3.0         2.6          2.8          2.9       3.0
*Note: Macondo Fallout assumes a 1-year delay. Spare capacity could fall as low as 2.4MBD with a 3yr
delay. Source: Company data, Credit Suisse estimates

Figure 94: A Framework for Indicative Revenues and Potential Liabilities
Latest Revenue Figures                                    Year 1           Year 2          Year 3          Year 4
Total Tourism & Fisheries Revenues                       30,966            30,966          30,966          30,966
Assumed Earnings Margin impact                             50%              50%             50%             50%
Economic Losses                                           Year 1           Year 2          Year 3          Year 4
Fishing                                                   100%              50%             25%             25%
Tourism                                                    15%             10.0%            5.0%            5.0%
Clean-up (High End)                                      $8,249
Lost Earnings                                            4645.5            2641.5          1320.75        1320.75
Total Out of Pocket                                      $12,894           $2,642          $1,321         $1,321
Discount rate                                               8%
Present Value                                            $16,223

BP share, $MM                                            $10,545
Per share impact, $                                        3.4
APC Share, $MM                                           $4,056
Per Share impact, $                                        8.2
Source: Company data, Credit Suisse estimates




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Macondo – Oil Market Impacts
The fall-out from the unfortunate incident at the Macondo well in the deepwater Gulf of
Mexico region continues to reverberate in the equity markets. Stocks at the epicentre of
this incident – BP, Anadarko, Transocean – have all lost $60bn of value, $41bn relative to
the market. Our analyst teams have looked at the potential fall-out of the incident on the
valuations of the companies involved in their published research and later herein.
In this note, we try and quantify the potential impact of the incident on the demand-supply
balance for oil. In doing so, we look at the potential scenarios that might play out, and the
impact that it might have on the future production pipeline.
A lot of the impact analysis, as we move away from the immediate situation, will revolve
around costs – the extra cost of compliance, design, insurance, provisioning for possible
events etc. These will likely add time to schedules and dollars to the breakeven costs
lowering potential future returns.
The political fall-out of the incident is yet to fully unfold. On 11 May 2010, the Interior
Secretary, Ken Salazar, is set to appear before the Senate Energy and Natural Resources
Committee. We would assume that over time, like Toyota and Goldman Sachs, the players
in the centre of this incident will also appear before the representatives of the People, and
answer tough questions.
So far, the immediate response of the US Government has been to step back from the
recently announced proposal by President Obama, where 130mn acres of offshore
acreage off the East Coast – South of the New Jersey Coast line – would be opened for
new drilling. California too appears to have, at least for the time being, dropped plans to
allow drilling offshore.
Implications for the oil market
In our recently published research report “Oil Prices: The Next Cycle Could Be Different”
dated 14 April 2010, we outlined our demand-supply assumptions up to 2017. Global oil
spare capacity is high currently (at 6MBD) but will most likely fall towards 3-4mbd between
2012 and 2015 in our risked base case. It could be as high as 7-8mbd in a more optimistic
scenario in which demand starts to slow under the weight of gas substitution/energy
efficiency and all the supply that we have modelled comes through without risks. While the
Macondo oil spill was not explicitly modelled, part of our $80/bbl forecast was already
predicated on supply delay.

Figure 95: Global oil spare capacity vs oil price                                                                                     Figure 96: Global oil spare capacity – base and potential
  (MMBD)                                                                                                                                (MMBD)
                                                                                                                                          8.0
    7.0                                                                                                                       110.0
                                                                                                                                          7.0
    6.0                                                                                                                       100.0
                                                                                                                              90.0        6.0
    5.0
                                                                                                                              80.0        5.0
    4.0
                                                                                                                              70.0        4.0
    3.0
                                                                                                                              60.0        3.0
    2.0                                                                                                                       50.0        2.0
    1.0                                                                                                                       40.0        1.0

     -                                                                                                                        30.0         -
                                                      2009
           2003
                  2004
                         2005
                                 2006
                                        2007
                                               2008




                                                                                                                                                 2003
                                                                                                                                                        2004
                                                                                                                                                               2005
                                                                                                                                                                      2006
                                                                                                                                                                             2007
                                                                                                                                                                                    2008
                                                                                                                                                                                           2009
                                                                     2011E
                                                                             2012E


                                                                                              2014E
                                                                                                      2015E
                                                                                                              2016E




                                                                                                                                                                                                          2011E
                                                                                                                                                                                                                  2012E
                                                                                                                                                                                                                          2013E




                                                                                                                                                                                                                                                  2016E
                                                                                                                                                                                                                                                          2017E
                                                             2010E



                                                                                     2013E




                                                                                                                      2017E




                                                                                                                                                                                                  2010E




                                                                                                                                                                                                                                  2014E
                                                                                                                                                                                                                                          2015E




                                Spare Cap CS Base Case                                       WTI                                                           Spare cap - Potential                          Spare Cap CS Base Case

Source: IEA, industry data, Credit Suisse estimates                                                                                   Source: IEA, industry data, Credit Suisse estimates




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                                                                                                                                                          14 June 2010


In our base case, we expect net non-OPEC supply to grow by 2.2mbd between 2010 and
2017. This is underpinned by nearly 10.5mbd of new projects growth and ramp up (netted
out by declines on existing production). Within this, the deepwater GoM region accounts
for 1.5mbd of risked new supply, or about 15% of total growth.


Figure 97: Non-OPEC supply – potential supply and                                      Figure 98: The risk factors built into our base case
risked for specific events

   58.0                                                                                   2.5


   56.0                                                                                   2.0
                                                                                                                                                      Greater Declines
   54.0
                                                                                          1.5
                                                                                                         New Exploration Ramp Up dela ys
   52.0
                                                                                          1.0                                   CS
                                                                                                               Deepwater GOM delays Risked Supply - What is reduced from

   50.0
                                                                                                                                                      Oil Sands Delays
                                                                                          0.5
   48.0
                                                                                                                                                         Russia Delay
          2003     2005     2007         2009    2011E    2013E    2015E     2017E
                                                                                          0.0
                           Potentia l                               Base                   2010E       2011E   2012E    2013E     2014E    2015E     2016E    2017E


Source: IEA, industry data, Credit Suisse estimates                                    Source: IEA, industry data, Credit Suisse estimates



Looking more globally, we note that offshore production in West Africa, US GoM, Brazil,
Ghana and some other regions is expected to grow from the current 6mbd to about 11mbd
in our base case. If indeed the Macondo incident raises concerns over offshore production
in general, then a larger swathe of output could be subject to delays. Outright bans on new
drilling are seen as unlikely but if enacted would present a greater risk.


Figure 99: Growth projects vs growth from GoM in base                                  Figure 100: Global offshore growth projects
case
 (MMBD)
 12                                                                                       4000

                                                                                          3500
 10
                                                                                          3000
  8
                                                                                          2500
  6                                                                                       2000

  4                                                                                       1500

                                                                                          1000
  2
                                                                                           500
   -
                                                                                                0
          2010E   2011E   2012E         2013E   2014E    2015E    2016E    2017E
                                                                                                2009   2010E 2011E 2012E 2013E 2014E 2015E 2016E 2017E

            Cumulative growth from GoM           Cumulative growth from new projects
                                                                                                          US GoMexico           Brazil       Ghana



Source: IEA, industry data, Credit Suisse estimates                                    Source: IEA, industry data, Credit Suisse estimates




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                                                                                                    14 June 2010


Potentially tighter markets
If we start with the assumption that our GoM production numbers will be delayed by 12
months across the board, i.e. the growth projects that we currently model to come on-
stream for 2013 are delayed into 2014 and so on, then our base case spare capacity
numbers will be lower.
In our base case, our model suggests a spare capacity of 2.7mbd for 2014 – a similar level
to the periods when oil prices spiked. In the base case, spare capacity goes back above
3MBD in the 2015-2017 period.

Figure 101: Scenario Table – Demand, supply and spare capacity
                                           2010E 2011E 2012E 2013E 2014E 2015E 2016E 2017E
Base global demand assumption               86.7   88.7   90.2   91.5   92.8   94.3   95.8   97.3


GoM deepwater supply
Base assumption                             1.6    1.7    1.7    1.7    1.8    2.2    2.7    3.0
Potential Supply                            1.6    1.7    1.7    1.7    1.8    2.3    2.9    3.4
Macondo fallout                             1.6    1.6    1.7    1.7    1.7    1.8    2.0    2.4


GoM shallow water                           0.26   0.25   0.24   0.22   0.21   0.20   0.19   0.18


Non-OPEC Supply – Base                      52.1   52.2   51.6   51.3   51.6   52.3   53.2   54.3
Non-OPEC Supply – Potential                 52.1   52.2   51.7   51.5   52.1   53.2   54.8   56.6
Non-OPEC Supply – Macondo fallout*          52.1   52.1   51.6   51.3   51.5   51.9   52.5   53.7


Spare Cap – Base                            5.9    5.1    3.7    3.0    2.7    3.2    3.6    3.6
Spare Cap – Potential                       5.9    5.3    4.0    3.7    4.1    5.0    6.5    7.5
Spare Cap – adjusted for Macondo            5.9    5.0    3.8    3.0    2.6    2.8    2.9    3.0
*Note: Macondo Fallout assumes a 1-year delay
Source: Company data, Credit Suisse estimates

However in our Macondo adjusted case, spare capacity in 2014-2016 would remain close
to the 2.6-2.9mbd mark, a level with a higher probability of oil price spikes.
We stress that the timeline on the regulatory adjustment in response to Macondo could be
multi-year if, for example, regulations require all BOP’s to be replaced with higher
specifications, assuming such BOPs could be built, or if further R&D into subsea spill
response is mandated before drilling can resume. A 3 yr delay to Gulf of Mexico drilling
could drive global spare capacity as low as 2.4MBD in 2015, a level consistent with upside
price risks.




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Figure 102: Global oil spare capacity – with levels seen during the spikes
   (MMBD)                                                                                                                                                                                                                                                                                                                                                                                                                                                         (US$/bbl)
     7.0                                                                                                                                                                                                                                                                                                                                                                                                                                                              110

     6.0                                                                                                                                                                                                                                                                                                                                                                                                                                                                      100

                                                                                                                                                                                                                                                                                                                                                                                                                                                                              90
     5.0
                                                                                                                                                                                                                                                                                                                                                                                                                                                                              80
     4.0
                                                                                                                                                                                                                                                                                                                                                                                                                                                                              70
     3.0
                                                                                                                                                                                                                                                                                                                                                                                                                                                                              60
     2.0
                                                                                                                    1Q08: 2.1                                                                                                                                                                                                                                                                                                                                                 50
                                                                                                            4Q07: 1.9
     1.0                                                                                                                                                                                                                                                                                                                                                                                                                                                                      40

      -                                                                                                                                                                                                                                                                                                                                                                                                                                                                       30
            2003 2004 2005 2006 2007 2008 2009 2010E 2011E 2012E 2013E 2014E 2015E 2016E 2017E

                                                                                                            Spare capacity - CS Base case (LHS)                                                                                                                                                               WTI oil price (RHS)

Source: IEA, industry data, Credit Suisse estimates



The other fall-out of the Macondo incident would be from any regulatory response.
Changes to equipment in use, changes to procedures and regulatory requirements and
the need to build in extra redundancies for future projects, or provide for greater insurance
coverage or make provisions for potential accidents like Macondo would raise costs for
new projects. Marginal in-fill drilling or subscale finds might not be justified given the
recoverable oil remaining. Deeper high pressure wells might be deferred until technology
is seen as truly fail-safe. Potentially problematic, we highlight that Macondo was neither
drilled in the deepest water nor to the greatest depth. If Macondo is held to be above the
safe limits that the industry can drill, many GoMexico wells would be affected.


Figure 103: US Deepwater GoM Water Depth (ft) – Identified projects
  10,000
   9,000
   8,000
   7,000
   6,000
   5,000
   4,000
   3,000
   2,000
   1,000
     -
                                                                                                                                                                                                          Santa Cruz (MC 519)




                                                                                                                                                                                                                                                                                      Thunder Hawk (MC 734)



                                                                                                                                                                                                                                                                                                                                                        Macondo




                                                                                                                                                                                                                                                                                                                                                                                                                       Shenzi (GC 654)
            Silvertip (AC 815)




                                                                                                                                                                    Mad Dog (GC 826)
                                                                                                                                                                                       Isabela (MC 562)




                                                                                                                                                                                                                                                                                                                                                                  Kodiak (MC 771)




                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      Knotty Head (GC 512)
                                                                                                                                                                                                                                                                                                                                                                                                                                         Tubular Bells (MC 725)


                                                                                                                                                                                                                                                                                                                                                                                                                                                                          Ursa (MC 810)




                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                Droshky (GC 244)
                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                Pony (GC 468)


                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   Mars
                                                                                                                                                                                                                                                   Thunder Horse
                                                                                     Perdido




                                                                                                                                      Buckskin




                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            K2
                                                                                                                                                                                                                                Freedom (MC 948)


                                                                                                                                                                                                                                                                   Kaskida (KC 292)




                                                                                                                                                                                                                                                                                                                                                                                    Caesar/Tonga
                                                                                                                                                                                                                                                                                                               Heidelberg (GC 859)




                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          Tahiti (GC 640)




                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             Clipper (GC 299)
                                                                                                                                                                                                                                                                                                                                                                                                   Atlantis (GC 699)



                                                                                                                                                                                                                                                                                                                                                                                                                                                                  Tiber




                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                Dorado (VK 915)
                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  Friesian (GC 599)




                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          Llano (GB 386)
                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           Conger (GB 215)
                                                                                                             Lucius




                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 Telemark Hub
                                                                                               Appomatoks




                                                                                                                                                 St Malo (WR 678)
                                                                       Great White
                                 Chinook (WR 469)
                                                    Cascade (WR 206)




                                                                                                                      Jack (WR 759)




                                                                                                                                                                                                                                                                                                                                     Big Foot (WR 29)




Source: Company data, Credit Suisse estimates




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Figure 104: US Deepwater GoM Total Depth (ft) – Identified projects
  40,000

  35,000

  30,000

  25,000

  20,000

  15,000

  10,000

   5,000

     -




                                                                                                                                                                                                                                                                                                                              Thunder Hawk (MC 734)




                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      Santa Cruz (MC 519)




                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            Macondo
                                      Pony (GC 468)




                                                                                                                Knotty Head (GC 512)




                                                                                                                                                                                                                                                                                                                                                                                                                                Mad Dog (GC 826)


                                                                                                                                                                                                                                                                                                                                                                                                                                                                     Droshky (GC 244)




                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         Silvertip (AC 815)
                                                                                       Tubular Bells (MC 725)




                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   Ursa (MC 810)
                                                                     Kodiak (MC 771)




                                                                                                                                                                                                                                                                                                            Shenzi (GC 654)




                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   Isabela (MC 562)


                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            Mars
                                                                                                                                                           Buckskin




                                                                                                                                                                                                                                                                                                                                                                                          K2
                                                      Caesar/Tonga




                                                                                                                                                                                                                                                                                                                                                                                                                Thunder Horse




                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   Perdido
           Tiber
                   Kaskida (KC 292)




                                                                                                                                       Friesian (GC 599)


                                                                                                                                                                      Freedom (MC 948)



                                                                                                                                                                                                                            Heidelberg (GC 859)
                                                                                                                                                                                                                                                   Tahiti (GC 640)




                                                                                                                                                                                                                                                                                                                                                                                               Llano (GB 386)




                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        Atlantis (GC 699)
                                                                                                                                                                                                                                                                                                                                                                                                                                                   Conger (GB 215)




                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      Clipper (GC 299)


                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              Dorado (VK 915)
                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            Lucius




                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             Telemark Hub
                                                                                                                                                                                                                                                                                                                                                      Appomatoks
                                                                                                                                                                                         St Malo (WR 678)




                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     Great White
                                                                                                                                                                                                            Jack (WR 759)



                                                                                                                                                                                                                                                                     Cascade (WR 206)
                                                                                                                                                                                                                                                                                        Chinook (WR 469)




                                                                                                                                                                                                                                                                                                                                                                   Big Foot (WR 29)
Source: Company data, Credit Suisse estimates



Tighter Markets but With a Few Caveats
We think that while theoretically, the markets would appear to be tighter, there are few
factors that might mitigate the impact on actual oil prices (as we go forward). The first is to
note that GoM deepwater, while accounting for 15% of aggregate incremental growth to
2017, is actually only 4% of growth from now to 2013, and 5-6% up to 2014. The real
surge of the deepwater US GoM is beyond 2014. This gives the industry time to respond
to regulations and time for other factors such as energy efficiency or substitution to work.

Figure 105: US GoM surge is back-ended                                                                                                                                                                                                                                                                                                                             Figure 106: US GoM’s share of global supply growth
            Mbd                                                                                                                                                                                                                                                                                                                                                           (MMBD)                                                                                                                                                                                                                                                                                                (%)
 3,500                                                                                                                                                                                                                                                                                                                                                                    12                                                                                                                                                                                                                                                                                                     15
              GOM Surge is Backended
 3,000                                                                                                                                                                                                                                                                                                                                                                    10                                                                                                                                                                                                                                                                                                           13

 2,500                                                                                                                                                                                                                                                                                                                                                                           8                                                                                                                                                                                                                                                                                                     11

 2,000                                                                                                                                                                                                                                                                                                                                                                           6                                                                                                                                                                                                                                                                                                     9

 1,500                                                                                                                                                                                                                                                                                                                                                                           4                                                                                                                                                                                                                                                                                                     7

                                                                                                                                                                                                                                                                                                                                                                                 2                                                                                                                                                                                                                                                                                                     5
 1,000

                                                                                                                                                                                                                                                                                                                                                                                      -                                                                                                                                                                                                                                                                                                3
   500
                                                                                                                                                                                                                                                                                                                                                                                               2010E                            2011E 2012E                                                                    2013E 2014E 2015E 2016E 2017E
     0
                                                                                                                                                                                                                                                                                                                                                                                                                                                              Cumulative growth from GoM (LHS)
         2000
         2001
                    2002
                                      2003
                                                      2004
                                                                     2005
                                                                                       2006
                                                                                       2007
                                                                                                                                       2008
                                                                                                                                                           2009


                                                                                                                                                                                         2011E


                                                                                                                                                                                                                            2013E
                                                                                                                                                                                                                                                  2014E
                                                                                                                                                                                                                                                                     2015E
                                                                                                                                                                                                                                                                     2016E
                                                                                                                                                                                                                                                                                                           2017E
                                                                                                                                                                      2010E


                                                                                                                                                                                                            2012E




                                                                                                                                                                                                                                                                                                                                                                                                                                                              Share of GoM growth to total growth (RHS)


Source: IEA, industry data, Credit Suisse estimates                                                                                                                                                                                                                                                                                                                Source: IEA, industry data, Credit Suisse estimates

Our supply model already has redundancies built in through risk factors. For example, our
“potential” supply case has aggregate supply in the US GoM that is 600mbd higher than
our base case assumption (400mbd in 2017, aggregate 600mbd). These risk factors are
built in to account for potential delays – on the supply side, these reflect historical delays in
project cycles, and to account for the technically challenging nature of the projects.



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The Macondo incident reflects the technically challenging nature of the business. While
the specific event is not in our numbers, we have reflected the possibility that events
arising out of the technical challenges can impact production schedule. As such, our base
numbers may already reflect the possible 12-month delays that we assume in the
Macondo fallout scenario.
On the issue of LT oil price and costs – we expect an impact on the long-term costs of
development. However, our US$80/bbl LT oil price is set to accommodate the highest cost
source of supply – the Canadian Oil Sands, which our Canadian Oil analyst believes will
need US$80/bbl to justify investments including cost of an upgrader.
The final impact on the GoM cost curve will be easier to quantify once all the regulations
are known – however, with the cost of development ranging from US$55-70/bbl for
deepwater GoM, US$45-50/bbl for deepwater Brazil, and deepwater West Africa projects
covered under PSC contracts (costs are recoverable), there is enough cushion to absorb
higher costs with our current LT oil price assumptions, we think.
Conclusion
The Macondo GoM oil spill incident brings into focus the challenges that the world faces
with its oil supply and adds grist to the mill of Peak Oil theories. Our models suggest that
contrary to the consensus view –supply exists, and it can grow. Initially growth will come
from OPEC and its NGLs output, but later we also forecast the potential for non-OPEC
supply growth. Iraq and Russia remain significant supply wildcards. That said, there are
challenges and risks. Non-OPEC is increasingly reliant on technically challenging
deepwater. Decline rates are accelerating and we don’t yet have conclusive evidence that
higher spend is mitigating this trend. The industry is subject to the usual project timeline
slippages etc. We believe we have risked these into our assumptions, but events like
Macondo will bring these risks to the surface. We retain our US$80/bbl oil price view in
2011 and beyond.
In the short to medium term, we think that Oil prices are moving into Phase II of a
recovery. So far, the high spare capacity has not kept a cap on oil prices. Oil has instead
responded to the massive and sharp recovery in oil demand from the bottom of the
recession.
However, we now see global IP momentum peaking. As such, the residual growth surprise
if any is likely to come from the US. History (1998 recession) suggests that oil tends to
peak a few months after a peak in global IP momentum, and then slips into a range. We
see oil prices trading in a US$70-90/bbl range. Our Global Commodities Team similarly
believes that oil should trade in a US$65-90/bbl range.
In the next few months, we expect oil prices to be supported by the US demand recovery –
US demand seasonally bottoms in April, and then rises through summer. This is the first
driving season after the end of a recession, and the market will be looking at the pace of
US recovery to determine the extent and scope of a cyclical bounce in demand, and the
structural trend thereafter. By the latter part of 2H10, we expect the end of US driving
season, and much slower growth in China oil demand to weigh on oil prices (within our
range).




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Figure 107: Oil price vs global IP momentum – 1998-2001                                                         Figure 108: Oil price vs global IP momentum – current
  IP growth (%)                                                                               (Oct-98 = 1)        IP growth (%)                                                                                                            (Feb-09 = 1)
    10          5   months after IP peaked,                                                         2.5             10                                                                                                                          2.0
                    oil corrected 20-25%                                                                                                                                                                                                           1.8
    8
                                                                                                       2.0           5                                                                                                                             1.6
    6                                                                                                                                                                                                                                              1.4

    4                                                                                                  1.5           0                                                                                                                             1.2
                                                                                                                                                                                                                                                   1.0
    2                                                                                                                                                            Global IP momentum in this cycle
                                                                                                       1.0          -5                                                                                                                             0.8
                                                                                                                                                                  peaks in Mar-10, and then slows
    0                                                                                                                                                                                                                                              0.6
                                                                                                       0.5         -10                                                                                                                             0.4
   -2
                                                                                                                                                                                                                                                   0.2
   -4                                              Months from IP momentum bottomed -                              -15                                                        Months from IP momentum bottomed                                     -
        0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34                                                                 0 2 4               6 8 10 12 14 16 18 20 22 24 26 28 30 32 34
   T-0 = Oct-98                                                                                                      T-0 = Feb-09
                  Global IP momentum (LHS)                          Oil price - rebased (RHS)                                       Global IP momentum (LHS)                                          Oil price - rebased (RHS)

Source: Datastream, Credit Suisse estimates                                                                     Source: Datastream, Credit Suisse estimates

Figure 109: China GDP growth – Quarterly                                                                        Figure 110: China oil demand growth in 2010

   13%                                                                                                             30%
                                                                             11.9%
   12%                                                                                                             25%

   11% 10.6%                                                        10.7%                                          20%
                                                                                     10.5%
            10.1%
                                                                                                                   15%
   10%                                                                                        9.5%
                           9.0%                             9.1%
                                                                                                       8.7%        10%                                                                                                                     8.4%
    9%
                                                    7.9%                                                            5%
    8%                                                                                                                                                                                                                                      4.4%

                                   6.8%                                                                             0%
    7%
                                           6.2%                                                                    -5%
                                                                                                                           Jan-10
                                                                                                                                    Feb-10

                                                                                                                                             Mar-10




                                                                                                                                                                           Jun-10




                                                                                                                                                                                                                Oct-10


                                                                                                                                                                                                                                  Dec-10
                                                                                                                                                        Apr-10
                                                                                                                                                                  May-10



                                                                                                                                                                                    Jul-10

                                                                                                                                                                                             Aug-10
                                                                                                                                                                                                       Sep-10



                                                                                                                                                                                                                         Nov-10




                                                                                                                                                                                                                                                   2010
    6%

    5%
                                                                                      2Q10E

                                                                                               3Q10E

                                                                                                        4Q10E
           1Q08

                    2Q08

                            3Q08

                                    4Q08



                                                     2Q09

                                                             3Q09

                                                                      4Q09

                                                                              1Q10
                                            1Q09




                                                                                                                                                      China demand growth - if 2010 = same trend as history
                                                                                                                                                      China demand growth - if 2010 = 2005

Source: CEIC, Credit Suisse estimates                                                                           Source: China OGP, industry data, Credit Suisse estimates



Finally a word on Europe
While North American oil demand may turn positive yoy in Q210, we don’t anticipate
positive yoy European oil demand until 4Q10. European oil demand could have fallen as
much as 6% yoy in 1Q10 (despite a colder than usual winter). OECD Europe represents
14MBD annually or 16% of the global total). On a yearly basis, we are forecasting -1.7%
demand growth in 2010, +0.1% in 2011 and then decline thereafter. The debt package
helps take Armageddon scenarios off the table. However, the trend of persistent erosion of
European demand due to higher efficiency and the increasing availability of cheaper non-
oil price related natural gas looks firmly entrenched in our view.




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                                                                                                                                 14 June 2010



Figure 111: European Oil Demand Growth, YOY (MBD)

                                     0.20
    OECD Europe, MBD Demand Change




                                     0.00


                                     -0.20


                                     -0.40


                                     -0.60


                                     -0.80


                                     -1.00
                                             2002   2003   2004   2005   2006   2007   2008   2009   2010   2011   2012   2013


Source: IEA, Credit Suisse estimates



Equity Implications
The ramifications of the Macondo oil spill stretch from deferred offshore drilling, to clean
up costs/liabilities, business interruption along the Gulf Coast, the insurance industry to
renewed emphasis on energy efficiency and alternative energy supply (e.g. solar, wind
ethanol). Much of the impact will only become clear over time. In this note, we’ve pulled
together thoughts from various analysts around the team. Recently published notes have
focused mainly on the energy sector and clean up winners:
April 26th – Transocean, What’s the Financial Impact of the Horizon
April 30th - Macondo Well Tragedy Slams Services
May 3rd – Macondo Oil Spill, A More Conservative Liability Case
May 3rd – CLH, Leading the Way (Upgrade from Neutral to Outperform)
May 10th – Macondo Update – Liability Conference Call Takeaways
Thus far, approximately $41bn of equity value has been wiped from the companies
involved in the Macondo spill relative to their local markets and $60bn in absolute terms.
This equity value loss reflects a combination of fears over direct cleanup costs and claims
but also uncertainty over the future pace of offshore drilling. Companies that are not
exposed to Macondo but with operations in the Gulf have also declined in value - CVX for
example has also lost 2%, Apache 11% and Cobalt 34%. There have been winners too –
CLH is up 13%. All this has taken place against the backdrop of volatile equity markets,
falling on European debt concerns (and rebounding today). Companies like ENI and Total
with less exposure to the US Gulf are down 13-15% since April also.




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                                                                                              14 June 2010



Figure 112: Macondo Impact on Spill Companies and Other Company Performance
                                                 %          Change in           Change in
                      Initial     Latest     Change        Market Cap         Market Cap
Company             Price, $     Price, $       Abs         $MM, abs $MM, relative to local
BP                        60         49.3      -18%             -33491               -21211
APC                       73           60      -18%              -6431                -4819
Mitsui                   350          300      -14%              -4575                -3146
RIG                       90         68.2      -24%              -7303                -5957
HAL                       35        28.28      -19%              -6082                -4668
CAM                       47        37.74      -20%              -2259                -1748
Total                                                           -60141               -41549

Other Companies
CVX                       82        80.45       -2%              -3112
APA                      110        98.33      -11%              -3921
CIE                     13.5          8.9      -34%              -1638
CLH                       55        62.17       13%
TOT                     59.5         50.6      -15%
RDS                       62           56      -10%
ENI                       48           42      -13%

Index
SPX                    1210         1156        -4%
UK FTSE 100            5750         5374        -7%
Source: Bloomberg, Credit Suisse estimates

In the following sections, we update the state of play, review our call on the legal issues
surrounding potential liabilities, and outline some stock recommendations.
State of Play
The May 12th trajectory of the Macondo oil spill is shown below. Although large in
geographic area, much of the spill is a thin sheen on the surface. Heavier areas are more
contained which could help the offshore response. Landfall has been made and will
become more prevalent.




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                                                                                               14 June 2010


                                                     th
Figure 113: Predicted Oil Spill Trajectory for May 12




Source: DeepwaterHorizonResponse.com

Stopping the leak is the highest priority
Currently there are two active subsea leaks associated with the well, with a flow rate of 1-
5kbd (42-210,000 gallons per day). Worst case flow rates could be higher (if the well was
allowed to flow completely unobstructed. BP failed to install a concrete dome over the well
in order to capture the bulk of the leak and process the oil, over the weekend. Permanent
solutions include the drilling and successful execution of a relief well (60-90days) and/or
other options such as a “top-kill” - robot submarines (ROV’s) would remove a control
mechanism from the blowout preventer and reconfigure it to allow the pumping of pieces
of matting and rubber into the well, followed by heavy drilling muds that should provide
adequate pressure on the reservoir to close it.




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                                                                                                        14 June 2010



Figure 114: Relief wells                                        Figure 115: Current Offshore Response




Source: BP                                                      Source: BP


Keep the oil offshore
The other main priority is to keep the oil offshore through the use of booms, skimming,
sorbents and controlled burns. Dispersants are being used both at the wellhead and on
the surface in order to allow natural processes to break down the oil. It feels inevitable to
us that some oil will reach shore – given the limitations of booms’ effective operating
conditions and the amount of boom available for deployment. We would note that much of
the geographical spill area highlighted on maps is made up of a thin sheen with perhaps
only 5% being thicker. While this may reduce the visible impact, experts are still concerned
about the underlying ecological damage.
Onshore Remediation
Some of the learnings from the ExxonValdez spill suggest aggressive steamcleaning of
the shoreline is counterproductive to the natural bacterial breakdown of oils. The terrain
(wetlands and beaches) is also less conducive. Pressure to address any visible impacts
will no doubt be applied. Mother nature and time are the most likely solution – a process
that took years in Prince William Sound. The EPA is also monitoring air quality which
appears okay up until publication.
Clean-up attempts can be more damaging than the oil itself, with impacts recurring as long
as clean-up (including both chemical and physical methods) continues. Because of the
pervasiveness of strong biological interactions in rocky intertidal and kelp forest
communities, cascades of delayed, indirect impacts (especially of trophic cascades and
biogenic habitat loss) expand the scope of injury well beyond the initial direct losses and
thereby also delay recoveries.
Oil that penetrates deeply into beaches can remain relatively fresh for years and can later
come back to the surface and affect nearby animals. In addition, oil degrades at varying
rates depending on environment, with subsurface sediments physically protected from
disturbance, oxygenation, and photolysis retaining contamination by only partially
weathered oil for years.
Rocky rubble shores should be of high priority for protection and cleanup because oil
tends to penetrate deep and weather very slowly in these habitats, prolonging the harmful
effects of the oil when it leaches out.
Oil effects to sea birds and mammals also are substantial (independent of means of
insulation) over the long-term through interactions between natural environmental



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                                                                                                  14 June 2010


stressors and compromised health of exposed animals, through chronic toxic exposure
from ingesting contaminated prey or during foraging around persistent sedimentary pools
of oil, and through disruption of vital social functions (care-giving or reproduction) in
socially organized species.
Long-term exposure of fish embryos to weathered oil at parts per billion (ppb)
concentrations has population consequences through indirect effects on growth,
deformities, and behavior with long-term consequences on mortality and reproduction.
Macondo Spill Clean-Up Costs and Liabilities
At this stage it is too early to provide exact clarity on both costs and potential liabilities.
Neither the clean up costs/economic impact nor the cause and hence liability is known.
However, we have pulled together data on tourism and fishing revenues across the states
that could be affected. We have also overviewed the key legal frameworks that will apply.
Clean up costs
BP has apent over $350M, current spend is $10M per day and BP will drill two relief wells,
each costing $150M, we believe. For offshore spend we are assuming $12M per day for
90 days. Depending on the success of containment, the release could total anywhere
between 6.3 million gallons and 18 million gallons (90days). This compares with the
ExxonValdez at 10.8 million gallons. Comparing relative costs and accounting for inflation,
this suggests an additional onshore clean up liability of between $2.4-$7bn depending on
the extent and type of landfall made. Clearly, keeping the oil from a significant landfall is a
major priority.
Claims and liabilities
Different legal frameworks (Maritime Laws, OPA, State Laws) will govern the liability that
each company RIG, BP, APC, Mitsui, HAL, CAM, WFT and other service providers
involved in Macondo, will face. We have sent out a transcript of a call with a law firm held
Friday 7th May for more detail and published a summary note for this call May 10th which is
available on request.
Transocean : Our understanding is that RIG’s liability will be dealt with under maritime
law. A key determinant of this liability will be whether any company manager had “privity or
knowledge of circumstance” i.e. was aware of improper activity and failed to intervene.
BP : After the ExxonValdez, the Oil Pollution Act of 1990 (OPA) made oil companies liable
for both cleanup costs and the spill-related losses of businesses and individuals. As
responsible party, BP is liable for all clean up costs and liable for all private claims under
the OPA up to a limit of $75 million. However, if violations of federal regulations, gross
negligence or wilful misconduct are proven against BP, this liability cap would be removed.
We note that the lawyers will attempt to find ways to circumvent the $75million cap, even
in the event BP qualifies for the $75M cap under OPA (see the conference call transcript).
Congress is also considering an increase in the OPA cap to $10bn which might be applied
retroactively. In any case, BP is already paying “reasonable claims” and has said the OPA
cap is irrelevant for now. This approach may change if claims become “unreasonable”.
APC and Mitsui : Liabilities for the non-operator parties will likely be contained with an
operation agreement between the partners that is non-public. We understand that only BP
is designated as the “responsible party” under OPA. Such a contract may contain
provisions that allow APC and Mitsui to reduce their liabilities in the case that BP as
operator was grossly negligent.
Product and service providers : We believe there will be attempts to prove legal liability
both as to design/manufacture of products used in the drilling procedure (Blow Out
Preventer, Cement, Casing) and to the procedures used (cementing, casing and mud).
Operator Indemnification : We understand that typical offshore contracts include a
clause whereby the operator indemnifies service and product suppliers from environmental



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claims and liability except in the case of gross negligence, though the specific contracts
are non-public.
Legal avenues aside, what is clear is that the Macondo spill is different from the
ExxonValdez in that it has occurred in the heavily populated Gulf Region. The table below
shows estimated tourism and fishing revenues for the region, totalling some $31bn pa.
We envisage claims being made for natural resources from states [water, air, seashore],
for damage to personal property (e.g. beachfront), and for lost revenues both at the
government level e.g. royalties, lease payments, fishing licenses, sales taxes and also
from lost earnings for local individuals/businesses e.g. fisherman, resort operators, casino
operators, fuel docks, excursion boats, hotels. These claims will need to be assessed and
paid over a multi-year period. As we published in our May 3rd report, the present value of
clean up costs and liabilities in a more conservative case could total some $15.8bn. If the
containment works and the well is also successfully stopped, it could be lower. Depending
on the lost revenues across the Gulf, it could be higher. We’ve rethought the way we
calculate liability in the table below – but the $16bn central case is broadly the same, with
the key caveat that much remains uncertain. BP is now spending circa $10M per day. We
are using $12M per day for 90 days in our offshore cost estimate of $1bn and up to $7bn
for onshore clean-up at the high case.




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Figure 116: A Framework for Indicative Revenues and Potential Liabilities
Latest Revenue Figures                 Yr 1      Yr 2           Yr 3         Yr 4
Alabama
- Tourism                              3200      3200           3200         3200
- Fisheries                            1154      1154           1154         1154
                                       4354      4354           4354         4354
Louisiana
 - Tourism                            9300      9300           9300         9300
 - Fisheries                          3107      3107           3107         3107
                                      12407     12407          12407        12407
MI
- Tourism                              1600      1600           1600         1600
- Fisheries                             205       205            205          205
                                       1805      1805           1805         1805
Florida (Total)
- Tourism                             57000     57000          57000        57000
- Fisheries                           5000      5000           5000         5000

Florida (PanHandle, @ 20%)
- Tourism                             11400     11400          11400        11400
- Fisheries                           1000      1000           1000         1000
                                      12400     12400          12400        12400

Total Tourism                         25500     25500          25500        25500
Total Fisheries                       5466      5466           5466         5466
Total Tourism & Fisheries             30966     30966          30966        30966
Revenues

Assumed Earnings Margin impact         50%       50%            50%          50%

Economic Losses                       Year 1    Year 2         Year 3       Year 4
Fishing                               100%       50%            25%          25%
Tourism                                15%      10.0%          5.0%         5.0%

Clean-up (High End)                  $8,249
Lost Earnings                        4645.5     2641.5        1320.75       1320.75
Total Out of Pocket                  $12,894    $2,642        $1,321        $1,321
Discount rate                          8%
Present Value                        $16,223

BP share, $MM                        $10,545
Per share impact, $                    3.4

APC Share, $MM                        $4,056
Per Share impact, $                     8.2
Source: Company data, Credit Suisse estimates




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HES, BP and CVX most Exposed to the Gulf
The Macondo well was neither in the deepest water nor at the greatest target depth. This
raises the risk that a greater percentage of Gulf of Mexico wells might be seen as
technologically challenging (unless some clear operational error is found). We note that
the industry is adept at overcoming technical challenges and may convince goverments
that drilling risks can be mitigated further. HES, BP and CVX are most exposed to the Gulf
of Mexico. COP, BP, XOM and RDS are the most exposed to potential regulatory
tightening in the Arctic.

Figure 117: US Deepwater GoM reserves as % of Total               Figure 118: US GoM acreage (mn acres)
Reserves (2P)
 20%                                                               3.0


                                                                   2.5
 16%

                                                                   2.0

 12%
                                                                   1.5


  8%                                                               1.0


                                                                   0.5
  4%

                                                                   0.0




                                                                                              XOM
                                                                                 CVX




                                                                                                                                    MRO
                                                                                                                             TOT
                                                                                                                      ENI
                                                                          BP




                                                                                       RDS




                                                                                                      HES


                                                                                                              COP
  0%
        HES    BP    CVX    AVG MRO RDS         ENI   XOM   TOT

Source: Company data, Credit Suisse estimates                     Source: Woodmac, Credit Suisse estimates



Figure 119: Arctic reserves as % of Total Reserves (2P)           Figure 120: Arctic acreage (mn acres)
 20%                                                               5.0



 16%                                                               4.0



 12%                                                               3.0



  8%                                                               2.0


                                                                   1.0
  4%


                                                                   0.0
  0%
                                                                         RDS    COP      BP     XOM         CVX     ENI     TOT    MRO
       COP XOM      BP   AVG RDS CVX ENI MRO TOT HES

Source: Woodmac, Credit Suisse estimates                          Source: Woodmac, Credit Suisse estimates
Includes Canada Artic, Alaska & Sakhalin                          Includes Canada Artic, Alaska & Sakhalin



Including BP’s share of a $16bn liability in the US Gulf of Mexico, the shares look
undervalued in absolute terms and relative to the peers. However, we don’t expect this
value gap to close until more progress has been made to stop the leak.




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                                                                                               14 June 2010



Figure 121: Upside to Blended TP’s (with Macondo liability = $16bn)
    60%

    50%

    40%

    30%

    20%

    10%

     0%
            MRO        BP       HES     COP    CVX     TOT      XOM      ENI      RDS

                      Blended TP Upside/Downside [LHS]          CS TP [RHS]

Source: HOLT, Credit Suisse estimates



E&P Implications
From an E&P standpoint, all offshore producers have been hard hit since the Macondo
disaster began. Anadarko Petroleum (APC) who is a non-op partner in the well (25%
interest) has seen its shares fall ~20% and its market cap shed ~$7.0B in value. However,
anyone with significant deepwater and even GOM shelf exposure has seen its shares
suffer materially. Investors are concerned that greater regulation for drilling will lead to
additional costs, make permitting tougher and materially push back exploration and
development timelines. Companies with significant deepwater assets have fallen hard.
Specifcally, CIE, ATPG, MUR and NBL have fallen a respective 38%, 31%, 13%, and 9%.
Even shelf producers such as WTI (-18%), SGY (-20%) that tend to have a greater focus
on natural gas, have stumbled badly. In particular, companies operating in the deep shelf
(PXP-down 22%, EXXI-17%, MMR-20%) have been hit the hardest as investors worry that
the MMS will ban the ability to complete/test wells which have inordinately high pressure
and temperature.
We Think the Market Has Over-Reacted in Many Cases
We would agree that costs, risk premiums and timelines in the offshore will be negatively
impacted. However, we believe the US Government and Department of Interior (MMS)
understand that the Gulf is far too important to US supply (1.7 MMBbl/d) to make the
permitting process unwieldy. Increased regulation with revised processes for BOP tests
and maintenance are a given, but permits will continue to be issued, in our opinion. We
think the bite off Anadarko's market cap more than punishes it for the likely financial
damages it will suffer. As mentioned, in a more conservative scenario we find a gross
liability of $16.0B for Macondo, which would equate to $4.0B or $8.00 per share net to
APC. This compares to $6.9B in lost market cap so far. In addition, APC has insurance for
cleanup and relief wells of ~$160 MM net. While non-op partners are generally liable for
their portion of environmental and civil liabilities, we feel that APC could be protected
depending on the wording of the operator agreement, if BP is seen as negligent (too early
to tell as yet). Meanwhile, APC has one of the best stories in the E&P space with a world
class suite of discoveries and meaningful future NAV growth potential.




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So What to Do With the E&Ps
We continue to have a preference for low-cost E&Ps that can fund growth internally.
Clearly, the Gulf event highlights the value of onshore oil in the US and we continue to
favor Whiting Petroleum (WLL) and Brigham Exploration (BEXP). We also like Anadarko
(APC) and Noble Energy (NBL) for their large backlog of oil-driven growth. We think its too
early to buy pure gas names generally because supply will keep rising and prices will
remain pressured until E&Ps significantly reduce the gas rig count (and that’s not
happening). However, we do believe that Petrohawk (HK) and Range Resources (RRC)
can still prosper given their vast best-in-class position in the Eagle Ford, Haynesville (HK)
and Marcellus Shale (RRC) plays.
Clean Harbors (TP $74/sh, Outperform)
Clean Harbors (CLH) is an environmental services company headquartered in
Massachusetts which provides emergency clean-up services for both public and private
entities. They have long-standing relationships with the Coast Guard, Fish and Wildlife
Associations, as well as BP. The company is already working on the clean-up effort,
providing everything from booms to boats to skimmers. The company currently has
approximately 600 people on site (with more on the way) and is receiving requests to
provide additional resources, including vacuum equipment, which we believe will be used
for the cleaning of some of the more sensitive areas, particularly off the coast of LA.
The company is primarily on site in Louisiana where the slick is reported to have hit
selected areas of the coast, but is also mobilizing assets in other states around the gulf
coast (MS, AL, FL). They are also sharing a response center on Dauphin island with the
Coast Guard to ensure they work hand in hand to maximize efficiency thus minimizing
environmental impact. The focus right now is primarily on the more sensitive marsh and
wetlands, home to some of our nation’s most precious wildlife. Going forward, we
anticipate additional contract workers to help with the effort if/when the slick spreads
across the Gulf.
Although the company states it is too early to gauge any potential revenue streams, given
the magnitude of the spill, difficulty to reach areas within the wetlands of the Gulf Coast
and the size of the clean-up area (potentially spanning from Louisiana to Florida), we
believe the clean-up effort could be years. CLH is primarily paid per person and by
equipment utilization. As much as we would like to see a swift and easy clean-up, based
on the number of variables affecting the effort, we believe the spill will result in a recurring
revenue stream. It is also important to note that CLH bills based on sites, therefore
receiving revenues from several sources.
We believe revenues of $60-80m would be a realistic estimate going forward, with about
25% EBITDA margins. Although we do not recommend buying CLH based solely on its
Gulf prospects, we reiterate our belief that the market is not considering the company’s
potential “benefit” from the clean-up effort and continue to believe investors are
undermining the company’s core business prospects. From the company’s involvement in
clean-up initiatives in the Gulf to providing environmental and industrial services to
companies developing the Marcellus Shale in Pennsylvania, we believe CLH will continue
to benefit from relationships within the energy industry.
Other Clean Up Winners
The two companies most likely to participate in the immediate clean up and after effects of
the BP spill are URS Corporation and Shaw Group. To be clear, the dollars associated
with the clean up remain uncertain and will largely depend on how well the spill is
contained and if it moves onshore. It is also unclear who will be in charge of the clean up,
BP alone or will government agencies like FEMA, the EPA or the Coast Guard be involved
in delving out work to contractors. Last, if disasters like Hurricane Katrina set any
precedence, the after effects of the spill could end up creating more work than the initial
clean up itself.



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URS has one of the strongest customer relationships with BP currently through their MSA
agreements and has already been approached to provide environmental remediation and
GIS studies related to the spill. This is likely just the beginning. URS also has relationships
with FEMA, the Coast Guard and the EPA; if the government were to get involved in the
clean up. Before the spill, URS had approximately 3,600 people employed in the Gulf
region which represents about 9% of their total employee base. Obviously more could be
brought in if need be.
Louisiana based firm, Shaw Group is also positioned to participate in the clean up. We
would argue their relationships are likely stronger with government agencies like FEMA,
EPA, the Coast Guard or the Core of Engineers versus BP. Also if the state of Louisiana
becomes involved with the clean up, SHAW is probably best positioned. Again it remains
difficult to estimate the potential impact and unlike URS, Shaw has not been brought in to
provide any services yet. Shaw was one of the biggest beneficiaries of Hurricane Katrina
which end up bringing in north of $1B to the top line or approximately $0.50 but over an
extended period of time.
RIG (TP $92/sh, Neutral)
Management believes it is fully indemnified from wellbore pollution. RIG continues to
support BP in its well containment efforts and is conducting an investigation to determine
the cause of the accident. Management believes it is fully indemnified by BP for any
liability associated with pollution and contamination from the wellbore, stating that the
contract language “is clear” regarding indemnification. That said, RIG was not in a position
to comment on its potential role in the accident (including if the Horizon semisubmersible
and BOP were properly maintained), citing its ongoing investigation. We note that in
Tuesday 11th May Senate Hearings, BP said there was pressure information that could
have raised concerns about replacing drilling mud with sea water. BP did not say who had
knowledge of these anomalous pressure readings - this potentially raises concerns over
the actions of both BP and RIG in the hours leading up to this tragedy.
Higher cost guidance on the horizon. RIG raised full-year opex guidance to $5.2 to $5.5
billion from $5.0 to $5.4 billion, citing $200 MM of anticipated costs associated with the
Deepwater Horizon incident related to insurance deductibles (~$65 MM), higher
anticipated insurance premiums, and legal costs. Assuming the mid-point of the range,
RIG modestly increased its SG&A guidance to $245 MM from $235 MM (-$0.03 per share
impact), but this was more than offset by lower tax guidance of 16% vs. 17% previously
(+$0.10 per share impact). RIG did increase its capex forecast slightly to $1.4 billion from
$1.3 billion previously.
Revising estimates. We revise our 2010/2011 EPS estimates to $8.00/$9.00 from
$8.20/$9.05 to reflect updated company guidance, removal of the earnings impact from
the Deepwater Horizon, and the newly announced contracts. RIG trades at 8.7x and 5.4x
our 2010 EPS and CFPS estimates vs. its peers at 9.8x and 6.3x, respectively. We revise
our 12-month target price to $92 from $94 per share, which is at parity with our DCF-
model, as a result of lower estimates and slightly higher capex. Since the Deepwater
Horizon accident, RIG shares have fallen 24.3%, underperforming peers by 8.4% as
concerns mount about the ramifications of the accident and subsequent oil spill. While RIG
shares are attractively valued, we believe the potential for sustained share price gains will
hinge on whether management can demonstrate that the equipment on the rig (including
the BoP) was appropriately maintained prior to the incident and the actions performed by
the crew were consistent with industry practices.
CAM (TP $48/sh, Neutral)
We believe establishing product liability is likely to be extremely difficult, given (1) the
active use and regular testing of the BOP, (2) that the BOP is 9-10 years old, with the
warranty period likely 12 months, (3) that CAM does not appear to have serviced the unit
over its life (although it did provide at least some of the spare parts) and (4) that the BOP
was modified by RIG in 20005 at the instruction and paid for by BP. It is worth mentioning,


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however, that the plaintiff's attorneys may try to pin CAM on either (1) a latent defect or (2)
inadequate warnings regarding the appropriate use of the BOP; although we still imagine
the risk to CAM related to being found culpable is still very small, these potential angles at
least add some risk, all else equal.
We are cautious on OFS near term pending better clarity on political and regulatory
reaction related to offshore drilling. Yet in light of CAM's underperformance, our perception
that it is unlikely to bear responsibility for the event and the plausible outcome that BOP
requirements may need to be strengthened, we expect CAM to at least modestly
outperform.
HAL (TP $42/sh, Outperform)
For different reasons, we also believe there is a very small risk for HAL related to this
incident. As a provider of the services for BP, HAL's responsibility would relate to faulty
cement procedure of some sort, which attorneys acknowledge is even harder to establish
than product defect. We believe that BP was integrally involved with all of the procedures
on the rig and therefore will be considered the responsible party. Further, we expect that
BP indemnifies HAL in their contract for all environmental liability and that the contract has
HAL not assuming any consequential damages.
In our legal liability conference call, with respect to the indemnification language in the
HAL-BP contract in the event that HAL is found responsible, the attorneys did point out a
set of circumstances that may negate the indemnification. The attorneys mentioned that
the cementing service may not be subject to Maritime law, because the cementing service
is similar to that which takes place onshore. That would allow the action at the State court
level (whereas Maritime law precludes State level action). And both LA and TX have
limitations on the ability of one company to indemnify the actions of another company if
one party (HAL in this case) was determined to be grossly negligent or was found to be
solely responsible for the incident. However, both of these standards seem very high to us
and again, we think the risk to HAL is very low. As such we view shares of HAL as being
very attractively valued. Our aforementioned caution on the group notwithstanding, given
secular prospects and expected performance HAL remains our top pick.
Impact to the Alternative Energy & Cleantech Sectors
As we have noted earlier in this report, politicians will likely use rising oil prices and public
support for increased environmental policy to introduce energy legislation. Alternative
Energy companies benefit from high oil prices and a supportive political environment.
That said, the US is not the largest country for alternative energy demand, especially solar,
today. Much of the larger cap quoted Alt Energy space is being affected by issues in
Europe, for example.
We believe that it is unlikely the Senate can pass a major, all-encompassing piece of
carbon legislation soon. The most promising initiative that would potentially be accelerated
is the bill from Senators Kerry and Lieberman. Even if they do introduce the bill this week,
which has been suggested by media, obtaining 60 votes is less than certain, especially
from Republicans (Senator Graham has already started to distance himself from the bill).
Even without comprehensive carbon policy, it is possible that more narrow legislation
could be introduced which would benefit wind companies. The 30% Cash Investment Tax
Credit for installing wind turbines is set to expire at the end of the year. If a narrow piece
of legislation was introduced to promote non-fossil fuel energy, it is plausible that
extending the ITC could easily be included.
There has already been tremendous support behind efficiency, including smart grid
stimulus grants ($3.4 billion already awarded), block grants for retrofitting buildings to
become more efficient, massive grants and loans to battery companies and automakers,
and funding for a federal credit to purchase an electric vehicle. While carbon policy and
renewable electricity standards (including efficiency mandates) would benefit the sector
longer-term, the impact may not be immediate.


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Stocks still dominated by European issues near term: We would refrain from making
individual stock calls in solar and wind names around the oil spill ramifications, as the near
term catalysts for the sector are mainly from outside the US. For example, solar stocks
are being driven by threats of feed-in-tariff cuts in Italy and substantial pressures from the
Euro falling vs. the dollar. Wind manufacturers such as Vestas and Gamesa are suffering
from their own problems. Large cap US utilities exposed to renewables are also wrapped
up in a call around natural gas prices. In the longer-term, carbon policy or a Renewable
Electricity Standard will be important for US demand, but the likelihood of any
comprehensive bill passing soon looks low and the immediate impact to stocks would be
muted.
Implications for Ethanol Policy
We think tighter restrictions on offshore oil drilling would accelerate the Obama
administration's efforts to increase the blend rate of alternative fuels in the U.S. gasoline
supply, particularly corn-based ethanol. The Environmental Protection Agency is already
expected to grant waivers to gasoline refiners in August to increase their ethanol blend
rates from 10% to 15% for newer vehicles built after 2001. However, in our proprietary
survey of refiners, we could not find a single gasoline blender willing to accept the waivers.
Gasoline refiners and station operators say they won't adopt a higher blend until the
government waives them of legal claims that engine owners may raise and/or amends the
terms of the warranties on their equipment. This sticking point may take some time to
resolve.
The administration could either choose to a) directly address the gasoline operators
concerns by absolving them of legal liability for 15% blends, or b) granting waivers for
11%-12% blends across all vehicles including older ones. The gasoline industry is more
amenable to 12% blends because it may not be corrosive enough to merit new pumping
equipment or underground storage tanks. In addition, it’s clearer for consumers (and
hence there is less liability) to pump 12% for all cars rather than 10% for old ones and
15% for new ones.
Given President Obama's farm state background, we have been surprised by the
administration's mixed message on ethanol. On one hand, they are proponents for higher
blending rates, but on the other, they have expressed concerns about the industry's
carbon footprint. Restrictive measures on offshore drilling could be the catalyst for more
aggressive adoption.
Who wins and loses: ADM is the most logical beneficiary in the food space because they
produce 1.5 billion gallons of ethanol per year. Tyson and Smithfield Foods would get hurt
by higher grain costs to feed their livestock.
Positive in the Short Term for Refining; Potentially Negative Longer Term
Any shift towards greater non-oil transportation and industrial demand, will erode the
demand for US refining. As we highlighted in our initiation, CO2 policy and CAFÉ
standards are already headwinds facing US demand that the gulf oil spill could accelerate.
CO2: We do not envision a CO2 policy that is aimed at closing the U.S. refining industry.
However, even a well designed CO2 policy that provides line of sight on the true cost of
emissions for consumers by raising gasoline prices at the pump will depress U.S. demand
for gasoline. We calculate that a $30 per metric ton (MT) price of C02 fully reflective of the
C02 emitted in the wells to wheels life cycle of gasoline would add circa $0.27 per gallon
to the cost of motoring (roughly 10%). Consumer behavior does respond to price signals in
terms of vehicle choice and miles driven. Based on the observed elasticity through the
2004-08 upcycle, we would expect an increase in prices of this magnitude to drive down
U.S. demand by an additional 300,000 bbl/d by 2020, equivalent to one or two additional
refineries that would need to close.
Weak end-user demand for gasoline: U.S. gasoline demand is under pressure from higher
fuel efficiency standards and a rising share of renewable fuels. We believe up to an


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additional 1.1 million bbl/d of U.S. refining capacity needs to close or be retooled (to make
diesel) to balance this U.S. gasoline surplus by 2016 and beyond. We explicitly model a
double dip in refining margins in 2012, after the U.S. recovery ebbs, to drive out this
additional marginal capacity. Weak end-user demand will constrain multiples, in our view.

Figure 122: U.S. Gasoline Under Pressure from CAFÉ and RFS
                    10,000                                                                                                                  2011-2020 average growth rates:
                                                                      Economic bounce back                                                          CAFE only - 0.8%
                                                                      slows decline in 2010                                          Inc. RFS - 1.7%, requires Blend Wall relaxation
  US gasoline consumption KBD




                                9,000



                                8,000



                                7,000



                                6,000



                                5,000
                                                      2007            2008        2009     2010   2011     2012        2013         2014            2015        2016     2017   2018     2019      2020

                                                                                 Gasoline demand after CAFE                       Refiner Gasoline demand after CAFE and RFS

Source: EIA, Credit Suisse estimates

In the shorter term, if Mississippi river traffic or the LOOP terminal (imports 1.2mbd) is
disrupted for extended period of time, then refinery crude runs and product logistics might
impact the Gulf Coast refining system. This could provide a temporary refining margin
bounce, depending on its extent and may explain some of the recent margin bounce.

Figure 123: Gulf Coast Margins


                                                      35
                                                                               Diesel Crack                Gasoline Crack
                                                      30

                                                      25
                                US Gulf Coast $/bbl




                                                      20

                                                      15

                                                      10

                                                       5

                                                       0

                                                       -5

                                                      -10
                                                             Jan-00


                                                                             Jan-01


                                                                                         Jan-02


                                                                                                  Jan-03


                                                                                                              Jan-04


                                                                                                                         Jan-05


                                                                                                                                           Jan-06


                                                                                                                                                           Jan-07


                                                                                                                                                                       Jan-08


                                                                                                                                                                                Jan-09


                                                                                                                                                                                          Jan-10




Source: Company data, Credit Suisse estimates




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Property Casualty Insurance
Insured Loss
We estimate insured losses from Transocean (RIG) and the BP consortium to be $1.3 Bn.
Our estimate assumes that RIG would not be liable for pollution clean up costs. However,
if RIG is found to be grossly negligent, insured losses could rise a further $600 mn. We
believe the primary liability for cleanup costs will be with the BP consortium. Since BP,
which owns 65% of the consortium, self insures, a large portion of the losses will not hit
the insurance industry. In addition, lawsuits against equipment manufacturers, suppliers
and sub-contactors as well as business interruption claims will likely increase total losses
for the insurance industry.
Impact on Insurers manageable
We believe that losses, while significant, will be manageable. From an insurance
company perspective, this loss is well-spread across the insurance market and shouldn't
be a huge hit to any single underwriter.
Impact on offshore energy pricing
The loss should be a positive for pricing in the offshore energy sector, where pricing was
declining 15% prior to this event. However, we don’t believe this will lead to a sustained
hard market in offshore energy insurance, given existing capacity levels.
Impact on demand for insurance
Business interruption coverage resulting from pollution is not widely purchased by
insureds. This environmental disaster could encourage more businesses to purchase such
cover.
Ancillary liability is complicated – ultimate loss costs should be manageable,
though legal defense costs could be high:
(1) Lawsuits against equipment manufacturers such as Cameron, sub-contractors and
    consultants such as Halliburton
    a.    Cameron (CAM) which manufactured the blow out preventer (BOP) that failed on
          the RIG, has a $500mn liability insurance policy. According to Brad Handler, our
          U.S. Oilfield Equipment and Services analyst, establishing product liability is likely
          to be extremely difficult, given (1) the active use and regular testing of the BOP,
          (2) that the BOP is 9-10 years old, with the warranty period likely 12 months
          following purchase and thus expired, and (3) that CAM does not appear to have
          serviced the unit over its life (although it did provide at least some of the spare
          parts). It is worth mentioning, however, that the plaintiff's attorneys may try to pin
          CAM on:
         i. A latent defect or inadequate warnings regarding the appropriate use of the
            BOP. For example, news reports indicate that the sheer rams on the blow out
            preventer were not designed to cut at threaded ends of the pipe. If not made
            expressly clear by CAM, that would be an example of failure to warn, for which
            CAM would be held responsible. Although we still imagine the risk to CAM
            related to being found culpable is still small, these potential angles at least add
            some risk, all else equal. One potential defense by CAM could be that RIG
            modified the BOP in 2005 which could have altered the way it functioned.
         ii. Warranty action by RIG: CAM’s warranty to RIG on the BOP would in normal
             circumstances have expired since the BOP was 9-10 years old while the
             warranty is only for 12 months. However, according to Louisiana case law,
             depending on specific language in the warranty, if the defect was in existence
             but unknown and had not yet caused damage, the 12 month warranty would not
             be triggered until after the event of failure. If this is applicable, RIG could still
             sue CAM on the warranty today even though the warranty ‘expired’ several


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           years ago. We understand that RIG does not currently plan to purse CAM
           using this defense. Also, the fact that RIG modified the BOP in 2005 could
           make it difficult to sue CAM.
    b.   Halliburton (HAL): For different reasons, our U.S. Oilfield Equipment and
         Services Analyst also believes there is a very small risk for HAL related to this
         incident. As a provider of the services for BP, HAL's responsibility would relate to
         faulty procedure of some sort, which attorneys acknowledge is even harder to
         establish than product defect. We believe that BP was integrally involved with all
         of the procedures on the rig and therefore will be considered the responsible party.
         Further, we expect that BP indemnifies HAL in their contract for all environmental
         liability and that the contract has HAL not assuming any consequential damages.
         In our legal liability conference call, with respect to the indemnification language in
         the HAL-BP contract in the event that HAL is found responsible, the attorneys did
         point out a set of circumstances that may negate the indemnification of HAL. The
         attorneys mentioned that the cementing service may not be subject to Maritime
         law, because the cementing service is similar to that which takes place onshore.
         That would allow legal action at the State court level (whereas Maritime law
         precludes State level action). And both LA and TX have limitations on the ability of
         one company to indemnify the actions of another company if one party (HAL in
         this case) was determined to be grossly negligent or was found to be solely
         responsible for the incident. However, both of these standards seem very high to
         us and again, we think the risk to HAL is very low.
    c.   Defense costs: Insurers would likely be liable for at least some of the defense
         costs which could be high. Defense costs for general liability contracts are not
         included in the insurance limit provided by insurers (i.e. they are paid for
         separately).
(2) Business interruption claims. Mitigating factors imply that ultimate losses may not be
    as high as investors expect
    a.   Pollution is usually excluded as a covered peril in admitted market policies.
    b.   Civil Action (the Government forcing an industry to shut down) losses are only
         covered if they arise out of a covered peril
    c.   Subrogation: Insurers can try to recover losses by suing the BP consortium, if the
         cause was pollution. However, this would imply paying losses first and then suing
         BP which could be a long drawn out process and litigation costs could be
         expensive.
There may be concerns about whether courts or politicians may try to force insurance
companies to cover business interruption claims in spite of policy exclusions because of
insurers’ ability to pay. We don’t believe this will be successful in light of the court
decisions for flood exclusion in favour of homeowners insurers during Hurricane Katrina.
An example can be found in Allstate’s 2008 10-K “The Mississippi Attorney General filed a
suit asserting that the flood exclusion found in Allstate's and other insurance companies'
policies is either ambiguous, unenforceable as unconscionable or contrary to public policy,
or inapplicable to the damage suffered in the wake of Hurricane Katrina. In December
2008, the trial court ruled that, as a matter of law, the flood exclusions are not ambiguous,
unconscionable or against public policy and do not constitute a deceptive trade practice.
The Court also ruled that the Attorney General lacks standing necessary to bring the suit,
as he is not a party to the insurance contracts at issue. Thus, all of the claims filed against
the Company were dismissed.”




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GOM infrastructure
Enbridge Inc. (ENB) has one of the most extensive natural gas GOM offshore pipeline
system. Majority of the existing system came when Enbridge acquired the Gulf of Mexico
pipeline assets from Shell for roughly US$613m in January 2005. At the end of 2009 the
system consists of 13 natural gas gathering and FERC-regulated transmission pipeline
and one oil pipeline with roughly 1,500 miles (2,400 km) of underwater pipe and onshore
facilities that transported roughly 2.3 bcf/d in 2009 (50% of production).

Exhibit 124: GOM production and ENB historical offshore pipeline volumes
Federal offshore GOM natural gas                   2005      2006      2007      2008      2009
Marketed production (mmcf/year) - EIA          3,132,089 2,901,969 2,798,718 2,326,943 2,432,900

Enbridge Offshore Pipelines (avg. mmcf/d)          2,102     2,153      2,060     1,672     2,037
Enbridge Offshore Pipelines (avg. mmcf/year)     767,230   785,845    751,900   610,280   743,505
Source: US Energy Information Administration (EIA) and Company data

In 2009 ENB secured two deepwater projects, the US$500m Walker Ridge Gas Gathering
System and the US$250m Big Foot Oil Pipeline. For greater details please see our note
titled “Deep dive into the Ultra Deep” published 05 October 2009. See Exhibit 125 for
Enbridge’s assets in the Gulf of Mexico.

Exhibit 125: Enbridge offshore pipeline map




Source: Company data

On ENB’s Q1 2010 conference held on 5 May 2010, the company stated it is too early to
assess the longer-term implications from the recent Gulf of Mexico oil spill on its onshore




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pipeline network. From our perspective, we view the near-term impact to Enbridge as very
minimal. Yet, depending on the direction and pace of future policy developments toward
the energy industry’s activities in the Gulf of Mexico, Enbridge’s future growth prospects
from new pipelines and increased volumes may be adversely impacted.
Appendix 1 - Excerpts from Prepared Congress Testimony
We summarized take-aways from a May 7th conference call to review the potential liability
issues surrounding the Macondo well disaster in our May 10th note Macondo – Liability
Conference Call. We’ve included in this appendix some of the relevant paragraphs from
BP, HAL and RIG from Tuesday 11th senate hearings. We highlight some additional areas
which need further investigation, specifically
1) BP said there was pressure information that could have raised concerns about
replacing drilling mud with sea water. BP did not say who had knowledge of these
anomalous pressure readings - this potentially raises concerns over the actions of both BP
and RIG in the hours leading up to this tragedy and could help APC and Mitsui depending
on the terms of the Operators Agreement. It’s too early to tell.
2) In Q&A it emerged that BP had paid RIG to modify the BOP so that the lower pair of
shear rams could be used to test BOP function without interupting drilling.
3) From RIG’s testimony, Weatherford is now a company with questions to answer
regarding the placement of casings, investigations will also include the casing
manufacturer (not yet known).

Extracts from BP Prepared Comments
BP – as a leaseholder and the operator of the well – hired Transocean to drill the well.
Transocean, as owner and operator of the Deepwater Horizon drilling rig, had
responsibility or the safety of all drilling operations. We don’t know yet precisely what
happened on the night of April 20, but what we do know is that there were anomalous
pressure test readings several hours prior to the explosion. These could have raised
concerns about well control prior to the operation to replace mud with sea water in the well
in preparation for the setting of the cement plug. Apart from looking at the causes of the
explosion, we are also examining why the blowout preventer did not work as the ultimate
fail-safe to seal the well and prevent an oil spill. Transocean has suggested that the BOP
was no longer needed because the drilling process was complete, but the BOP remains a
critical piece of equipment to ensure well control up until the well is sealed with a cement
plug prior to abandonment.

Extracts from RIG Prepared Comments
"As the drilling progresses, huge pipes are inserted into the well to maintain the integrity of
the hole that has been drilled and to serve as the primary barrier against fluids entering the
well. This job is coordinated by the casing sub-contractor selected by the Operator (in this
case, Weatherford). In its well plan, the Operator specifies the diameter and strength of
each casing segment, purchases the casing, and dictates how it will be cemented in place.
What caused that catastrophic, sudden and violent failure? Was the well properly
designed? Was the well properly cemented? Were there problems with the well casing?
Were all appropriate tests run on the cement and casings? These are some of the critical
questions that need to be answered in the coming weeks and months. Over the past
several days, some have suggested that the blowout preventers (or BOPs) used on this
project were the cause of the accident. That simply makes no sense. A BOP is a large
piece of equipment positioned on top of a wellhead to provide pressure control. As
explained in more detail in the attachment to my testimony, BOPs are designed to quickly
shut off the flow of oil or natural gas by squeezing, crushing or shearing the pipe in the
event of a “kick” or “blowout” – a sudden, unexpected release of pressure from within the
well that can occur during drilling. The attention now being given to the BOPs in this case



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is somewhat ironic because at the time of the explosion, the drilling process was complete.
The well 5 had been sealed with casing and cement, and within a few days, the BOPs
would have been removed. At this point, the well barriers – the cementing and the casing
– were responsible for controlling any pressure from the reservoir. To be sure, BOPs are
an important aspect of well control. During drilling, BOPs provide a secondary means of
controlling pressure if the primary mechanisms (e.g., drilling mud) prove inadequate. BOPs
are robust, sophisticated pieces of equipment that can be activated by various direct and
remote methods. Since the BOPs were still in place in this circumstance, they may have
been activated during this event and may have restricted the flow to some extent. At this
point, we cannot be certain. But we have no reason to believe that they were not
operational – they were jointly tested by BP and Transocean personnel as specified on
April 10 and 17 and found to be functional. We also do not know whether the BOPs were
damaged by the surge that emanated from the well beneath or whether the surge may
have blown debris (e.g., cement, casing) into the BOPs, thereby preventing them from
squeezing, crushing or shearing the pipe.

Extracts from HAL Prepared Comments
Approximately 20 hours prior to the catastrophic loss of well control, Halliburton had
completed the cementing of the ninth and final production casing string in accordance with
the well program. Following the placement of 51 barrels of cement slurry, the casing seal
assembly was set in the casing hanger. In accordance with accepted industry practice, as
required by MMS and as directed by the well owner, a positive pressure test was then
conducted to demonstrate the integrity of the production casing string. The results of the
positive test were reviewed by the well owner and the decision was made to proceed with
the well program. The next step included the performance of a “negative” pressure test,
which tests the integrity of the casing seal assembly and is conducted by the drilling
contractor at the direction of the well owner and in accordance with MMS requirements.
We understand that Halliburton was instructed to record drill pipe pressure during this test
until Halliburton’s cementing personnel were advised by the drilling contractor that the
negative pressure test had been completed, and were placed on standby. We understand
that the drilling contractor then proceeded to displace the riser with seawater prior to the
planned placement of the final cement plug, which would have been installed inside the
production string and enabled the planned temporary abandonment of the well. Prior to the
point in the well construction plan that the Halliburton personnel would have set the final
cement plug, the catastrophic incident occurred. As a result, the final cement plug was
never set. Halliburton is confident that the cementing work on the Mississippi Canyon 252
well was completed in accordance with the requirements of the well owner’s well
construction plan




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Macondo Liability Conference Call Highlights (May
10th, 2010)
■   We summarize take-aways from a conference call to review the potential liability
    issues surrounding the Macondo well disaster: We hosted a conference call with
    Leopold Sher and Peter Hilbert from Sher Garner Cahill Richter Klein and Hilbert to
    discuss the legal issues around Macondo. A transcript of the call is now available upon
    request. The call raised as many questions as it answered: What follows are the most
    interesting takeaways (and questions) from the call (we note these attorneys disclosed
    their firm has been retained to represent aggrieved parties related to the spill). Please
    also see Exhibit 126 for a “flow chart” of potential legal outcomes.

■   Apparent limitation of liability for RIG: The Deepwater Horizon is expected to be
    considered a “ship” and therefore subject to liability limitation provisions of Maritime
    Law. Liability limitation has various benefits, including that all claims are filed together
    in a Federal Court and that as long as RIG was without privity or knowledge leading to
    the casualty, RIG’s pollution liability may be limited to the value of the rig after the
    accident (i.e. $0).

■   Potential warranty challenges for CAM: The attorneys indicated that Maritime law
    recognizes the right of third parties to file liabilities claims. Liability would be
    established if the BOP could be determined to be defective because of its design,
    manufacture or warnings (= instructions on proper use). Lawyers may argue that a
    warning may have been required, for example, that the BOP should not be used to cut
    thicker sections of drill pipe. Further questions were raised regarding warranty
    language — we are now less clear that warranty protection is limited to 12 months
    after sale.

■   State jurisdiction may raise risks regarding indemnification for Services? HAL
    has suggested that it generally does not take on environmental liability, leaving the
    inference that BP has indemnified HAL in this case. The attorneys on our call
    suggested that products and services provided may be subject to Louisiana or Texas
    Law, which can interfere with the enforcement of indemnity agreements with regards
    to gross negligence (or may limit amounts to specific insurance provision). We
    maintain that it seems highly unlikely that HAL can be established as having been
    grossly negligent given BP’s ongoing involvement in the drilling program.

■   The call revealed two interesting sidebars on the Oil Pollution Act (OPA): Under
    OPA BP is responsible for all cleanup/removal, but assuming no gross negligence,
    willful misconduct or violation of federal regulation, its liability to claimants is $75MM. 2
    sidebars include (i) whether punitive damages can be pursued in the event of
    negligence and (ii) what constitutes applicable Federal regulation–e.g. it may have
    been enough for the MMS to have raised concerns about BOPs even if rules had not
    been updated.

■   Questions persist about the sequence of events and the decision to remove the
    drilling mud. Industry observers continue to piece together the sequence of events
    preceding and following the explosion on the Deepwater Horizon. We believe it is
    important to stress that this process is filled with conjecture. But it may indeed be
    relevant to share performance as formal investigations continue–and as the actors
    begin testimony in front of both U.S. Senate and House Committees starting
    tomorrow–and we summarize some of this discussion below.
    It has been generally reported that the crew was preparing to temporarily abandon the
    well. It was also reported that HAL finished the cement job, that the cemented string
    passed integrity tests and that the final step was setting a cement plug in place to “cap




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    the well”. Prior to capping the well, the decision appears to have been made to
    displace the drilling mud with sea water.
    Either this “lightening” of the hydrostatic head, or some inadequacy in the cement job
    (including timing to set), are the two most widely presumed “causes” related to
    “allowing” the highly pressured gas to ascend the drilling column. This chain of events
    then being exacerbated by a failure of the BOP either due to a fault in the BOP or lack
    of “communication” from the rig.
    Who made the decision, or perhaps who had any advisory role in the decision, has to
    be established. It appears clear to us that lawyers will use every angle possible to
    secure payment for their clients. Which route has the greater chance of success will
    only be apparent once the investigation is complete.
    Further, we don’t know how that decision (or others through the drilling process)
    compared to standard drilling practice. In our conference call, the attorneys asserted
    that recommendations regarding standard or best practice could well be deemed as
    being authoritative (although not conclusive) unless there is dispute as to the
    appropriateness of the recommendations. And, they maintained, in the case of an
    authoritative recommendation, the courts would likely look favorably on such
    recommendation.

■   BOP designs and testing limitations. The product liability conversation in our
    conference call highlighted challenges CAM may face with respect to establishing that
    Deepwater Horizon BOP stack was adequately designed to handle emergency
    conditions. It is clear that elements of the BOP had been used to manage this and
    other wells in the BOPs life and frequent testing establishes basic operability. But the
    shearing “functionality” was not tested regularly. And as for warnings, we do not know
    the specifics in this case. We believe standard industry practice is to indicate the
    general “power” to shear and thus not be so specific as to say that the shear ram can
    or cannot shear through the tool joint versus the rest of a specific type of drill pipe.




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                 Exhibit 126: Potential Liability "Flow Diagram" -- A Summary of May 9 , 2010 Conference Call Take-aways




                                                                                                                           14 June 2010
                 Source: Company data, Credit Suisse estimates
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Integrated Oils: Macondo Oil Spill Liability, a More
Conservative Case (May 3th, 2010)
■   Strong results overshadowed by Deepwater Horizon: Since the end of Q1 reporting,
    Credit Suisse FY1 and FY2 earnings estimates for the Big Oils group have been raised
    by 3.5% and 2.3%. Our Big Oil Fights Back thesis suggests rising earnings and
    expanding free cashflow have not been priced into the shares. However, uncertainty
    about the Gulf of Mexico have overshadowed performance. The US GoM accounts for
    3.1% of the Super 7 2P reserves on average (range from 0.4% at lowest to 16.9% at
    highest).
■   While the cost could be as low as $1bn, the further BP shares fall, the more
    we've tried to blue sky potential the liabilities: Our initial estimate of $7bn included
    $3bn for clean up and $4bn for lost income claims (predominantly tourism and fishing).
    Today, we are laying out a higher potential for the fishing and tourism revenues that
    could become seen as a liability. Our $3bn clean up estimate is higher than the current
    $6M per day runrate for 90 days - the bulk of this difference relates to onshore costs.
    We release a higher estimate of claims primarily to test the value of BP shares at
    current levels.
■   We estimate Alabama’s Gulf Coast region to have generated $3.2bn pa in tourism
    revenues out of $9.3bn for the entire state of Alabama. Commercial fishing and sport
    fishing accounts for ~$1.15bn. In Louisiana, according to 2008 data, tourism spending
    was $9.3bn with saltwater commercial fishing accounting for additional revenues of
    $2.35bn (2006 data) and recreational fishing a further $0.76bn (2006 data). These are
    revenue figures. Assuming a 40% margin on 100% of revenues and a full 2 year
    disruption, the PV of this liability (including $3bn for clean up costs) could be $15.8bn.
■   Incorporating a more conservative case scenario and higher liability from our Blended
    TP for BP, we find 54% upside relative to an average of 25% for the group.
■   The resultant annual payment of ~$5.1bn, (represents 5% of BP’s pre-spill EV and
    accounts for BP’s 65% share and equal payments over 2 years) to affected
    communities would compare with our estimate of ~$8bn pa (average 2010 – 2011) of
    excess cashflow above BP's capex and dividend. Even in this more conservative
    scenario, actual payments would likely take longer, lowering the potential cash outflow
    burden.
■   While we are trying to help investors to blue sky worst case potential liabilities, we
    stress that this is still a very early estimate. The next few weeks will be critical. If BP
    can successfully cofferdam the leaks (first attempt in 2 weeks), if the BOP can be
    operated, or if the spill can be contained offshore, the damage may well be limited to
    the current level of $6M per day (less than $1bn).
■   Finally, we note the US Gulf of Mexico is a significant source of current non-OPEC
    production (1.7mbd) and accounts for 20% or circa 2.4MBD of 2017 growth projects.
    Higher oil prices in the event of GoM volume deferral would benefit onshore oilier
    E&P's and the renewable energy sector.




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Blended Target Prices
Exhibit 127: Blended Target Prices – Integrated Oils (Pre-Liability for BP)




Source: Company data, Credit Suisse estimates



Exhibit 128: Blended Target Prices – Integrated Oils (Post-Liability for BP)




Source: Company data, Credit Suisse estimates




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Exhibit 129: More conservative estimate of liability for Macondo well oil spill to reflect
higher potential claims from damaged parties




Source: Company data, Credit Suisse estimates




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US OFS: Macondo Well Tragedy Slams Services –
Earnings analyses for CAM, FTI, and OII (April 30th,
2010)
■   Strong stomachs required, but we find the sell-off in CAM and HAL overdone:
    HAL liability seems very unlikely as we describe below and we are buyers here. We
    think liability is also very unlikely for CAM, but we await a clearer sense of whether
    CAM had any recent interactions with the Blowout Preventer (BOP).
■   Theories abound; answers likely hard to find: why the well would “kick” during or
    after cementing in the casing and where responsibility may lie within services, if at all,
    is unclear. And we suspect the damage to equipment and perhaps the wellbore
    incurred in the explosion may render it nearly impossible to get answers.
■   Hard to see liability for CAM and HAL: for HAL, almost certain lack of contractual
    liability suggests no exposure barring a finding of gross negligence, which we imagine
    would be extremely difficult to establish (even if it were true, which we are not at all
    asserting). For CAM, we imagine warranty periods could only be relevant if CAM
    refurbished the BOP within the last year; and here too limited liabilities likely prevail.
    Similarly we imagine there is little reputational risk for either.
■   We note both CAM and HAL have umbrella liability: CAM specified$500MM; HAL
    isn’t saying, but we imagine coverage is greater than for CAM.
■   Pain in share prices has been all Macondo related; we wonder if that’s optimistic: A
    temporary ban on drilling and, more importantly, additional safety-related audits or
    approvals could impact deepwater development (economics). This adds some risk to
    Gulf of Mexico (GoM) exposure across OFS.
■   CAM: our 2010 estimates and $48 TP are unchanged: We continue to see EPS
    upside potential in 2010 and 1Q10 orders exceeded expectations, although we found
    order commentary, and thus the prospects for a dramatically better 2011, a little softer
    than expected.
■   FTI: paying respect to margin improvement; raising TP to $65: We raised 2010E
    EPS to $2.90 from $2.60 and 2011E to $3.15 from $2.90 all largely on higher subsea
    margins (and modestly higher subsea revenues in 2011). However, with share strength
    YTD, we struggle with valuation, even as we acknowledge operating strength.
■   OII: tweaking 2010E; raising TP to $68 to reflect growth potential: We raised
    2010E EPS to $3.45 from $3.25 and raised our TP to $68 from $53 overdue “catch up”
    on discount rate to reflect growth potential and more specifically stronger products
    (non-umbilicals) growth in 2011-2015.


Discussion
Macondo well update
The spill and efforts to control it
■ As of yesterday, the estimate for the amount leaking from the well was raised to 5,000
  barrels per day from 1,000 previously. And BP said there is a second breach in the
  marine riser just above the BOP. Skimmers had gathered 18K gallons of oily water as
  of yesterday afternoon and a test of controlled burning of the oil slick was deemed
  successful, but rough weather moving in to the GoM precluded further burns for the
  time being. Instead dispersants were being readied, with the intent to deploy them
  through coiled tubing, a method never before used in the GoM. BP has contracted
  three support/intervention vessels (each with two Remotely Operated Vehicles or
  ROVs): the Ocean Intervention III from OII; Boa Sub C from Aker and Skandi Neptune
  from Subsea 7.



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Efforts to actuate the BOP
■   ROVs from the intervention vessels have hit the access points that were designed to
    trigger the shutting of the BOP, but were unsuccessful. BP has also reportedly said that
■   Transocean workers on the rig tried to activate the BOP from the rig’s bridge before
    having to evacuate, but the BOP failed to close.
HAL had recently finished cementing the well
■   HAL has confirmed that it had 4 employees on the Deepwater Horizon rig performing
    cementing operations on the well. The employees were in their quarters (i.e. not on the
    deck floor) at the time of the incident. And we have heard independently, but not
    confirmed, that the cement job had been finished and that wellbore cleanup was under
    way.
■   The reason for the kick in the well is not known and although we understand there are
    circumstances in which the cement job can “pull” on the well, we cannot at all say that
    any such action contributed to creating the kick.
Why the BOP did not actuate still isn’t clear
■   A BOP is a set of valves designed to “catch” a kick or a blowout. We understand there
    are some elements that are automatic, which tend to be designed to close the valves in
    the event of a power outage, and others that need to be manually actuated. The shear
    ram portion of the BOP—which “shears” the pipe in the wellbore (e.g. the drill pipe) and
    completely seals the wellhead—appears not to have been actuated, for reasons that
    are unclear.
The potentially broader implications
■   Investor concerns to date have been very specific and targeted only at companies with
    perceived potential liability associated with the explosion of Transocean’s Deepwater
    Horizon rig and the subsequent oil spill. Yet as the spill grows and approaches shore
    (possibly as early as today), we wonder if broader concerns regarding activity in the
    GoM may settle in. The MMS is checking BOPs across the Gulf of MX (GoM), only a
    short term interruption for the region. But the Obama Administration has indicated it
    may at least may be contemplating a temporary ban on offshore drilling. And more
    generally additional safety-related audits or approvals could impact deepwater
    development (economics). These add some risk to GoM exposure across OFS. For
    diversified services GoM revenues are roughly 15% of total U.S. (although above
    average margin); for subsea trees, GoM comprises 18% of what was ordered in 2008
    and 2009; and clearly GoM-focused logistics companies and offshore construction
    companies have significant exposure.


Cameron International Corp. (CAM) – Q1 2010 Earnings
■ Fair Value of $48; but not quite ready to step in front of BOP overhang: We
  continue to see EPS upside potential in 2010 and 1Q10 orders exceeded expectations.
  We did find order commentary, and thus the prospects for a stronger 2011, a little
  softer than expected.
■   Q1 In Line: CAM reported operational Q1 2010 EPS of $0.51, in line with our $0.50
    and Street’s $0.51. Variances to our estimate included higher Drilling and Production
    margin (+$0.04, net of -$0.01 lower revenue) and higher Valves and Measurement
    margin (+$0.01), offset by lower Compression Systems revenue (-$0.02), higher
    corporate expense (-$0.02), and a higher share count (-$0.01). Operational results
    excluded $10.3 million (pre-tax), or $0.03 per share, for severance and acquisition
    integration costs.
■   Lowering Estimates: We maintained our 2010 EPS estimate of $2.35, but lowered our
    2011 estimate to $2.60 from $2.70 and our 2012 estimate to $3.15 from $3.20 mainly



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    due to lower Drilling and Production, partially offset by stronger Valves and
    Measurement.
■   Maintaining Rating and Target Price: Our $48 TP is DCF-based; we model FCF out
    to 2016, using a 4.5% terminal growth rate and 10% WACC.

FMC Technologies, Inc. (FTI) – Q1 2010 Earnings
■ FTI: paying respect to margin improvement; raising TP to $65 from $57: We are
  impressed with FTI’s operating efficiencies and, as we reflect in our higher estimates,
  are more comfortable modeling higher subsea EBIT margins going forward despite
  lingering concerns about competitive threat. Yet with share strength yesterday and
  YTD as a result of (1) defensive characteristics, (2) M&A enthusiasm and (3) order
  excitement, we continue to struggle to find value, even as we acknowledge operating
  strength.
■   1Q10 Ahead: FTI reported $0.80 versus our $0.60 and the Street’s $0.64 on record
    subsea margins (17.8%, +$0.22 to our EPS estimate), higher subsea revenue (+$0.02)
    and higher subsea systems margin (+$0.03) partially offset by higher corporate
    expense (-$0.06) and a higher tax rate (-$0.02).
■   Raising Estimates: We raised 2010E EPS to $2.90 from $2.60 and 2011E to $3.15
    from $2.90 largely on higher subsea margins (and modestly higher subsea revenues in
    2011).
■   Shares have run ahead of fair value, in our view: Our $65 TP is DCFbased; we
    model FCF out to 2016, using a 5.5% terminal growth rate and 10% WACC.


Oceaneering Intl, Inc. (OII) – Q1 2010 Earnings
■ Raising TP to $68 from $53 to reflect growth potential; we find shares fairly valued:
  Salvage operations for the Macondo well helps offset a damaged vessel in the GoM,
  and we are for now giving credence to management’s confidence in a pickup in
  offshore construction activity in 2010. In our higher price target we have primarily given
  more credit to Subsea Products (away from umbilicals) and higher ROV margins. But
  doubts remain regarding offshore construction in 2010; and we are concerned about
  the eventual margin pressure potential in ROVs from competition.
■   Q1 EPS Ahead: OII reported Q1 2010 operational EPS of $0.77, ahead of our $0.75
    and the Street's $0.74. Variances to our estimate included higher ROV (-$0.03 revenue
    miss on utilization, offset by +$0.04 margin benefit) and Subsea projects (+$0.04
    revenue, +$0.01 margin) contribution, lower Inspection margin (-$0.01), and higher
    Advanced Tech margin (+$0.02), partially offset by higher Corporate and other
    expense (-$0.05).
■   Raising 2010, Tweaking down 2011-2012: We are raising our 2010 EPS estimate to
    $3.45 from $3.35 mainly due to improved ROV margins. We lowered our 2011 and
    2012 estimates by $0.05 on slower Subsea Product growth and lower Subsea Project
    margins.
■   Raising Target Price, Maintain Neutral: We raised our target price to $68 from $53
    as our new assumptions flow through our DCF-based valuation (we model FCF out to
    2016, discounted at a 10% WACC and assuming a 4.5% terminal growth rate.




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Integrated Oils: BP (BP.L) – Strong 1Q10 results.
Momentum pick up. (April 27th, 2010)
■   1Q10 results confirm operational leverage potential: BP reported clean EPADR of
    $1.81 versus consensus of $1.53. This is a 20% beat at the net income line, driven by
    strong operating performance in both E&P and R&M, where lower costs combined with
    improving macro conditions.
■   Investment Case: Although the strong volume growth of 2009 will not be repeated (we
    forecast volumes to fall 0.2% YoY in 2010) we argue that BP will start to see rising
    returns and cash flows as they move into a more benign phase of the investment cycle
    over the next 3 years. The upstream is moving to higher frequency - a total of 42
    material project start-ups by 2015 - and on our estimates, higher IRR projects, as many
    of the new start-ups are tie-ins to existing hubs abound the company’s core positions in
    the Gulf of Mexico and Angola in particular
■   Earnings momentum picking up: We have upgraded our 2010 EPS estimates by 7%
    on the back of our mark-to-market of 1Q results. Forecasts for subsequent years are
    barely changed. We think upside momentum potential remains – both from a macro
    environment which remains above the current consensus forecast, and from
    restructuring gains. BP’s downstream remains a key source of potential future
    upgrades, driven by a normalisation of operating practices in the US refining business
    after two years of material constraints. Equally, trading profits, a material part of the
    earnings mix historically, have also been subdued, but will return as volatility
    normalises.
■   Valuation: At under 9x 2010E P/E, BP shares trade at a reasonable discount to the
    sector, and for those concerned about the understatement of depreciation across the
    industry, this discount translates into a sectorleading 9% free cash flow yield at $80 oil
    in 2010E, with a distribution of most of this to shareholders, in the form of a 5.7%
    dividend yield.


BP 1Q10 Results
Conference call update on Macondo
■   BP took the opportunity of the conference call to update the market on the latest
    developments from the recent blow out, fire, and loss of life at the Macondo field in the
    Gulf of Mexico. Concerns over the ultimate ecological, economic, and financial impact
    of this accident have clearly impeded the BP share price despite an unimpeachably
    strong set of 1Q results.
■   At present, uncertainty prevails over the cause of the accident, the timeline for shutting
    the flow of oil from the sub-surface riser, the ultimate extent of the oil dispersal and the
    cost of the remediation effort. This uncertainty, more than the actual potential financial
    impact, appears to be the main cause of near term share price weakness.
■   Our base case remains that the company will be able to stop the flow within 2 weeks in
    a best case scenario, and 3 months in a worst case scenario (time to drill second
    intersect well) – implying a spill of 20kbpd-100kbpd. Methods to clean up the slick have
    so far seen skimming and dispersal efforts – with a light slick still some 30 miles from
    shore. Arguably the incremental nature of the oil spill is easier to control than the
    immediate dumping of 125-250kbbls into the sea witnessed with high profile tanker
    spills seen by the industry.
■   While the company is at pains to explain that efforts right now focus on the joint
    response to the accident, it is also noted that contractually, responsibility for the
    operation of the rig lies with the drilling contractor, while BP’s responsibilities begin with
    the efforts to regain control of the well, and then with the environmental clean-up effort.



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    At present, the company does not see any reason to adjust its guidance on ongoing
    drilling activity or production guidance for 2010, and potentially a degree of flexibility in
    the drilling portfolio, new rigs acquired with the Devon Brazil asset transaction, or even
    new opportunities within a slightly looser deepwater drilling market, mean that this
    current guidance may not necessarily change.

Results
■ BP reported clean EPADR of $1.81 versus consensus of $1.53 and CS at $1.54. This
  was a 20% beat at the net income line, driven by strong operating performance in both
  key divisions.
■   $0.23/ADR of the beat came in the E&P division, where lower operating costs (total
    group cash costs down 6%YoY) combined with a strengthening macro environment to
    deliver strong operational leverage.
■   $0.02/ADR of the beat came in R&M where a stabilising macro environment
    neutralised recent losses in the US business.
■   The remainder of the beat was driven by a positive consolidation adjustment ($208m)
    vs. expectations of flat for the quarter – driven by a reduction in underlying inventories.
■   Non operating items and fair value accounting effects had a negative impact of $49m
    after tax. The tax rate of 34% was in line with company guidance.
■   In terms of the cash generation profile, OCF of $9,633m before working capital moves
    was 9% ahead of our forecast, reflecting a strong conversion of earnings into cash flow.
    The result was up 47% YoY.
■   The quarterly dividend was in line with expectations at $0.14/share. However, capital
    expenditures were somewhat lower than anticipated for the quarter, at $3,600m
    although full year spending guidance of $20,000m remains unchanged. As a result of
    this gearing (ND/CE) fell to 19%, materially lower than in the previous quarter (20.6%).

Divisional highlights:

Clean E&P $8,188m, vs consensus $7,118m, (15% beat).

■   Production of 4,010kbd was flat y/y and 1% lower q/q. Guidance of slightly lower YoY
    volumes in 2010 remains unchanged in view of turnaround activity – with up to
    100kboed expected to be out in the second quarter in GoM (Thunder Horse), and
    North Sea. The key positive driver of the quarter looks to be that despite in-line
    volumes, earnings were stronger on lower unit production costs (-3% YoY).
    Realisations were slightly stronger than forecast, notably in US and RoW gas.


Clean R&M $789m vs consensus $571m (38% beat).

■   A stronger performance from R&M comes despite ongoing weak conditions for supply
    and trading – where low volatility continues to depress earnings. Refining saw
    improved operational availability, but the US business was still loss-making – albeit
    close to breakeven finally. Refining margins were $3.08/bbl vs $1.49 in 4Q, with BP’s
    realised refining margins outperforming the global indicator margin as the light-heavy
    differential widened in the quarter, benefitting BP’s coking-strong refining portfolio.
    Petrochemicals were also strong due to restocking effects (volumes up 40% YoY) – an
    effect which will dissipate somewhat in the second quarter. BP has seen some margin
    improvement into the second quarter, although it expects the enduring effect to be
    fairly muted in the current supply-demand picture.

Clean OB&C posted a loss of $210m vs consensus of -$467m



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■   The beat came from stronger margins in Alternative Energy, higher freight rates and
    positive FX effects, while operating costs declined sequentially (albeit from a high
    seasonal base in 4Q). There is no change to company guidance of a $400m charge
    per quarter. There was a positive $208m consolidation adjustment vs consensus of -
    $23m due to the reversal of high inventories at end-2009.




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US OFS: Transocean Inc. (RIG) – What’s the
Financial Impact on the Horizon? (April 26th, 2010)
■   Deepwater Horizon accident. Preliminary reports suggest that a well-control incident
    (e.g., a blowout) caused a fire aboard the Deepwater Horizon ultra-deepwater semi,
    which led to the sinking of the rig on April 22. The rig had completed the drilling of an
    exploration well for BP and its partners (BP 65%, Anadarko 25%, and Mitsui 10%
    working interests) at the Macondo prospect on Mississippi Canyon Block 252 in the
    U.S. GOM (Exhibit 131). At the time of the incident, the crew was apparently running
    production casing. It is unclear why the pressure build-up occurred after the well had
    been drilled.
■   Tragic loss of human life is by far the biggest impact of the incident. At the time of
    the incident, there were 126 workers on the rig, including 79 employees from
    Transocean, 6 from BP, and 41 from other service providers. It appears that 11 people
    were killed from the explosion, including 9 Transocean employees and 2 employees
    from Smith International’s MI Swaco unit. In addition, 17 crew members were injured,
    including 7 critically.
■   Liability from the incident could top $1.25 billion. According to insurance
    underwriting publications, the total liability for the Deepwater Horizon incident could top
    $1.25 billion, including the apparent loss of the rig, well control and redrill costs,
    pollution clean-up, and crew liability costs. Preliminary reports suggest Transocean’s
    liability could approach $950 MM, but our analysis indicates that the company’s robust
    insurance policies should help mitigate the financial impact of the tragedy. That said, it
    is impossible to gauge the short-term and long-term reputational impact to Transocean
    as well as its relationship with BP, which was RIG’s largest customer in 2009
    accounting for 12% of operating revenues.
■   How is liability shared amongst the operating group? Under typical industry drilling
    contracts, RIG is responsible for the drilling rig, salvage costs of the rig, and safety
    protocols, including the maintenance of lifesaving equipment and evacuation
    procedures. Unless there is gross negligence, the operating group is responsible for
    environmental clean-up costs associated with the release of hydrocarbons and well-
    control/redrill liability associated with blowouts.
■   Transocean appears to be adequately insured. Our analysis of public filings
    suggests RIG has robust insurance in place that mitigates the bulk of its exposure to
    the incident (see Exhibit 130), including $560 MM of insurance on the Deepwater
    Horizon semi by a syndicate of insurers. RIG has a $125 MM deductible subject to a
    $250 MM aggregate loss limit on hull and machinery, but its retention declines to $1.5
    MM or less in situations where the rig is deemed a total constructive loss, which is the
    most likely scenario given the sinking of the rig. RIG also has personal injury and
    collision liability insurance subject to a $10 MM deductible plus insurance for third-party
    non-crew claims subject to a $5 MM deductible. Together, the personal injury, collision,
    and third-party non-crew claims are subject to a $50 MM aggregate deductible on top
    of the per occurrence deductible, meaning RIG would be on the hook for the first $65
    MM of these types of claims. RIG also has $950 MM of third-party liability insurance,
    but it is unclear what its deductible is under this third-party liability policy.




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Exhibit 130: Potential Claim for Transocean Under its Physical Damage Insurance
Program
in millions of US Dollars
Claim                                                                                    Total
Hull and Machinery Claim                                                                 $560
Sue and labor provision (25% of $560 MM total)                                            140
Removal of wreck (25% of $560 MM total)                                                   140
Contingent operators' extra expense                                                       100
Care of custody and control                                                                 5
Total                                                                                    $945
Source: The Insurance Insider (4/26/2010), Credit Suisse

■   Impact to earnings and replacement cost estimate. The Deepwater Horizon was
    operating under a 5-year contract with BP at a dayrate of approximately $497K. On an
    annual basis, we estimate that the Deepwater Horizon accounted for $0.34 per share
    in annual EPS, or just under 4% of our published EPS estimate for 2011 as RIG did not
    possess loss of hire insurance on the Horizon. We estimate the replacement cost value
    of the Deepwater Horizon to be around $615 MM, or 1.3% of our $47.6 billion total
    replacement cost estimate for the fleet. We are maintaining our estimates until the
    company’s Q110 results conference call on Thursday, May 6.
■   BP appears to be self-insured. Analysis of BP’s 2009 20-F filing suggests that BP is
    largely self-insured through captives, while Anadarko and Mitsui appear to have
    coverage that limit their liability. Anecdotal evidence suggests that APC has $250 MM
    of well-control and clean up coverage, which scales down to $50 MM based on its 25%
    share in the joint venture. In addition, APC has general liability insurance. Mitsui has
    $300 MM of well-control coverage that scales down to 10%, or $30 MM, for its share of
    joint venture costs. In addition, Mitsui has $150 MM of liability insurance to protect
    against clean-up costs.
■   Uncertainty around the Blow Out Preventer (BOP). With the BOP failing to prevent
    the apparent explosion, we discuss some of the commercial conditions surrounding
    BOPs and supplier Cameron International (CAM). We imagine it is unlikely that CAM
    faces contractually-based liability. Although we do not know the specific Terms and
    Conditions for this BOP, it is our understanding that in general the warranty period lasts
    one year (this BOP was delivered in 2001). Initial approval includes extensive testing of
    the BOP both in the factory (the manufacturers have testing bays in which they can
    simulate hydrostatic and rated in-well bore pressures) and once installed on the sea
    bed. More generally, we believe there is at least some risk to the service industry and
    perhaps equipment providers in particular, as a result of this accident and the oil spill.
    We wonder if safety concerns/approvals at the MMS for high pressure reservoirs are
    scrutinized or politicized further, which could add time to development programs and
    thus slow orders. We note high pressure reservoirs include the deep shelf as well as
    deepwater fields.




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                                                      14 June 2010



Exhibit 131: Drilling Location of Deepwater Horizon




Source: SkyTruth, Google




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Companies Mentioned (Price as of 11 Jun 10)
Anadarko Petroleum Corp. (APC, $42.00, OUTPERFORM [V], TP $71.00)
Apache Corp. (APA, $95.34, RESTRICTED [V])
Archer Daniels Midland Inc. (ADM, $25.64, NEUTRAL, TP $30.00)
ATP Oil & Gas Corp. (ATPG, $9.47)
Atwood Oceanics, Inc. (ATW, $26.53, NEUTRAL [V], TP $29.00)
Baker Hughes Inc. (BHI, $41.94, NEUTRAL [V], TP $58.00)
BP (BP.N, $30.67, OUTPERFORM, TP $49.04, MARKET WEIGHT)
BP (BP.L, 355.45 p, OUTPERFORM, TP 560.00 p, MARKET WEIGHT)
Brigham Exploration Co. (BEXP, $17.97, OUTPERFORM [V], TP $22.00)
Bristow Group Inc. (BRS, $32.16, NEUTRAL [V], TP $41.00)
Cameron International Corp. (CAM, $35.79, NEUTRAL [V], TP $48.00)
Chevron Corp. (CVX, $74.18, OUTPERFORM, TP $93.00)
Clean Harbors (CLH, $67.76, OUTPERFORM, TP $74.00)
Cobalt International Energy (CIE, $7.31, RESTRICTED [V])
Complete Production Services (CPX, $14.12, NEUTRAL [V], TP $19.00)
ConocoPhillips (COP, $52.80, OUTPERFORM, TP $68.00)
Diamond Offshore (DO, $60.25, UNDERPERFORM [V], TP $57.00)
Enbridge Inc. (ENB.TO, C$49.23, NEUTRAL, TP C$50.00)
ENI (E.N, $38.07, UNDERPERFORM, TP $46.00, MARKET WEIGHT)
Ensco Plc. (ESV, $38.28, NEUTRAL [V], TP $40.00)
Exterran Holdings (EXH, $26.34, NEUTRAL [V], TP $30.00)
ExxonMobil Corporation (XOM, $61.37, NEUTRAL, TP $75.00)
FMC Technologies, Inc. (FTI, $52.75, NEUTRAL [V], TP $65.00)
Global Geophysical Services, Inc. (GGS, $8.49, OUTPERFORM [V], TP $13.00)
Global Industries, Ltd. (GLBL, $5.30, NEUTRAL [V], TP $7.00)
Halliburton (HAL, $24.02, OUTPERFORM [V], TP $42.00)
Helmerich & Payne, Inc. (HP, $41.39, NEUTRAL [V], TP $43.00)
Hercules Offshore (HERO, $2.82, OUTPERFORM [V], TP $5.00)
Hess Corporation (HES, $53.67, NEUTRAL [V], TP $71.00)
Marathon Oil Corp (MRO, $32.56, OUTPERFORM, TP $41.00)
Mcmoran Exploration Co (MMR, $11.00)
Murphy Oil Corp. (MUR, $54.56, UNDERPERFORM [V], TP $63.00)
Nabors Industries, Ltd. (NBR, $20.81, OUTPERFORM [V], TP $30.00)
National Oilwell Varco (NOV, $36.85, OUTPERFORM [V], TP $49.00)
Noble Corporation (NE, $30.00, OUTPERFORM [V], TP $40.00)
Noble Energy (NBL, $63.68, OUTPERFORM [V], TP $91.00)
Oceaneering Intl, Inc. (OII, $45.54, NEUTRAL [V], TP $68.00)
Oil States International (OIS, $42.05, NEUTRAL [V], TP $45.00)
Patterson-UTI Energy, Inc. (PTEN, $14.48, UNDERPERFORM [V], TP $17.00)
PetroHawk Energy Corp. (HK, $21.05, OUTPERFORM [V], TP $30.00)
Plains Exploration & Production Co. (PXP, $23.49, NEUTRAL [V], TP $29.00)
Pride International Inc. (PDE, $24.09, OUTPERFORM [V], TP $33.00)
Range Resources (RRC, $49.49, OUTPERFORM [V], TP $63.00)
Rowan Companies (RDC, $23.60, UNDERPERFORM [V], TP $24.00)
Royal Dutch Shell PLC (ADR) (RDSa.N, $52.38, NEUTRAL, TP $59.83, MARKET WEIGHT)
Schlumberger (SLB, $58.66, OUTPERFORM [V], TP $86.00)
Shaw Group, Inc. (SHAW, $34.68, NEUTRAL [V], TP $35.00)
Smith International, Inc. (SII, $39.68, NEUTRAL [V], TP $33.00)
Smithfield Foods (SFD, $17.05, NEUTRAL [V], TP $21.00)
Stone Energy (SGY, $13.50)
Tidewater (TDW, $41.08, NEUTRAL [V], TP $47.00)
Total (TOTF.PA, Eu39.59, NEUTRAL, TP Eu40.00, MARKET WEIGHT)
Transocean Inc. (RIG, $44.78, NEUTRAL [V], TP $63.00)
Tyson Foods (TSN, $18.57, NEUTRAL [V], TP $21.00)
URS Corporation (URS, $42.05, NEUTRAL, TP $51.00)
Vestas (VWS.CO, DKr298.00, UNDERPERFORM [V], TP DKr245.00, MARKET WEIGHT)
W&T Offshore Inc. (WTI, $10.11)
Weatherford International, Inc. (WFT, $13.79, OUTPERFORM [V], TP $20.00)
Whiting Petroleum Corp. (WLL, $88.31, OUTPERFORM [V], TP $104.00)




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                                                                Disclosure Appendix
Important Global Disclosures
The analysts identified in this report each certify, with respect to the companies or securities that the individual analyzes, that (1) the views
expressed in this report accurately reflect his or her personal views about all of the subject companies and securities and (2) no part of his or her
compensation was, is or will be directly or indirectly related to the specific recommendations or views expressed in this report.
The analyst(s) responsible for preparing this research report received compensation that is based upon various factors including Credit Suisse's total
revenues, a portion of which are generated by Credit Suisse's investment banking activities.
Analysts’ stock ratings are defined as follows:
Outperform (O): The stock’s total return is expected to outperform the relevant benchmark* by at least 10-15% (or more, depending on perceived
risk) over the next 12 months.
Neutral (N): The stock’s total return is expected to be in line with the relevant benchmark* (range of ±10-15%) over the next 12 months.
Underperform (U): The stock’s total return is expected to underperform the relevant benchmark* by 10-15% or more over the next 12 months.
*Relevant benchmark by region: As of 29th May 2009, Australia, New Zealand, U.S. and Canadian ratings are based on (1) a stock’s absolute total
return potential to its current share price and (2) the relative attractiveness of a stock’s total return potential within an analyst’s coverage universe**,
with Outperforms representing the most attractive, Neutrals the less attractive, and Underperforms the least attractive investment opportunities.
Some U.S. and Canadian ratings may fall outside the absolute total return ranges defined above, depending on market conditions and industry
factors. For Latin American, Japanese, and non-Japan Asia stocks, ratings are based on a stock’s total return relative to the average total return of
the relevant country or regional benchmark; for European stocks, ratings are based on a stock’s total return relative to the analyst's coverage
universe**. For Australian and New Zealand stocks a 22% and a 12% threshold replace the 10-15% level in the Outperform and Underperform stock
rating definitions, respectively, subject to analysts’ perceived risk. The 22% and 12% thresholds replace the +10-15% and -10-15% levels in the
Neutral stock rating definition, respectively, subject to analysts’ perceived risk.
**An analyst's coverage universe consists of all companies covered by the analyst within the relevant sector.
Restricted (R): In certain circumstances, Credit Suisse policy and/or applicable law and regulations preclude certain types of communications,
including an investment recommendation, during the course of Credit Suisse's engagement in an investment banking transaction and in certain other
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Volatility Indicator [V]: A stock is defined as volatile if the stock price has moved up or down by 20% or more in a month in at least 8 of the past 24
months or the analyst expects significant volatility going forward.
Analysts’ coverage universe weightings are distinct from analysts’ stock ratings and are based on the expected
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Overweight: Industry expected to outperform the relevant broad market benchmark over the next 12 months.
Market Weight: Industry expected to perform in-line with the relevant broad market benchmark over the next 12 months.
Underweight: Industry expected to underperform the relevant broad market benchmark over the next 12 months.
*An analyst’s coverage universe consists of all companies covered by the analyst within the relevant sector.
**The broad market benchmark is based on the expected return of the local market index (e.g., the S&P 500 in the U.S.) over the next 12 months.

Credit Suisse’s distribution of stock ratings (and banking clients) is:
                                                 Global Ratings Distribution
                        Outperform/Buy*        45%      (63% banking clients)
                        Neutral/Hold*          41%      (60% banking clients)
                        Underperform/Sell*     13%      (55% banking clients)
                        Restricted              2%
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The following disclosed European company/ies have estimates that comply with IFRS: BP.L, XOM, TOTF.PA.
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Disclaimers continue on next page.




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                                                                                                                                                                             Americas
                                                                                                                                                                      Equity Research




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