credit suisse - oil & gas primer

OIL & GAS PRIMER September 2011The Credit Suisse Energy Team

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/ research disclosures 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.

Credit Suisse Global Energy Team

Source: Credit Suisse

United States EuropeIntegrated Oils & Refiners Integrated Oils & Refiners Ed Westlake (New York)) +1 212-325 6751 [email protected] Kim Fustier (London) +44 20 7883 0384 [email protected] Rakesh Advani (New York) +1 212 538 5084 [email protected] Thomas Adolff (London) +44 20 7888 9114 [email protected] & Production Exploration & Production Arun Jayaram (New York) +1 212 538 8428 [email protected] Tao Ly (London) +44 20 7888 1778 [email protected] Mark Lear (New York) +1 212 538 0239 [email protected] Ritesh Gaggar (London) +44 20 7888 0277 [email protected] David Lee (New York) +1 212 325 6693 [email protected] Arpit Harbhajanka (London) +44 20 7888 0151 [email protected] Services Oil Services Brad Handler (New York) +1 212 325 0772 [email protected] Tao Ly (London) +44 20 7888 1778 [email protected] Eduardo Royes (New York) +1 212 538 7446 [email protected] Arpit Harbhajanka (London) +44 20 7888 0151 [email protected] Jonathan Sisto (New York) +1 212-325-1292 [email protected] UtilitiesMLPs Vincent Gilles (London) +44 20 7888 1926 [email protected] Yves Siegel (New York) +1 212 325 8462 [email protected] Mark Freshney (London) +44 20 7888 0887 [email protected] Brett Reilly (New York) +1 212 538 3749 [email protected] Stephen Deeley (London) +44 20 7883 9534 [email protected] Michel Debs (London) +44 20 7883 9952 [email protected] Dan Eggers (New York) +1 212 538 8430 [email protected] Mulu Sun (London) +44 20 7888 0269 [email protected] Kevin Cole (New York) +1 212 538 8422 [email protected] Zoltan Fekete (London) +44 20 7888 0285 [email protected] Matt Davis (New York) +1 212 325 2573 [email protected] Specialist Sales Katie Chapman (New York) +1 212 325 1261 [email protected] Jason Turner (London) +44 20 7888 1395 [email protected] Energy Mark Whitfeld (London) +44 20 7888 8038 [email protected] Satya Kumar (San Francisco) +1 415 249 7928 [email protected] Ed Westlake (New York)) +1 212-325 6751 [email protected] Patrick Jobin (New York) +1 212 325 0843 [email protected] Latin AmericaSpecialist Sales Oil & Gas Tom Marchetti (New York) +1 212 325 0667 [email protected] Emerson Leite (Sao Paulo) +55 11 3841 6290 [email protected] Charlie Balancia (New York) +1 212-325 6314 [email protected] Utilities

Vinicius Canheu (Sao Paulo) +55 11 3841 6310 [email protected], Agribusiness and Transportation

Canada Luiz Campos (Sao Paulo) +55 11 3841 6312 [email protected] Brian Dutton (Toronto) +1 416 352 4596 [email protected] Andrew Kuske (Toronto) +1 416 352 4561 [email protected] Courtney Morris (Toronto) +1 416 352 4595 [email protected] Australia Paul Tan +1 416 352 4593 [email protected] Sandra McCullagh (Melbourne) +61 2 8205 4729 [email protected] Jason Frew (Calgary) +1 403 476 6022 [email protected] Nik Burns (Melbourne) +61 3 9280 1641 [email protected] Terence Chung (Calgary) +1 403 476 6024 [email protected] Ben Combes (Melbourne) +61 3 9280 1669 [email protected] David Phung (Calgary) +1 403 476 6023 [email protected]

Asia-PacificRussia/Emerging Europe David Hewitt (Singapore) +65 6212 3064 [email protected] & Gas Horace Tse (Hong Kong) +852 2101 7379 [email protected] Mark Henderson (London) +44 20 7883 6901 [email protected] Edwin Pang (Hong Kong) +852 2101 6406 [email protected] Andrey Ovchinnikov (Moscow) +7 495 967 8360 [email protected] Yang Song (Hong Kong +852 2101 6550 [email protected] Trina Chen (Hong Kong) +852 2101 7031 [email protected] Anton Fedotov (Moscow) +7 495 967 8362 [email protected] Sanjay Mookim (Mumbai) +91 22 6777 3806 [email protected]

Yuji Nishiyama (Tokyo) +81 3 4550 7374 [email protected] Siriporn Sothikul (Bangkok) +66 2 614 6217 [email protected] Poom Suvarnatemee (Bangkok) 66 2 614 6210 paworamon.suvarnatemee@credit-suisse. A-Hyung Cho (Seoul) +82 2 3707 3735 [email protected] Annuar Aziz Kuala Lumpur) +603 2723 2085 [email protected] Sidney Yeh (Taipei) +8862 2715 6368 [email protected]

Johannesburg

MoscowLondon

New York

Toronto

Sao Paulo

Hong Kong

SeoulTokyo

Call us anywhere: we can help you

Credit Suisse Global Energy Team

Kuala Lumpur

Sydney

BangkokSingapore

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Crude OilCrude Oil Overview 6Crude Oil Supply 12International Offshore Exploration 19 Crude Oil Demand 27Global Oil Markets 32

Natural GasNatural Gas Overview 39

North American Natural Gas 45Shale Gas in Focus 57Liquefied Natural Gas (LNG) 67

The UpstreamThe Upstream Process 83

Oil and Gas Reserves 99

The MidstreamNatural Gas 107Crude Oil/Refined Products 111

Oilfield Services, Equipment and DrillingProducts and Services 116

Company Specific Details 136

The DownstreamRefining 148

Refinery Operations 161Oil Product Marketing 171

Table of contents

Investing in Big Oil 176

Outlook for Big Oil 185

Investing in E&P 190

Investing in OFS 195

Investing in Refining 205

Outlook for Refining 215

Investing in MLPs 219

Industry Overview Basics of Energy Investing

CRUDE OIL

Crude Oil Overview

What Is Oil and Natural Gas?Oil and natural gas (or hydrocarbons) are composed of chains of linked hydrogen and carbon atoms.

Plant and animal remains were covered by layers of sediment (particles of rock and mineral) and over millions of years of extreme pressure and temperatures these particles were reduced to liquid hydrocarbons (oil) or gaseous hydrocarbons (natural gas).

Under geologic pressure, oil migrates from its “source rock” into rocks with larger spaces or pores “reservoir rock.” Limestone and sandstone have with large porosity and are two common types of “reservoir rock.” Oil is held in these reservoirs by impervious rock structures above called caps or traps.

Source: Earth science Australia

Crude Oil Composition

Crude oil ranges from almost clear water-like fluids to black viscous semi-solids.Crude oil can be categorized into various API degrees of gravity. The higher the API gravity, the lighter the crude. Crude oils with higher API gravity yield greater proportions of lighter petroleum products like gasoline.

Arab LightIranian HeavyBasrah Light

Fateh

ANS

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Brent

Bonny LightCabindaBonny Medium

Arab Heavy Arab Medium

Maya

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Cold Lake

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Crude oils with higher than average sulfur content are known as “sour.” Those with low sulfur levels are called “sweet.”The majority of global reserves are light/medium and slightly sour.

Source: DOE

Global Oil ReservesS

ourc

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The majority of the world’s current proved oil reserves are in OPEC countries.The BP Statistical Energy Review states that 956 billion barrels or 76% of the world’s proved reserves are held by OPEC. 754 billion of these are in the Middle East.The remaining 302 billion barrels or 24% of the world’s proved reserves are in non-OPEC regions. The former Soviet Union holds 42% of non-OPEC proved reserves.Additionally, the Canadian oil sands contain 150.7 billion barrels of proved reserves.

What is OPEC?

The Organization of the Petroleum Exporting Countries (OPEC) is a permanent, intergovernmental organization, created in 1960 by Iran, Iraq, Kuwait, Saudi Arabia, and Venezuela.

The five Founding Members were joined by Qatar (1961); Indonesia (1962, left in 2008); Libya (1962); United Arab Emirates (1967); Algeria (1969); Nigeria (1971); Ecuador (1973 suspended membership from 1992-2007); Angola (2007), and Gabon (1975, left in 1994).

OPEC’s stated objective is “to coordinate and unify petroleum policies among Member Countries, in order to secure fair and stable prices for petroleum producers; an efficient, economic and regular supply of petroleum to consuming nations; and a fair return on capital to those investing in the industry.”

OPEC’s members in effect attempt to raise the clearing price of crude oil above its “natural” level by withholding relatively cheap reserves from the market.

OPEC sets production quotas which individual members adhere to with varying degrees of success (or “compliance”).

World Oil Production

The world’s oil production profile is different from its reserve distribution

Declining production of aging fields is an important theme

The Middle East, North America, and Europe/Eurasia rank as the top three producing regions.

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Crude Oil Supply

Global Oil Supply

The characteristics of producing basins vary substantially around the world, including differences in the costs of finding, development and production.

The United States is the world’s most mature producing region with correspondingly low per well productivity and higher extraction costs.

The Middle East is the most productive region with the largest remaining undeveloped resources.

Russia is the world’s largest oil producer and contains two highly mature provinces: Western Siberia and Volga/Urals.

West Africa is a large source of production with future growth from the offshore.

Brazil looks like a huge new resource opportunity with the development of the pre-salt play in the offshore Santos Basin.

Frontier areas: Arctic, Greenland, Eastern Siberia, Antarctic, even deeper Offshore

Global Production Split: OPEC and Non-OPEC

OPEC accounts for roughly 40% of global oil supply, a sharp increase from the trough of 1985, but still lower than its historical level of 55%+ pre-1973/74.

Non-OPEC (ex-Former Soviet Union or FSU) production grew rapidly in the 1960s, 1970s/80s and the 1990s. However, non-OPEC supply growth has slowed in recent years.

Non-OPEC’s restricted access to new reserves, combined with higher decline rates, are the reasons.

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OPEC Oil Production*

* Assumes no inventory change: 2009 - 2012

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OPEC Supply [LHS] Market Share [RHS]

OPEC’s Spare Capacity: a Key Measure

Most of the time OPEC withholds existing supply from the market, creating spare capacity’ i.e., oil which could be produced, but is offline.

Anticipated levels of future spare capacity have important effects on crude prices generating more or less fear about supply (see markets and pricing section).

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Watching OPEC Capacity Additions

OPEC’s current policy appears to be to add new capacity only in line with expected increases in demand: “investing behind the demand curve.”

OPEC capacity additions between 2011-2012 are expected to be modest.

OPEC Net Capacity Additions

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Algeria Angola Ecuador Iran Iraq KuwaitLibya Nigeria Qatar Saudi Arabia UAE Venezuela

Iraq: Significant potential, But Infrastructure a Challenge

Could change perception of long-term supply.

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% World reserves % World production

Iraqi oil production over time – rise and fall Iraq – 9% of world reserves, 3% of world production

Source for top charts: IEA, industry data, Credit Suisse estimates

Iraqi Civilian Deaths Jan 2006 – Aug 2009 Oil projects awarded and growth

Source: Iraq Oil Forum

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Iran/Iraq warGulf war

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Impliedpotential

Reserves (BB)Initial Rate (MMB/d)

Cost Recovery Floor (MMB/d)

Targeted Plateau Rate (MMB/d)

1st round awardsRumaila 17.77 1.05 1.155 2.85Zubair 4.08 0.195 0.2145 1.125West Qurna Phase-1 8.58 0.26 0.286 2.325Sub-total 30.43 1.51 1.66 6.30

2nd round awardsMajnoon 12.58 0.046 0.175 1.800West Qurna Phase-2 12.88 0.000 0.120 1.800Halfaya 4.10 0.003 0.070 0.535Garraf 0.86 0.000 0.035 0.230Badra 0.11 0.000 0.015 0.170Qaiyarah 0.81 0.000 0.030 0.120Najmah 0.86 0.000 0.020 0.110Sub-total 32.19 0.05 0.465 4.765

Total 62.62 1.55 11.07

Source: Department of Defense

Onshore Growth Accelerating; We Need Offshore Too

Non-OPEC supply expected to be lacklustre through 2014 even with onshore growth in the US

A surge in deepwater projects helps lift Non-OPEC supply beyond 2014

US Onshore Supply Growth and Infrastructure

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Deepwater Hockey Stick

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International Offshore Exploration Success Improving

Brazil is Still the Largest Hot SpotS

ource: Petrobras

BM-S-22

Focus area has been Santos Basin (Tupi Cluster)

Blocks BMS-8, 9, 21, 22 (Sugar Loaf) area, together with BMS-11 (Tupi) and BMS-24 (Jupiter)

(1) Teak could potentially be larger than the market expects. The third and fourth appraisal wells could create a standalone development

(2) The left chart shows Tullow presentation of Teak in August. The Right shows KOS view. Appraisal will determine how large Teak truly is.

(3) The are large fans underneath the giant Tweneboa Discovery that have yet to be tested

(4) Cedrela will test the Cenomanian fairway in which HES has enjoyed success

(5) Other targets in 2012 include Wawa, Wassa, Sapele in Deepwater Tano Block and new Albian prospects are being worked up.

Ghana: Could Be Larger Than We Currently Think

French Guiana/Suriname – Zaedyus Game Changer

Source: APC, TLW

(1) Tullow believes Zaedyus discovery could be 700mmboe, with 5-6 more similar prospects in the near vicinity.

(2) Tullow believe the fan structure is larger than the entire Tano basin in Ghana

(3) Matamata is an additional large structure in the West of this block

(4) Further drilling activity in Block 47, Georgetown offshore Suriname

1st Successful Wildcat in Guyana Basin

Source: APC, TLW

Africa : More Late Cretaceous

Testing Liberia, Sierra Leone, Cote D’Ivoire (APC)

Large multi-hundred million barrel prospects being targets by APC, Tullow, CVX in Sierra Leone, Liberia and Cote D’Ivoire in 2H11/1H12

CVX spuds Liberia acreage in 4Q11

Montserrado Deep is important – potentially opens up a new basin in Liberia

Source: APC, TLW

West Africa Exploration to the Forefront – Pre Salt AngolaAngola Pre-Salt

Source: CIE

Cobalt Pre-Salt – Drilling Cameia Currently

US Gulf of Mexico S

ource: Wood M

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US GoM Reserves, 78% Held by Supermajors

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Crude Oil Demand

Oil Demand

Oil demand grew by a CAGR of 1.5% from 1992 to 2008.

We expect global oil demand to rise by about 1.9% in 2010.

We expect oil demand to grow at 1.4% per annum from 2011 to 2017.

Oil demand growth has been historically correlated with GDP growth, but not exclusively so. Price, taxation and fuel switching have all driven significant changes in consumption patterns.

The future of oil demand growth is presumed to be outside the OECD: mainly in China, India and other developing economies.

The principal uses for oil are transportation, power generation, and heating.

The highest value use of oil today is as a transportation fuel. As countries become richer they tend to reduce or phase out their industrial uses of oil.

Oil demand is price elastic: different consuming zones exhibit different price elasticity to crude prices. This is partly due to different end user taxation levels (the United States and China have low taxes, Europe has high taxes) and partly due to the relative availability of substitute fuels.

Oil Demand Correlation with Real GDP Growth (1969 - 2008)S

ource: BP S

tats, Credit S

uisse estimates

Global GDP trends are a clear underlying driver of oil demand.

However, the relationship is uneven and consuming regions exhibit very different demand multipliers to GDP (~1 in emerging economies, ~0.5 in the OECD).

R2 = 0.5802

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Worldwide Oil Consumption Growth

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Oil Demand Growth & Oil Prices


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Demand growth Real Brent Oil Price (USD/bbl), 2007

Recovery

Recession Recession

SPIKE

Collapse

Recovery

Saudis change policy

18 years of low and stable oil prices 1986-2004

Recession

Recovery

Boom

Recession

BoomBoom

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Recovery

Boom

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The Good Old Days

Recovery

Oil is a cyclical commodity (with managed characteristics).

Higher oil prices during booms create deeper demand recessions afterwards.

Oil Demand: Consumption Profile

In the past 20 years, Asia-Pacific has roughly doubled its oil consumption.

North America has also grown reasonably strongly.

Europe has been flat.

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Global Oil Markets

Oil Markets: Global in Nature

Oil is produced on nearly every continent. A complex transportation and refining system exists to move oil to end-user markets.

We estimate that the physical global crude trade is $1,680-billion-per year at $55/bbl oil and baseline global demand of 86 MBD.

Variations in the U.S. dollar exchange rate also play a significant role for crude price given that oil is traded in U.S. dollars. Geopolitics and speculation also influence the price of oil.

Crude oil is largely purchased by refiners to convert into refined products such as gasoline, as well as by power generation plants.

Futures are traded on major exchanges such as the NYMEX and the ICE.

Oil Markets: NYMEX

The NYMEX light, sweet crude oil futures contract is the world’s most liquid forum for crude oil trading and is also the world’s largest-volume futures contract trading on a physical commodity. The contract trades in units of 1,000 barrels, and the delivery point is Cushing, Oklahoma. The contract provides for delivery of several grades of domestic and internationally traded foreign crudes.650,000 contracts are traded on average per day.

Source: BBC

Oil Markets: Trading

Futures trading: standardized, exchange-traded contracts in which the contract buyer agrees to take delivery, from the seller, a specific quantity of crude oil at a predetermined price on a future delivery date.

Over-the-Counter Swaps etc: instead of trading via a futures exchange, buyers and sellers of crude oil can enter into an over the countertransaction, often known as a swap. These contacts have become more popular than futures trading in recent years, but can prove difficult to liquidate at times of market dislocation.

Term contracts: private contracts to buy specified quantities of crude oil at prices based on regional benchmarks. These contracts are not traded in any form. Most Kuwaiti crude oil is sold on term contracts, with the price of Kuwaiti crude oil tied to Saudi Arabian Medium (for western customers) and a monthly average of Dubai and Oman crudes (for Asian buyers).

International Energy Agency (IEA): Every month, the IEA releases the “Oil Market Report,” which contains information on supply, demand, stocks, prices, and refinery activity. U.S. Department of Energy: The DOE provides weekly information on crude and principal petroleum products in regards to factors such as supply, imports, inventories and refinery activity. Market participants utilize these types of data sources in order to form opinions on companies as well as the expected direction of the commodity.

Oil Markets: Data Sources

Source: IEA

Source: IEA

Futures Curve: Backwardation vs. Contango

$77.09

$72.04$72.49 $73.04 $73.61

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The shape of the 12-month futures curve is often an indication of current supply/demand balances.An upward sloping curve suggests higher expected prices and implicitly higher demand relative to supply in the future: ContangoA downward sloping curve suggests current demand is outpacing current supply with the expectation that the imbalance will become less pronounced in the coming time period: Backwardation

Source: Bloomberg

Futures Curve: Contango Example Futures Curve: Backwardation Example

Source: Bloomberg

$72.04

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NATURAL GAS

Natural Gas Overview

What is Natural Gas?

Natural Gas is a combustible, colorless and odorless gas that is made up of a mixture of hydrocarbons.Methane (which is dry gas) is the most commercially marketable component of the natural gas stream. Other components of the typical well-head natural gas stream (wet gas) include heavier “liquids” such as ethane, propane and butane. Natural Gas is measured on a unit basis in thousands of cubic feet (Mcf). The benchmark spot price is Henry Hub, which is quoted on a $ per Millions of British Thermal Units basis (MMBtu). An Mcf is a volume unit, while MMBtu is an energy measurement.Because of the need for extensive pipeline systems and difficulty in shipping, natural gas is most used in regions with indigenous supply. Meanwhile, the ability to ship gas in liquid form (LNG) is gaining traction.

Source: Chesapeake Energy

Global Natural Gas: Proved Reserves (2010)

North America350 Tcf

Asia Pacific575 Tcf

South & Central America264 Tcf

Middle East2,675 Tcf

Source: BP Statistical Review of World Energy 2011.

Europe & Eurasia2,227 Tcf

Total Proved Reserves were over 6,600 trillion cubic feet at year-end 2010.

Africa522 Tcf

World Energy: Natural Gas Has Gained Share of the Energy Pie

According to BP Statistical Energy Review, natural gas accounted for 24% of global primary energy consumption, the highest on record, in 2010.

Source: BP Statistical Review of World Energy 2011

Global Natural Gas: Daily Demand By Region (Bcf/d)

Source: BP Statistical Review of World Energy 2011

Global gas demand growth is currently being driven by Asia and the Middle East (due to a switch away from oil).

Substitutes for Natural Gas

There are numerous substitutes for natural gas including coal, oil, heatingoil, naphtha and alternative energy (such as wind, solar and nuclear power).

A global movement towards clean energy has put natural gas more in favor versus coal and oil, due to inherently lower CO2 emissions.

Coal Oil Alternative Energy

Source: www.britishcoalgasification.co.uk. Source: ecotechdaily.com Source: www.greengop.org.

North American Natural Gas

N. AM. Natural Gas PricingNorth America is mostly a “closed”market with natural gas prices driven by demand trends (weather, economic growth) and the cost of new supply.

Over the past 14 years, NYMEX gas prices have traded as low as $2-3 per MMBtu and as high as $14-15 per MMBtu.

In North America, oil and natural gas do not exhibit a strong pricing relationship as the two fuels don't compete much (oil is not used much for power while gas is not used much for transportation).

Outside of the U.S., prices tend to be linked to crude owing to less liquid trading markets.

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North American Natural Gas: Industry Overview

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The process of bringing natural gas to market begins with exploration & productionand ends with the retail distribution of gas to end markets.Along the way, gas is gathered and processed for removal of oil, water, natural gas liquids (NGLs) and sulfur. It is then transported and stored while awaiting distribution.

Upstream: Where is Natural Gas Located?

Source: U.S. Geological Survey. Source: StatoilHydro.

Onshore: Shale Onshore: Tight Gas Offshore

Source: Department of Primary Industries, Australia.

Exploration & Production (also known as the upstream) of natural gas is a global venture and producers operate in both onshore and offshore environments.

Natural gas is located underground and below seabeds.

Producers often drill thousands of feet beneath the surface to reach natural gas reservoirs.

In North America, onshore unconventional resources like shale and tight gas sands have become a growing source of production in recent years as traditional and lower cost sources have matured.

Upstream: Exploring and Producing Natural Gas

Producers use various techniques to locate and test for the existence of natural gas including geophysical surveys, seismic evaluation, exploratory wells, well logs, core samples and others.Once commercially viable quantities of natural gas have been discovered and confirmed, producers will develop the reservoir and commence production. Produced natural gas is then sent to processing facilities via pipeline.Please see Upstream section for additional detail on the exploration and production process.

Source: Japan Agency for Marine Earth Science and Technology Source: www.smi-online-co.uk

Midstream: Processing Natural Gas

Processing natural gas (midstream) involves the removal of oil, water, hydrogen sulfide, carbon dioxide and NGLs (ethane, butane and propane).The end goal is to produce dry gas, free of impurities or other non-methane compounds.

The Midstream: Transporting Natural Gas

Natural gas in the U.S. is delivered via a complex web of interstate and intrastate pipelines estimated by the American Gas Association to extend ~2.4 million miles.Pipeline companies charge regulated fees (tariffs) for moving gas.Major pipelines include the Transcontinental, Northwest, Rockies Express (REX) and Ruby pipelines. The Ruby Pipeline, which was completed in July 2011, provides westbound transport from the Rockies region with 1.5 Bcf/d of capacity.

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Natural Gas Marketing: What are Basis Differentials?

The NYMEX natural gas price (Henry Hub, Louisiana) is not necessarily what producers receive for their gas. The actual price received (well-head price) is different throughout the country. The difference relative to NYMEX is called a basis differential.

Regional prices are a function of local supply and demand balances and the transport cost to the consuming markets in the Northeast.

Historically, Rockies gas trades at the widest discount (given little local demand and long pipeline distances) while Appalachia gas trades at a premium (given proximity to high demand areas on the east coast). However, differentials across the U.S. have narrowed in recent quarters as a result of expanded pipeline capacity.

~$4.20/MMBtu

~$3.60/MMBtu ~$4.30/MMBtu

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Natural Gas Storage: The U.S. has a Deep Storage System

Before being transported for local distribution, natural gas is stored in underground facilities such as depleted reservoirs, salt caverns and aquifers.Total natural gas storage capacity in the U.S. is approximately 4.1-4.2 Tcf. Storage is located primarily in the Gulf Coast and the ‘consuming’ areas in the Midwest and Northeast.

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U.S. Weekly Storage Report

Natural gas in storage fluctuates from the withdrawal season (November to March) when cold weather typically results in storage withdrawals to the refill season(April to October) when lower demand leads to net storage injections.Every Thursday at 10:30am ET, the EIA reports the storage injection / draw for the prior week. The amount of injection or draw can have a material affect on gas prices as it indicates supply / demand trends relative to previous years.

WORKING GAS IN STORAGE

Change Change Differential9/2/2011 Week Ago % Bcf Year Ago % Bcf 5-Year Avg % Bcf

Producing Region 959 957 0.2% 2 971 (1.2%) (12) 925 3.7% 34Consuming East 1,636 1,578 3.7% 58 1,707 (4.2%) (71) 1,732 (5.5%) (96)Consuming West 430 426 0.9% 4 477 (9.9%) (47) 427 0.7% 3Total U.S. 3,025 2,961 2.2% 64 3,156 (4.2%) (131) 3,085 (1.9%) (60)

Source: Energy Information Administration (EIA)

Total U.S. Working Gas In Storage

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Major End Markets for Natural Gas

ResidentialGas used in private dwellings for space and water heating, air conditioning, cooking and other household uses

Electrical PowerGas used by power plants to generate electricity

CommercialGas used by non-manufacturing establishments in the sale of goods or services

IndustrialGas used for heat, power or chemical feedstock for manufacturing. End products include petrochemicals, fertilizers, plastics, etc.

Other smaller end-market uses of natural gas include 1) fuel (natural gas vehicles) and 2) oil & gas production.

Source: Energy Information Administration

U.S. Natural Gas Demand By End Markets

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Natural gas demand trends are highly seasonal. Because natural gas is used as a heating fuel, demand rises materially in the winter/cold weather months.

U.S. Natural Gas Demand by User (Bcf/d)

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Natural Gas Upstream Trends:Shale Gas in Focus

Shale Gas in Focus

Shale is a fine-grained sedimentary rock that may contain high concentrations ofnatural gas.Producers drill into shale beds and break open the rock using advanced drilling techniques and tremendous energy (pressure pumping). Shale is a growing source of current and future natural gas production in the U.S. It currently represents about 13-15 Bcf/d (~20-22%) of total U.S. production.

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Shale Basins in the U.S.Major shale plays include: Bakken, Barnett, Eagle Ford, Fayetteville, Haynesville, Marcellus and Woodford.

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Bakken Shale

The Bakken Shale is an unconventional resource play located in the Williston Basin in North Dakota, Montana and Saskatchewan. An oil-based shale play that offers one of the highest rate of returns in the industry.Major players include BEXP, CLR, DNR, EOG, NFX, WLL, XTO/XOM and KOG. Transporting produced volumes out of the Williston remains an issue for the industry, but recent capacity additions have provided some relief. Significant rise in completed well costs (+35% since 2009) is the biggest concern.

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Barnett Shale Barnett Shale Natural Gas Production (MMcf/d)

Includes Denton, Tarrant, Wise, Hood, Johnson, Parker, Hill, Bosque, Sommervell, and Ellis Counties.

The Barnett Shale is an unconventional resource play located in North Central Texas.

Production growth has slowed to less than 5% in 2010 after growing 36% per annum over the 2004 – 2009 timeframe showing that the play is maturing.

~3MM total acres with DVN, XTO/XOM, EOG and CHK as the major players.

Wells can be drilled in 15-20 days, much quicker than some other shale plays.

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Barnett Growth –– 37.1% 37.3% 46.3% 30.9% 9.4% 32.9% 42.0% 54.0% 46.0% 10.1% 4.1%

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Industry believes play spans some 3.5MM acres

We believe much of the “greenfield” leasing has been done

Ways to enter now are through acquisitions, joint ventures or farm-outs

Haynesville Shale

The Haynesville Shale is an unconventional resource play located in East Texas / North Louisiana. Production has ramped up quickly and some industry sources indicate it could total 1.6 Bcf/d today. Major players include ECA, CHK, PXP, RDS and HK. IP rates are typically 10-15 MMcf/d and have been as high as 30 MMcf/d, but first year decline rates are 80-90%.

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Marcellus Shale

The Marcellus Shale is an unconventional resource play located in Appalachia. Recent upward well EUR revisions in the SW PA region has pushed it to be one of the highest rate-of-return plays in the industry. IP rates typically range 2-10 MMcf/d.Play consists of ~60MM acres with EQT, RRC, APC, CVX, UPL, CNX, COG and CHK as the major players. Takeaway capacity concerns are being addressed with increased processing and pipeline buildouts.The Marcellus is currently producing ~3 Bcf/d and should continue to ramp into 2012.

Low Pressure AreaHigh Pressure Area

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Eagle Ford Shale

The Eagle Ford Shale is an unconventional resource play located in South Texas.It has gained significant attention with BHP Billiton’s recent acquisition of Petrohawkfor $12.1 billion (a 65% premium).Concerns over takeaway capacity (lack of pipelines and trucks) remain a key issue, but are currently being addressed.EOG, APC, CHK, NFX, SM, SFY, ROSE and BHP are major players. IP rates typically range 8-12 MMcfe/d.

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Emerging Plays - Utica

The Utica Shale is an unconventional resource play located in Eastern Ohio.It is considered an analog to the Eagle Ford with oil, wet gas/volatile oil and dry gas windows. Current focus has been on liquids-rich and volatile oil parts of the play.There has been significant exploratory activity and deal flow with recent JV’s and acquisitions (CNX/HES) that have valued the Utica at ~$9,000/acre.CHK, EVEP, DVN, APC, GPOR, REXX, PETD, CNX and HES are major players. IP rates are speculated to be 20+ MMcf/d.

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Emerging Plays – Uinta and Other Basins

The Uinta Shale is an unconventional resource play located in Northern Utah.BBG/BRY have announced an initial well and NFX has announced five wells to date with impressive early results.The Brown Dense is a new oil/gas play in Southern Arkansas and Northern Louisiana with no results announced to date. SWN and DVN are first movers in the play.The Tuscaloosa is a new play in Southeastern Mississippi/Eastern Louisiana with DNR, GDP, DVN and ECA have established acreage in the play.

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Liquified Natural Gas (LNG)

Liquefied Natural Gas (LNG)

Liquefied Natural Gas (LNG) is natural gas (methane) that is chilled to liquid form.Natural Gas as a liquid occupies 1/600th of the space versus ambient gas, making it easier to store and transport on cargoes. LNG can be transported by ship or truck to destinations that can’t be easily reached by pipelines.

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LNG: Industry Overview

LNG is exported from regions that have an abundant supply of natural gas, but without significant local markets.

LNG facilities are highly capital intensive ($5-10B) and LNG vessels are $200-300MM each.

While most LNG projects operate under long-term contracts (20-25 years), there is a growing spot market of ~5-6 Bcf/d.

Spot shipments are delivered to regions with the highest netback prices (i.e., offer the highest bids for LNG cargoes).

Contracted import prices are often based on a oil-indexed contract (such as Japanese Crude Cocktail [JCC]).

LiquefactionTransport

Regasification

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LNG: Liquefaction

Liquefaction is the process by which natural gas is converted to liquid form.Methane gas is piped to a liquefaction facility where it is chilled to -260°F, at which point the vapor condenses to liquid. The liquefied gas is then loaded on to a carrier and transported to import markets.Construction of a liquefaction facility can take five to seven years.Key LNG Supply Markets: Pacific Basin (Australia, Indonesia, Malaysia), Atlantic Basin (Algeria, Nigeria, Trinidad), and Middle East (Qatar, Egypt, Oman).

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LNG: Regasification

Imported LNG is received as shipments at terminals with regasification (“regas” ) capabilities.Regasification involves bringing natural gas back to its gaseous form through thermal energy. The gas is then stored and distributed to local end-users through pipelines.Key Import Markets: Asia (Japan, Korea, Taiwan, India, China), Europe (U.K., Spain, Belgium) and U.S. (bidder of last resort). New markets are emerging in Southeast Asia, Latin America and the Middle East.

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Storage FacilityLNG Carrier

U.S. LNG import terminals (with regas facilities) include Cove Point, Elba Island, Everett, Freeport, Lake Charles, Cameron, Peñuelas, Sabine and Golden Pass.COP and MRO closed the Kenai LNG plant in October 2011, the only LNG export terminal (with liquefaction facilities) in the U.S. The largest supplier of LNG to the U.S. is Trinidad.

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LNG: U.S. Import Terminals

LNG now accounts for 30.5% of the global gas trade

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LNG: 2010 Imports / Exports by Region

Japan is currently the largest importer of LNG globally, importing 9.0 Bcf/d in 2010 as the country has few domestic means to satisfy natural gas demand.Imports primarily come from Australia, Indonesia and Malaysia.Total regasification capacity is currently approximately 25 Bcf/d with one terminal (Sodegaura) capable of importing 3.9 Bcf/d, one of the largest in the world.

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LNG: Major Importing Countries – Japan

South Korea is currently the second largest importer of LNG globally, importing 4.3 Bcf/d in 2010.Current regasification capacity is roughly 10 Bcf/d with imports primarily from Qatar, Indonesia and Malaysia.Similarly to Japan, Korea has minimal domestic natural gas production and relies on LNG to fill the gap.

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LNG: Major Importing Countries – South Korea

Spain is currently the third largest importer of LNG globally, importing 2.7 Bcf/d in 2010.Current regasification capacity is roughly 5.9 Bcf/d and is set to rise to nearly 7 Bcf/d over the next five years or so.Spain relies on LNG imports (~3.0 Bcf/d) and pipeline gas (0.9 Bcf/d) to satisfy natural gas demand.

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LNG: Major Importing Countries – Spain

Qatar is currently the largest exporter of LNG globally, exporting 7.3 Bcf/d in 2010.Liquefaction capacity currently stands at ~10.2 Bcf/d and should continue to grow through 2012 as two recently completed projects have yet to reach plateau.Qatar exports gas to most markets including Japan, Korea, Spain, U.K. and the U.S.Exported gas is primarily sourced from the large North Field, which has estimated recoverable natural gas reserves of more than 900 Tcf.

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LNG: Major Exporting Countries – Qatar

Indonesia is currently the second largest exporter of LNG globally, exporting 3.0 Bcf/d in 2010.Liquefaction capacity currently stands at ~4.2 Bcf/d with the majority (3 Bcf/d) from the large Bontang LNG facility that includes eight processing trains.Indonesia plans to reduce future LNG exports from traditional LNG trains due to increasing domestic demand for gas, but recently granted project approval to Tangguhto build a third train, which should increase capacity by 0.6 Bcf/d.Like Australia, Indonesia primarily exports LNG to Asian markets.

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LNG: Major Exporting Countries – Indonesia

Australia is currently the fourth largest exporter of LNG globally, exporting 2.5 Bcf/d in 2010.While liquefaction capacity only stands at ~3.2 Bcf/d currently, future projects are set to raise liquefaction capacity to 10-15 Bcf/d by 2020.Australia primarily exports its gas to Asian markets such as Japan, China and Korea.The $37B, 2.0 Bcf/d Gorgon LNG project is currently being developed with first production expected in 2014 or 2015. Gorgon will be Australia’s largest resources project.

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LNG: Major Exporting Countries – Australia

THE UPSTREAM

Exploration & Production

Exploration & Production is the first link in the oil & gas supply chain and involves:1) Search and discovery of oil & gas reserves. 2) Extraction of oil & gas resources.

Oil Supply Chain Natural Gas Supply Chain

Source: American Petroleum Institute.


Exploration & Production: Industry PlayersThe industry is made up of several categories of players who participate in exploration and production for oil and natural gas.

1) Integrated Oils: Are involved in all links of the supply chain, including the upstream.

2) Independent E&P: Primary business is to engage in exploration & production.

3) Pipeline Companies: Focus mainly on natural gas transmission but often have upstream segments as well.

Independent E&Ps Pipeline FocusedIntegrated Oils

Source: Google images

The Upstream Process

The Upstream Process (E&P)

Exploration & Production involves the search for and development and production of oil and gas reservoirs. The process is broken down into five primary phases:

1) Acreage Acquisition: Producers begin by acquiring leases and drilling permits. Prospects include:Locations contiguous to producing formationsUnexplored areas

2) Exploration & Appraisal: Producers will then begin to evaluate the acreage to see if there are commercially recoverable reserves.

Involves sub-surface analysis, shooting seismic and drilling exploratory wells and appraisal wells. Wells drilled in previously unexplored areas are known as wildcats.

3) Development: Once the commercial viability of a prospect is determined, rigs and equipment will be contracted and wells are drilled and completed.

4) Production: Full scale production involves the ongoing collection of hydrocarbons. Oil and gas are produced from within the well and transported to processing facilities via pipelines.

5) Plugging and Abandonment: When a well has produced out its economically recoverable reserves, the well is decommissioned and equipment is removed from within the wellbore.

Source: www.directnews.co.uk, Gardner Denver ,Texas A&M University

The Upstream Process

Acquire acreage

Conduct seismic survey

Interpret data

Identify prospects

Drill exploration

wellsEvaluate results

Good

Bad

Plug & Abandon

Drill further wells -

appraisal

Oil

Gaswith no spot

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Examine gas sales options

For Sale

Negotiate gas sales contract

Sign gas sales

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START HERE

Formulate Development

PlanNo market identified

Final Investment Decision

Begin drilling wells

Install platform/ rig or drilling

ship

Begin production

Install production facilities

Sell oil / gas for cash

Go on to Development

Source: Google images.

Acreage Acquisition: Exploration and Right to Drill

The first step producers take is to negotiate or bid for leaseswith governments, states or spare private land owners. Producers then acquire drilling permits / necessary regulatory approvals (from federal/state/local governments) for the right to drill.

Lease terms vary widely between countries but leases typically include:

1) A royalty payment to land owners that represent a percentage of gross production (typically 12.5-30.0% in the U.S.), OR

2) In some countries, leases are commonly awarded as Production Sharing Contracts or Agreements (PSCs, PSAs)

Lease terms can range from:1) Short-term: 3-5 years

2) Long-term: approximately 10 years

3) Held by production: lease can be held based on a minimum production threshold

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Exploration & Appraisal: Finding Hydrocarbons

Among various techniques, producers use geological surveys and seismic evaluation to determine the likely existence of hydrocarbons before drilling a well.Geological surveys involve surface level analysis of the geology of an area to assess if sufficient oil and gas reserves are likely to be beneath the surface.Seismic evaluation allows producers to develop a subsurface image of a play.

Seismic Evaluation

Source: Cobalt Exploration.

Geological Surveys

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Exploration & Appraisal: Seismic Evaluation

Seismic evaluation has greatly de-risked the exploration process. Seismic is one of the most widely used exploration tools today and is used both onshore and offshore.Seismic evaluation involves the creation of a subsurface area image that can indicate hydrocarbon accumulations.The process: – Seismic waves (acoustic vibrations) are created.

– The waves migrate downward and reflect off of various layers of subsurface rock back to the surface where receivers "catch" the waves.

– The speed and nature of how the waves reflect are then interpreted to estimate subsurface geology.

Please see Oilfield Services section for additional detail

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Exploration & Appraisal: Drilling Test Wells

Once a target is chosen, producers will drill a prospect to confirm the existence of hydrocarbons. In areas where the existence of oil and gas reserves are unproven, producers will drill an exploratory well to confirm pre-drilling test data (geological surveys and seismic).– Successful exploration wells are capitalized as part of

the project’s overall cost.

– Unsuccessful exploration wells are known as “dry holes” and their cost is generally immediately expensed.

For higher risk offshore production, producers will often drill appraisal wells to test flow rates and determine the commercial viability of the reservoir.

Resources (Germany): Kansas University Geological Survey

Source: Federal Institute of Geosciences and Natural

Exploration & Appraisal: Downhole Tests

Downhole tests are run from within the well during drilling to test formation properties and determine the commercial viability of the reservoir. Common tests include:1) Coring – Core samples from the formation are collected from within the well. Fragments are tested to estimate flow potential for the well and effectiveness of fracture stimulation.

2) Logging – Uses electrical, acoustic and other signals to measure depth and formation properties in the wellbore. Source: San Joaquin Geological Society

Development: Drilling the Well

The most common technique used to drill a well is rotary drilling. As the name implies, rotary drilling uses a sharp drill bitthat drills through the Earth’s crust.Wells are drilled with rigs and equipment that is often contracted from an oilfield service company, to which producers pay day rates and fees for services rendered.Once a well is drilled, its commercial viability is determined. If a well contains sufficient oil and gas, it is completed and production commences.If a well does not contain sufficient hydrocarbons, it is designated a dry welland then plugged and abandoned.

Source: Schlumberger

Source: Encarta

Development: Horizontal Drilling

An advanced drilling technique used by producers is directional drilling, which allows the well to be drilled at varied angles to access reservoirs that would otherwise be difficult to reach using traditional vertical drilling. Horizontal drilling is a widely used variation of directional drilling and has been a key to unlocking gas from shale formations.Horizontal drilling allows producers to access more difficult reservoirs, albeit it at higher costs.

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Vertical Well

Horizontal Drilling reaches deeper into blanket formations

Horizontal Well

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Development: Well Completions

The process of completing a well involves installing casing to provide support for the wellbore (to prevent it from caving in). Well casing also serves to prevent leakage of oil and gas.Well casing is typically made of steel, which makes producers susceptible to movements in steel prices.Once the casing is installed, the well is perforated via explosive charges that are lowered into the well, which produce holes for hydrocarbons to flow into.


Source: Halliburton Source: Schlumberger

Development: Well Stimulation

If a reservoir contains hydrocarbons which are high in viscosity or have limited fissures to move through, producers may need to stimulate the reservoir with hydraulic fracturing (“frac job”).

Frac jobs involve pumping fracturing fluid (a combination of water and sand) into the well at high pressures, creating fractures in the formation that allow oil and gas to flow through and into the wellbore.

The goal of fracturing is to increase flow of oil and natural gas. S

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Additional fractures allow for better flow of oil and gas

trapped within a formation

Production: Producing the Well

Production begins once a well has been completed and hydrocarbons flow to the surface. During production, the natural pressure within a well may allow hydrocarbons to flow freely to the surface. When hydrocarbons are highly viscous or the formation below the surface has low permeability or low porosity, lifting equipment and / or compression may be necessary to best extract the oil and gas.

Sources: Well Services Energy, University of Texas

Production: Decline Rates

Production will come on at an initial production rate (IP rate) and decline as natural pressure dissipates and the well produces out.Production decline rates will vary among different fields, with some gas shales exhibiting very steep declines within the first year (80-90%) and long life tails. Decline rates force producers to consider the time-value of a play.

Source: Ultra Petroleum.

Sample Decline Curve for a Pinedale Tight Gas Well

Production: Enhanced Oil Recovery

As natural pressure fades during primary recovery, production falls leaving a significant amount of unrecovered oil remaining in the reservoir. Enhanced Oil Recovery (EOR) methods can be used to restore pressure within oil wells and regenerate flow (secondary and tertiary recovery). Secondary recovery involves pumping water into the well to restore pressure and stimulate oil flow. Secondary recovery can restore flow to a well for 10-15 years.Tertiary recovery involves pumping CO2 to increase recovery. CO2 restores pressure to the well, and also make oil less viscous and therefore easier to produce.

Sou

rce:

Sch

lum

berg

er

Abandonment

At the end of its productive life, a well or field area is abandoned.

In the onshore segment, the tubing may be removed from the well and sections of well bore filled with cement. The surface around the wellhead is then excavated, the wellhead and casing are cut off, and a cap is welded in place and then buried.

In the offshore segment, the process is sometimes referred to as “decommissioning.”Platforms are de-activated and either removed or dropped to the seabed as prescribed.

Source: The Fairweather Group.

Oil and Gas Reserves

Exploration & Production: Reserves

Producers can add reserves either 1) organically (drill-bit) or 2) through acquisitionsRecognizing Reserves:1) Proven Reserves (1P) – Estimated quantities of oil and gas that are reasonably certain(80%-90% confidence) to be recoverable under today’s technology and prices. 1P can be broken down into:

- Proven Developed (PDP): Reserves expected to be recovered from existing wells, existing equipment and/or improved recovery techniques.

- Proven Undeveloped (PUD): Reserves that will require further development and that are expected to be recovered from undrilled acreage or existing wells that require recompletion work.

. 2) Probable (2P) – Unproven reserves that are more than likely to be recoverable (50% confidence). Probables cannot be booked under current SEC guidelines.3) Possible (3P) – Unproven reserves that are less likely to be recovered than probables. Possibles cannot be booked under current SEC guidelines. Possibles

Probables

PUD

PDP

0%

20%

40%

60%

80%

100% Proved


Exploration & Production: Estimating ReservesOil in place or gas in place refers to the amount of oil or gas in a subsurface reservoir.

Only a fraction of this oil can be recovered from a reservoir and is known as the recovery factor. The portion that can be removed is considered in the calculation of reserves.

There are three general categories for estimating oil reserves:

1. Volumetric Method: This method attempts to determine the amount of oil/gas-in-place by using the size of the reservoir as well as the physical properties of its rocks and fluids. Then a recovery factor is assumed, using assumptions from fields with similar characteristics. This method is most useful early in the life of the reservoir, before significant production has occurred.

2. Materials Balance Method: The materials balance method for an oil field uses an equation that relates the volume of oil, water and gas that has been produced from a reservoir, and the change in reservoir pressure, to calculate the remaining oil/gas. It requires some production to occur (typically 5% to 10% of ultimate recovery), unless reliable pressure history can be used from a field with similar rock and fluid characteristics.

3. Production Decline Curve Method: The decline curve method uses production data to fit a decline curve and estimate future oil production. It is assumed that the production will decline on a reasonably smooth curve, and so allowances must be made for wells shut in and production restrictions.

Exploration & Production: Reserve Accounting

Producers are not required by the SEC to perform reserve audits but many choose to use outside engineers.

Reserves may be revised depending on assessments of price and performance.

Performance revisions include better than expected recovery (eg. In-fill drilling).

At low commodity prices, it sometimes becomes uneconomic to produce certain reserves, so producers are forced to post negative price reserve revisions.

Negative price revisions are different than impairments (which are taken against oil & gas properties, not reserves).

The SEC recently revised the rules regarding reserve accounting that took effect for the 12/31/2009 reporting season. Some of the changes include:

Use of a 12-month average price (calculated as the arithmetic average of the price on the first day of each month) rather than single-day, year-end pricing.

Producers are able to report proved undeveloped reserve locations that are not directly offset by a producing well (one offset rule), which has led to higher industry PUD ratios.

Exploration & Production: Reserve Life

This is the length of time that remaining reserves would last if production were to continue at current levels.Calculated as the reserves remaining at the end of any year divided by the production in that year.

Source: BP Stats

68

58

46

37

11

60

200

0

10

20

30

40

50

60

70

80

Middle Eas

t

Africa

Europe/E

urasia

Latin A

merica

AsiaNorth

Ameri

ca

World

Year

s

THE MIDSTREAM

Midstream

Midstream refers to all activities between the production of natural gas and oil and the end-use marketsMidstream activities include transporting, processing, fractionating, and storing natural gas, natural gas liquids, crude oil and refined products

Source: Enterprise Products Partners


Midstream: Industry Players

The industry is made up of several categories of players but may generally be split by hydrocarbon

1) Natural Gas Midstream: Involved in transporting natural gas and natural gas liquids to end-use markets.

2) Crude Oil / Refined Products Midstream: Involved in transporting crude oil and refined products to end-use markets.

Crude Oil / Refined Products MidstreamNatural Gas Midstream

El Paso

Spectra

Williams

ONEOK

Enterprise

Energy Transfer

Kinder Morgan

Boardwalk

The Majors

Plains All American

Colonial Pipeline

Enbridge

Kinder Morgan

NuStar

Sunoco Logistics

Magellan

Buckeye

Natural Gas

Midstream: Natural Gas Processing

Processing natural gas involves the removal of oil, water, hydrogen sulfide, carbon dioxide and natural gas liquids (NGLs).After the NGLs are separated from the natural gas stream they are transported via pipeline to fractionators where they are further separated into purity products (ethane, propane, butane, isobutane, natural gasoline).The resulting dry gas, free of impurities or other non-methane compounds, is deemed “pipeline quality”.

NGL Fundamental Drivers

Source: Bloomberg, Credit Suisse, as of 09/07/2011

Natural gas production requires gathering and processing servicesEspecially rich gas from unconventional resource plays

The relationship between natural gas prices (the feedstock for NGLs) and crude oil prices affect natural gas processing economics

NGL price - Natural Gas price = Processing Margin

Drivers of natural gas liquids productionAbsolute level of natural gas producedMix of natural gas production between rich gas (contains relatively more NGLs) and dry gas (contains small amounts of NGLs)

Quarterly NGL Composite Price(Average of Weekly Prices)

$1.44

$0.71$0.63

$0.73$0.84

$1.04

$0.81

$1.15$1.03 $0.97

$1.16$1.08

$1.25$1.40$1.40

$1.65 $1.65

$1.36

0.00

0.20

0.40

0.60

0.80

1.00

1.20

1.40

1.60

1.80

1Q08 2Q08 3Q08 4Q08 2008 1Q09 2Q09 3Q09 4Q09 2009 1Q10 2Q10 3Q10 4Q10 2010 1Q11 2Q113Q11TD

($ /

Gal)

Quarterly Gross Processing Spread(Average of Weekly Spreads)

$0.67$0.65

$0.15$0.23

$0.40

$0.56$0.67

$0.47

$0.70$0.65$0.59

$0.82

$0.69

$0.88

$1.01$1.03

$0.85

$0.58

0.00

0.20

0.40

0.60

0.80

1.00

1.20

1Q08 2Q08 3Q08 4Q08 2008 1Q09 2Q09 3Q09 4Q09 2009 1Q10 2Q10 3Q10 4Q10 2010 1Q11 2Q113Q11TD

($ / G

al)

Dry natural gas can move into interstate or intrastate pipelines or into storageInterstate pipelines are regulated by the Federal Energy Regulatory Commission (FERC)Intrastate pipelines are regulated at the state level (and FERC in certain instances)Storage facilities may be FERC-regulated or have market-based ratesTwo favorable characteristics of interstate pipelines:1) The pipeline does not take title to the commodity and is thus not sensitive to commodity prices2) Capacity reservation fees provide stable revenue regardless of volumes transported

Natural Gas Pipelines & Storage

Source: EIA

Natural Gas Pipelines Natural Gas Storage

Crude Oil / Refined Products

Crude Oil: Lease Gathering & Marketing

Source: American Petroleum Institute

Purchase and sales are typically entered into nearly simultaneously to mitigate commodity price exposure. Although lease gathering contracts are usually for short periods of 30 days, producers tend not to switch and remain loyal because the crude gatherer also provides field and administrative services to the producer.

Midstream companies purchase crude from producers at or near the wellhead (lease) and sell that crude to refiners or third party marketers. Typically the crude is gathered by trucks or small diameter pipelines.

~200,000 miles of pipelines in the U.S. transport about two-thirds of the petroleum consumed (water carriers (28%), trucks (4%), and rail (2%) represent the balance). Pipelines must be dedicated to either crude or refined products, but not both. Liquids pipelines do not take title to the commodities transported; their revenue streams depend on tariffs and the volume of product transported.Tariffs may be market based or regulated by the FERC.– Pipelines are allowed to adjust tariffs each July based on the producer price index for finished

goods for the prior calendar year plus 2.65%.– This index methodology is reviewed every 5 years; current calculation is set through June 2012.

Crude Oil / Refined Products Pipelines

Source: Allegro Energy Group

Major Crude Oil Pipelines Major Refined Products Pipelines

Refined Products Pipelines: Batching

Source: www.pipeline101.com

Products that meet certain specifications can be mixed (batched) and transported together in sequence. A batch is a quantity of one product or grade that will be transported before the injection of a second product or grade. Transmix is created at the interface point where two batches meet. This new mixture must be moved to a separate storage facility and reprocessed.

R egular Gasoline

Premium Gasoline

Premium Gasoline

R egular Gasoline

D iese l

Jet F uel

OILFIELD SERVICES, DRILLING & EQUIPMENT

Products & Services

Oilfield Services: Industry Segments

The Industry is made up of several segments/life cycle categories. We list them by stage of a new oil & gas field:

1) Exploration/Seismic2) Drilling3) Completion4) Production

Oil Service companies aid independent exploration and production companies (E&Ps), international oil companies (IOCs) and national oil companies (NOCs) in the exploration and production of oil and natural gas.

2010 Western Service company total revenues: $259B

Source: Spears & Associates

Completion15%

Production Services

6%

Contract Drilling22%

Drill ing Services25%

Exploration/ Seismic

5%Equipment/

Infrastructure27%

Total Revenue: $259B

Total Drilling 47%

Total Production 33%

Source: Spears & Associates, BP Energy, Baker Hughes

Streamer

s

Receiver

vessel

Seismic services and equipment include:Data Acquisition - collection of seismic dataData Processing - third party processing of seismic data prior to interpretationLibrary Sales - multiclient sales of non-exclusive seismic dataSoftware - software products for seismic processing, interpretation, mapping, reservoir modeling and characterization, petrophysical evaluation, and engineering analysis that can run on workstations or PCsGeophysical Equipment - data recorders, telemetry systems, geophones/hydrophones, energy sources (vibratory vehicles, air guns, etc.) used in data acquisition.

OFS - Exploration: SeismicMarine Seismic Survey

Seismic Output

Source: Spears & Associates, Schlumberger, American Association of Petroleum Geologists

Types of Log Measurements:

Electrical properties – resistivity and

conductivity

Neutron density (porosity)

Pressure testing

Sonic properties

Dimensional measurements

Formation fluid sampling

Spectroscopy (lithography)

Wireline logging includes both open and cased hole services. Open hole logging occurs during the drilling process and measures characteristics of the rock and the fluids contained therein. Cased hole logging refers to measurements taken in a well after a casing or liner has been set in the well. It is often applied in old wells to help operators determine what to do next (e.g. where to drill a side track well).

OFS – Exploration/Drilling: Wireline Logging/LWD

OFS – Contract Drilling: Land Rigs

Land Rigs can be mechanical or electric and vary in terms of drilling depth and horsepower. They are used for onshore oil and gas drilling. Key equipment includes:Derrick – A structure used for lifting and positioning the drilling string and piping above the well bore and containing machinery for turning the drill bit. Top drive – A device suspended in the derrick that rotates the drill pipe in order to drill the well. Draw works – A steel spool device that is used to reel out and reel in the drilling line.Blow Out Preventer (BOP) – A large valve used to seal off a well being drilled or worked over at the surface to prevent the escape of pressure.


Source: ODS-Petrodata, Noble, Rowan

Jackup

OFS – Contract Drilling: Offshore RigsSemisubmersible

Drillship

Drillship A floating mobile offshore drilling vessel that operates in the midwater, deepwater and ultra-deepwater and is typically dynamically positioned.Semisubmersible A floating mobile offshore drilling platform that operates in the midwater, deepwater and ultra-deepwater and can be conventionally moored (anchored) or dynamically positioned. Jackup A mobile offshore drilling platform that operates in shallow water and rests on the oceanfloor when in operation. 2 types:– Independent Leg -Anchored by “legs”

that extend down to the seabed– Mat - Anchored by a mat-like structure

that rests on the sea bed.

OFS – Contract Drilling: Offshore Rigs by Geography

Middle East, SE Asia are the largest jackup markets

Global jackup markets as % of total Global floater markets as % of total

Source: ODS-Petrodata, note figures exclude newbuilds

South America, West Africa, North Sea are the largest floater markets

US GOM17%

Central/South America10%

North Sea9%

Med./Africa13%

Middle East/India31%

Southeast Asia/Far East20%

US GOM12%

Central/South America31%

North Sea15%

Med./Africa19%

Middle East/India4%

Southeast Asia/Far East15%

Australia/New Zealand3%

Other1%

Roller or Tri-Cone

Fixed Cutter or Polycrystalline

Compact Diamond (PDC)

OFS – Drilling: Bits

Drill bits come in two main categories: Roller-cone and fixed cutter (PDC). Technology advancement has led to steady share gains by PDC bits and is moving the market to buy on a $/ft drilled basis (i.e. a “rental” model).–Roller cone bits have teeth typically made of milled

steel or tungsten-carbon inserts mounted on three roller cone assemblies. They are best used in hard and medium strength formations.

–Fixed cutter bits usually use Polycrystalline Compact Diamond (PDC) inserts mounted on the body of the bit. Fixed cutter bits are often custom engineered for specific formation characteristics. PDC bits have typically been used for soft formations, but advancing technology now puts them in hard, abrasive rock.


OFS – Drilling: Fluid System

The drilling fluid, also known as drilling mud, is one of the major factors in the success or failure of the drilling operation. Drilling fluid serves three functions:

– Lifts cuttings to the surface

– Cools the drill bit

– Supports the integrity of the wellbore and prevents hydrocarbon “kicks” by providing weight/pressure that is generally greater than that of the reservoir (known as an “over-balanced” condition).

The fluids handling system re-circulates the drilling mud and includes:

– Mud pump

– Mud mixer

– Shale shaker - to remove cuttings from the subsurface

– Mud pit – to collect used mud for recirculation

Fluid Circulation System

Fluid Enters the well at the Bit

Directional and Horizontal Wells

Directional drilling entails drilling in a direction other than vertical. There are two methods:

– Conventional uses a bend near the bit and a steerable mud motor. Drilling fluid is pumped through the mud motor, turning the bit and thereby allowing it to drill in the direction the bit points (unlike conventional [vertical] drilling, the drill string does not rotate).

– Rotary Steerable Tools (RST) allow the driller to “point” or “push” the bit without stopping drill pipe rotation, allowing for faster and smoother hole construction.

Drilling directionally entails use of steering systems (Measurement While Drilling or MWD) and Logging While Drilling or FEWD or LWD). LWD measurements are generally similar to those taken in wireline logging.

OFS – Directional Drilling

Rotary Steerable Technology

Source: www.horizontaldrilling.org, Halliburton

Completing the well is the process of accessing the reservoir including:

– Installation of casing and liner. Casing is large diameter steel pipe that is cemented into the well bore to ensure stability of the formation.

– Perforating the casing to access the reservoir. A series of “chargers” are deployed to where the well accesses the reservoir.

– Stimulation (see next page)

OFS - Completions

Casing

Reservoir

Perforations

Perforating Casing/ Completion

Other key products include:– Packers and plugs to isolate zones

– Screens to keep sands away from production

– Isolation valves to manage flows from multiple completion zones

Screen Layers

Source: Schlumberger, Halliburton

Completion System

Packers

Source: BJ Services, Carbo Ceramics, Independent Oil & Gas Service, Gulftex, ProPublica

Frac job

Frac unit

Cementing unit

OFS – Completion: Pressure Pumping

Pressure pumping consists primarily of cementing and various forms of production stimulation.

–Cementing of Casing (approx 20% of P.P revenue) -As described in the completions section, casing is cemented in place in the well bore. Cement is pumped thru the casing to the end of the section and forced back up the well in the annulus (between outer wall and well) where it sets and hardens.

–Stimulation (80%) – Services include hydraulic fracturing (dominant), acidizing and nitrogen injection.

In fracturing, fluid is pumped at high pressures into the well bore to create/widen fractures in the formation so oil/gas can flow into the well. Proppants are used to keep fractures open and can be sand, resin-coated sand, and/or ceramic.

In acidizing, acids can be used to etch away rock.

Proppants

OFS – Hydraulic Fracturing Equipment

Source: Jereh-PE, Weir SPM, Schlumberger

Treating Iron

Frac Pump Transmission

EngineCooling System

Power EndExpected Lifespan:Up to 2 years

Fluid EndExpected Lifespan:Ranges from 500 to 1,400 hours

Frac Pump: a high pressure, high volume

pump used in hydraulic fracturing

• Manufacturers include independents

such as Gardner Denver (GDI) and Weir

SPM (WEIR.LN) and vertically integrated

providers such as Halliburton (HAL) and

FracTech

Treating Iron: temporary surface piping,

valves and manifolds required to bring fluid

treatment down to wellbore from the pump

Frac Truck

Frac Pump

Source: FMC Technologies, Oceaneering International, Umbilical Manufacturers’ Federation

Subsea TreeSurface Tree

OFS – Production: Subsea

A Christmas tree is a set of valves that sit on top of the wellhead and control the flow of pressure of a producing well.

– Surface trees are installed on land and on offshore platforms.

– Subsea trees are installed on the sea bed.

Manifolds house equipment and pipes that control, direct and measure the flow of fluids to/from the subsea well.

Umbilicals are used for the control of subsea production systems. Umbilicals are made of either steel or thermoplastic tubes that contain fluid conduits for hydraulic power and chemical injection.

Subsea TreeManifold

UmbilicalsFlowlines

Subsea TreeManifold

UmbilicalsFlowlines

Subsea Production System

Umbilical

Source: MMS, Credit Suisse

OFS – Production: Offshore SystemsOffshore production infrastructure includes:– Fixed Platforms consist of a jacket driven into the

seabed with a deck; water depths up to 1,500ft.

– Compliant Towers can sustain significant lateral deflections; water depths 1,000-2,000ft.

– Tension Leg Platforms float but connected to the sea floor by vertical tendons; water depths up to 4,000 ft.

– SPAR Platforms have a large single vertical cylinder supporting a deck; water depths beyond 4,000 ft.

– Floating Production Systems are semi-submersibles anchored by wire rope and chain, or dynamically positioned; water depths beyond 4,000 ft.

– Floating Production, Storage & Offloading Systems (FPSO) are large tanker vessels moored to the seafloor; process and stow production from subsea wells and offload to a small tanker; suited for remote deepwater areas with no pipeline infrastructure; water depths beyond 4,000 ft.

Offshore Production Development Systems

Source: Spears & Associates, Weatherford, Independent Oil & Gas Service, Schlumberger

Rod pump

OFS – Production: Artificial Lift

Artificial Lift is a technology for mature oil and gas wells that need to boost fluids out of the wellbore, particularly as they produce water. 90% of existing producing oil wells and gas wells requiring water removal utilize some type of artificial lift. Main types of artificial lift include:

– Reciprocating rod pumps – a plunger and valve assembly driven by surface motor

– Electric Submersible Pumps (ESPs) – typically several centrifugal pump stages to access different wellbore sections driven by a downhole electric motor

– Progressive Cavity Pumps (PCPs) – a surface motor rotates the sucker rods using a stator and rotor to cause fluid to flow upward

ESP PCP

Source: Exterran Holdings, Ariel

Compressor

OFS – Production: Compression

Compression raises the pressure of natural gas in the reservoir so that it will flow into pipelines and other facilities. There are three segments to the field compression market:

–wellhead

–gas gathering

–processing

Compressors have historically been owned and operated by oil companies, but the U.S. is now approximately 1/3 outsourced to contract compression providers.

Gas Gathering Compression

OFS – Production: Well Servicing

Well Servicing refers to the maintenance procedures that take place on a well after the well has been completed and production from the reservoir has begun. It is done to sustain and enhance the productivity of the well. Key products/services include:

–Workover – the process of performing major maintenance or remedial treatment on a well.

–Coiled tubing – tubing used for the placement of fluids or manipulation of tools during workover

–Snubbing – the process of putting drill pipe into the wellbore when the BOPs are closed and pressure is contained in the well

–Plug and Abandonment – the process of preparing a well to be permanently closed

Source: Schlumberger, MTG

Workover rig

Coiled tubing unit

Source: Bristow Group, Superior Energy, Wartstila, MMS

Supply Boat

OFS – Drilling/Production: Offshore LogisticsHelicopters are used for transporting personnel between onshore bases and offshore platforms, drilling rigs, and installations.

Lift Boats are self-propelled, self-elevating vessels with a relatively large, open deck for carrying equipment in support of offshore exploration and production, and which can serve as a platform from which maintenance and construction work can be conducted.

Supply Boats are ships specifically designed to transport goods (i.e. drilling mud, cement, diesel fuel, chemicals, water, tools, etc) and personnel to and from offshore oil platforms and other offshore structures.

Lift Boat

Source: CalDive, Oceaneering

OFS –Production: Offshore ConstructionPipelay vessels use either the S-lay method in water depths <2K ft where pipe is laid into the water horizontally and bends twice in an S-shape, or the J-lay method in deep water where pipe is laid vertically and only bends once as it hits the seabed.Derrick barges have cranes used to lift heavy structures such as platforms/topsides.Diving support vessels (DSVs) support divers performing inspection, maintenance, repair (IMR) and welding. Surface divingcan be performed in depths up to 200 ft; saturation diving can be performed in 200-1,000 ft depths. Offshore Support Vessels (OSVs) are equipped with Remotely Operated Vehicles (ROVs) , tethered underwater robots used for IMR, construction and drill support in deep water.

Combination Pipelay/Derrick Barge

ROV

Company Specific Detail

OFS: Life Cycle Exposure and Selected Co’sLife Cycle Stage Oil Services Activities Examples of OFS Co's Life Cycle Stage Oil Service Activities Examples of OFS CO'sExplorationProspect ID Seismic Acq./Processing SLB, PGS.NO, CGV, DWSN Evaluation Open Hole Wireline Logging SLB, BHI, HAL

Reservoir Imaging HAL Coring CLBProduction Testing SLB, Expro

DrillingContract Drilling Land NBR, PTEN, HP Drilling Services Bits SLB, BHI, NOV

Shallow Water HERO, RDC Fluids SLB, HAL, BHIDeepwater RIG, DO, SDRL OCTG TS, X

Directional Drilling SLB, HAL, BHI, WFT

CompletionCasing Handling WFT, TESO"Tools" HAL, BHI ,SLB, WFTPressure Pumping HAL, SLB, BHI, CRR, CPX

ProductionOngoing Chemicals BHI, Nalco Well Servicing Workover Rigs KEG, NBR, BAS (Enhancement) Artificial Lift WFT, SLB, BHI LUFK Coiled Tubing/Intervention BHI, CPX, SPN

Nat Gas Compression EXH, NGS Fishing SLB, BHICased Hole Wireline Logging SPN

Logistical Support Supply Boats TDW, CKHHelicopter BRS

Equipment/InfrastructureDevelopment Engineering/Design TEC.FP, ACGY, SPM.IM Capital Equipment Rig Equipment NOV, Aker, CAM

Fabrication GIFI, MDR Drill Pipe NOV, VallourecInstallation HLX, GLBL Seismic Equipment IO, CGV

Production Unit/Equipment OISProduction Subsea/Surface Equip. FTI, CAM, Aker, TTS

Umbilicals OII, TEC.FPRisers/Flowlines GE (OG), DRQ

Geographic Revenue Segmentation (2010) Life Cycle Segmentation (2010)

Diversified Service Revenue by Product (2010)Diversified Service Revenue by Region (2010)

Source: Spears & Associates, Company data, Credit Suisse estimates

OFS: Diversified Service Segmentation

30%12% 6% 12%

64%84%

67%67%

6% 4%26% 21%

0%

20%

40%

60%

80%

100%

SLB HAL WFT BHI

Ex ploration Dev elopment Production

25%45% 40% 46%

33%

20% 37% 16%

42% 35%23%

38%

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

100%

SLB HAL WFT BHI

NAM Land Intl Land Offshore

21%

48%37%

49%20%

13%16%

12%23%

20%

13%18%9%

3%

7%

5%18%11%

20%9%

8% 6% 6% 8%

0%

10%

20%30%

40%

50%

60%

70%80%

90%

100%

SLB HAL WFT BHI

Other E Hemi

Middle East

Russia/FSU

Eur/Afr

LAM

NAM 6% 5%

16%6%

6% 10%

3%

3% 7%

15%

15%10%

16%

13%

12% 7%28%

21% 40%

12% 20%

3%

15%

7%16%

3% 13%8%

19%4%

17% 14%

6%2%

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

100%

SLB HAL WFT BHI

Other

Artificial Lift

Interv ention

Completion

Pumping

Other Drilling

Fluids

Dir Drilling

Bits

Wireline

Geophy sical

Com

pl.Pr

od'n

Drilli

ngEx

plor.

Source: Company data, Credit Suisse estimates

OFS: Equipment/InfrastructureCameron (CAM) FMC Technologies (FTI)National Oilwell Varco (NOV)

Oceaneering (OII) Dril-Quip (DRQ) Dresser Rand Corp (DRC)2010 Revenues = $12.7B 2010 Revenues = $6.1B 2010 Revenues = $4.1B

2010 Revenues = $1.9B 2010 Revenues = $0.6B 2010 Revenues = $1.9B

Rig Technology

55%

Distribution Serv ices

12%

Petroleum Serv ices &

Supply33%

Subsea26%

Rig Equipment17%

Process & Compression

Systems19%

Valves & Measurement

21%

Surface17%

Remotely Operated Vehicles (ROVs)

34%

Subsea Projects

13%

Adv anced Technology

12%

Subsea Products

29%

Inspection & NDT12%

Subsea Equipment

65%

Offshore Rig Equipment

16%

Serv ices14%

Surface Equipment

5%

Upstream50%

Other5%

Env ironmental15%

Dow nstream20%

Midstream10%

Surface16%

Subsea65%

Energy Processing

Sy stems19%

OFS: Market Shares for Key Services/Products

HAL29%

SLB24%

Trican5%

WFT4%

Calfrac4%

NBR1%

Others17%

Frac Tech5%

BHI11%

Pressure Pumping

Fluids Completions Artificial Lift Bits

Directional DrillingSeismic Wireline


2010 Revenues = $25.0B 2010 Revenues = $11.8B 2010 Revenues = $9.4B 2010 Revenues = $9.5B

2010 Revenues = $8.3B 2010 Revenues = $6.6B 2010 Revenues = $6.5B 2010 Revenues = $3.5B

BHI14%

SLB54%

SPN3%

WFT6%

Ex pro2%

China OFS2%

J-W Wireline

2%

Others6%

HAL11%

SLB36%

HAL20%

BHI18%

Scientific Drilling

4%

Others15%

WFT7%

SLB37%

Others8%

NOV2%

WFT2%

China OFS2%

NR7%

HAL27%

BHI11%

TTI4%

SLB29%

BHI28%

NOV19%

Others4%

HAL14%

Varel6%

HAL34%

BHI32%

SLB17%

Ex pro3%WFT

12%

Others2%

CGV25%

SLB17%

PGS9%

Fugro7%

Others22%

GGS2%

TGS5%

GOK5%

HAL8%

WFT20%

BHI17%

SLB16%

Others19%

Dov er6%

LUFK7%

Borets8%

WG.LN7%

OFS: Market Shares for Equipment/InfrastructureOffshore Construction

Compression

Surface Equipment

Subsea Tree Orders

Subsea Equipment

Source: Spears & Associates, Quest Offshore Resources

2010 Revenues = $29.9B 2010 Revenues = $10.9B

2010 Revenues = $2.4B


2010 Tree Orders = $6.7B

Saipem20%

KBR13%

MDR9%

Subsea 77%

OII2%

Others18%

DVR2%

GLBL2%

Technip3%

Fugro4%

Aker6%

SBMO7%

ACGY7%

CAM31%

FTI18%WG.LN

10%

Aker6%

Others21%

Weir SPM3%

TTES4%

GE7%

FTI25%

Technip17%

CAM15%

GE7%

Others9%

Aker14%

OII5%

WSM.LN4%

DRQ4%

EXH45%

Valerus5%

Others27%

Compr . Systems

6% J-W8%

CDM Resource

9%

FTI59%CAM

17%

AKER16%

GE8%

OFS: Market Shares for Rig EquipmentBlowout Preventers (BOP)

Top DrivesCementing Skids

Mud Pumps

Source: Spears & Associates, ODS Petrodata, Oceaneering

Total since ‘05 = 183 BOPs Total since ‘05 = 169 Mud Pumps

Total since ‘05 = 219 Skids Total since ‘05 = 167 Top Drives

Rig Equipment


Drill Support ROVs

Total = 747 Vehicles

NOV53%

CAM8%

Aker5%

OIS3%

Others24%

Bentec2%

GE5%

CAM43%

Hydril27%

Shaffer22%

NOV7%

CIW1%

NOV53%

LEWCO20%

Wirth20%

Others7%

NOV60%

Maritime Hydraulics

19%

Hydralift7%

Others14%

OII35%

Subsea 720%

Sonsub8%

Fugro7%

Canyon6%

Other24%

HAL41%

BHI23%

SLB34%

Other2%

OFS: Market Shares for Contract Drilling/OtherOffshore Contract Drilling

Petroleum Aviation Well Servicing

Land Contract DrillingSupply Vessels





CPX8%

KEG15%

NBR17%

Integra6%

BAS6%

PDS5%

Others43%

Maersk 12%

Bourbon14%

TDW16%

TRMA7%

CKH12%

Gulfmark5%

Others34%

PTEN6%

HP10%

PDC6%

ESI6%

WFT5%

Saipem4%

SLB4%

Other44%

NBR15%RIG

24%Other32%

ESV5%

SDRL9%

DO9%

NE7%

China OFS4%

PDE4%

KCA Deutag

3%

Maersk3%

Rotorcraft4%

BRS31%

Petroleum9%

CKH6%

Heli-Union2%

Others9%

CHC Helicopter

39%

OFS – Contract Drilling: Fleet Profiles

Fleet Profile by Company (all rigs)

Fleet Profile by Company (Floaters)

Source: ODS-Petrodata, note figures exclude newbuilds

Fleet Profile by Company (Jackups)

64

45 49

13 1428

3

50

17

23

5

4632

6

5

14

4

7

1

16

2

3

2

0

20

40

60

80

100

120

140

RIG ESV NE HERO DO SDRL RDC ATW

Jackup Semisubmersible Drillship Other (excl. platforms and barges)45 48

3036

71

18

2

11

1

16

2

7

22

214

0

10

20

30

40

50

60

70

RIG

HER

O

ESV

NE

RD

C

SDR

L

DO

ATW

NA

DL

Standard (< 300') Premium (> 300')

11

13

9

7

716

4 32

12

8

13

4

31

6

98

10

0

10

20

30

40

50

60

70

80

RIG DO ESV NE SDRL.OL ATW

Shallow Water Mid Water Deepwater Ultra Deepwater

OFS – Contract Drilling: Fleet Age & Growth TrendsEstablished U.S. Drillers vs. Others’ Fleet Age Deepwater Expansion: Fleet more than doubling

within 5 year span (2008 to 2013E)

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

219187174

140

99

214

120

0

40

80

120

160

200

240

2008 2009 2010 2011E 2012E 2013E 2014E

Dee

pwat

er (4

,500

ft.+

) Rig

Sup

ply

at y

ear-

end

6-year CAGR:14%

Order Trends:

Established U.S. Drillers

vs. Others in Recent

Order Cycles

31.7 30.8

27.424.6

21.9 21.719.0

16.1

0

5

10

15

20

25

30

35HE

RO DO NE RIG

ESV

ATW

Othe

r Avg

.

RDC

Aver

age

Rig

Age

(Yea

rs)

Established U.S. Drillers = 48% Total Global Fleet

3 4 4 41

41 3 1 3 4

1 16

25

34

6 5 6

26

36 4

5

103

36

11

10

1

3 32

1 1

1

1 14

11

4

9

41 1 2

11

8 6

2

118

1

3

37

61

5

8

9

2 2

2

1 2

13

8

14

0

5

10

15

20

25

30

35

1Q04

2Q04

3Q04

4Q04

1Q05

2Q05

3Q05

4Q05

1Q06

2Q06

3Q06

4Q06

1Q07

2Q07

3Q07

4Q07

1Q08

2Q08

3Q08

4Q08

1Q09

2Q09

3Q09

4Q09

1Q10

2Q10

3Q10

4Q10

1Q11

2Q11

# of

Rigs

Ord

ered

Established Drillers: Floating Rigs Other Drilling Co's: Floating RigsEstablished Drillers: Jackups Other Drilling Co's: Jackups

Fav orable global macro env ironment and drilling

fundamentals open the door for new entrants

Risk of obsolescence in light of commodity price stability +

fav orable y ard economics encourages established

drillers to order again; new er market entrants capitalize on

this too

THE DOWNSTREAM

The Downstream

Refining is the processing of raw crude into usable fuels called refined products: gasoline, diesel and jet. These products are sold into wholesale and retail markets.In the wholesale market, products are traded between large customers in global markets or on exchanges. These products are then sold into the retail market.In the retail market, petroleum products are sold to the end-user. The primary example of this gasoline or diesel sold at service stations.

Source: Company data, Credit Suisse estimates.

The downstream segment refers to all activities after crude is produced to when it is sold to the end-user.

Refining and marketing are the two key downstream components.

Petrochemicals are also included in downstream activities but are usually considered a separate segment.

Refining

Refining Basics

Refining is the process of turning crude oil into usable petroleum products. A refinery is the factory where this process takes place.When in operation, refineries run continuously. However, refineries do take downtime for planned reasons, such as upgrading a refining unit, or unplannedreasons, such as fires or other accidents.

Exxon Mobil’s Baytown, TX refinery

BP’s Texas City, TX refinery

Source: www.houstonist.com

Source: www.state.tx.us

Sunoco’s Philadelphia, PA refinery

Source: www.sunoco.com

Breaking Down a Barrel of Crude

The refining process splits crude oil into a variety of refined products.An example of the mix that comes from one barrel of crude oil is shown to the right.

To create these different products, a furnace first heats and vaporizes the crude. The vaporized crude is then piped into a crude distillation unit or CDU (referred to on the left as the Distillation Tower). Here, the vaporized crude naturally separates into different fractionsor cuts. The heavier cuts fall to the bottom of the CDU. This process is repeated several times until the cuts fully separate.

Source: www.eia.doe.gov


A Closer Look at Separation and Cuts

The heavier cuts generally create heavier refined products. The heaviness of a product refers to the length of its hydrocarbon chain. Heavier products tend to be less valuable than lighter products.The first cuts from the CDU do not produce usable refined products. Further treatment stages are needed, for example to turn naphtha into gasoline.

The temperature at which crude oil changes its product yields is called a cut point. At 220 degrees F an equal amount of gasoline and naphtha are produced. At 250 degrees F only 35% gasoline is yielded while the remaining 65% is naphtha. Controlling the cut point is a way to alter the product slate, which refers to the total product mix from a barrel of crude oil. The chart to the right illustrates various different cut points.

Source: Marathon Oil

From Fractions to Final Products

Once separation is complete, the various fractions are recondensed into liquid form. A typical barrel of light crude before any further treatment would look similar to the barrel shown on the right.

The product slate can then be further altered. Advanced upgrading units such as crackers and cokers treat products from the refinery’s first cut, generally breaking heavier fractions into lighter, shorter hydrocarbon chains. Examples of upgrading units are shown to the left. Not every refinery has each of these units.The more conversion units a refinery has, the more flexible it generally is in terms of final product slate. Conversion units also comprise a refinery’s complexity, which we discuss later.

Source: Bloomberg, Credit Suisse estimates

Source: www.zeonglobalenergy.com

Basic Upgrading Units: Reformer & Desulfurizer

A reformer has two functions. The first is to upgrade low octane naphtha into high octane reformate, a key component of high octane gasoline. The second function is to provide the hydrogen needed by a distillate desulfurizer. Octane measures how resistant a fuel is to self-igniting, which causes knocking. Knocking occurs when the engine backfires, wasting fuel and causing potential engine damage. Higher octane gasolines are more resistant to self-igniting.A desulfurizer or hydrotreater uses hydrogen to strip out naturally occurring sulfur from final refined products (gasoline, diesel, heating oil) in order to comply with modern environmental requirements.

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Reformer Desulfurization unit

Advanced Upgrading Unit: Fluid Catalytic Cracker (FCC)

A fluid catalytic cracker (also called an FCC or cat-cracker) is used to convert heavy crude elements into smaller, lighter elements through a process called cracking.FCCs mainly add to the gasoline final product stream of a refinery. Cracking occurs at temperatures of over 900 degrees F.

During cracking, a processing gain occurs: the cracking process yields more than the original amount of crude. 1.0 gallon of crude fractions yield 1.38 gallons of crude fractions after cracking.

The lightest cracked fraction, isobutene, goes to a gas processing facility to form propane and butane. Other light cat-cracked fractions are added to gasoline.

Middle-cracked fractions are blended with distillate. The remaining cracked fractions are sent to an alkylation unit, which is discussed on the next slide. The use of a deasphalter can also convert even more heavy fuel oil into additional fractions that can be run through an FCC.

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Advanced Upgrading Unit: Alkylation Unit

Cat cracked elements not sent to the gas-processing facility, blended, or cracked again are sent to an alkylation unit (shown below).– Alkylation is the reverse of fractionation: the process makes larger refined product components

from smaller molecules.

– A reverse processing gain occurs, as alkylation decreases yields. This is known as shrinkage.

– Paraffins, such as isobutane, are created in the gas-processing facility. These are combined with other olefins to form iso-paraffins, or alkylates. Alkylates are used as fuel additives to both boost the octane rating and make fuels cleaner-burning.

Source: Valero

Advanced Upgrading Unit: Delayed Coker

A delayed coker is used to convert low value fuel oil into higher value gasoline, gas oils and petroleum coke (used in the steel industry and elsewhere). The sample yields from a delayed coker are shown in the image below.

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Making Finished Gasoline

Even after crude is processed by the upgrading units, the products gasoline and diesel are not quite ready for market. Before entering the market, gasoline vapor pressure and octane ratings must be fine tuned.A gasoline with high vapor pressure is one that does not become ignitable until very high temperatures and pressures are reached. Refiners make different gasoline blends for different seasons. Winter blends, which come into use from September 15th, can have lower vapor pressure while summer blends are required to have a higher vapor pressure so that the gasoline does not inadvertently ignite in the warm weather.Higher octane gasoline corresponds with lower engine knocking. In addition to alkylates, lead, methanol and ethanol can be used as additives to increase the octane rating.

Source: www.answers.com

Making Finished Diesel

Diesel goes through two final processes before entering the market: hydrotreating and catalytic reforming.Hydrotreating removes sulfur and other contaminants from distillate so that the final product meets environmental specifications. Catalytic reforming increases low octane diesel to a higher octane level.

Source: www.i.treehugger.com

Where Does the Product Go Once It Is Refined?Once refined, products are transported to end-use sites such as retail stations. They can be transported by pipelines (shown to the right), trucks and ship. Pipelines are the cheapest form of transportation. Crude is also initially transported by these three means. Pipelines must be dedicated to either crude or refined product, not both.

If crude or product is not being used immediately, then it is stored in fields similar to the one to the left.



Examples of the Uses for the Products Created from Crude

Liquid petroleum gas (LPG) is the lightest product. These gases can include ethane, butane, and propane and are used both as chemical feedstocks and for outdoor cooking.

Light distillates are the next cut up from LPGs and include gasoline and naphthas. These are used as petrochemical feedstocks and automotive fuels.

Middle distillates can include diesel fuel, jet fuel, kerosene, and heating oil. These are used for jets, trucks and residential heating.

Cuts that are heavier than middle distillates are usually called “bottom of the barrel” products. These can be residual fuels such as fuel oil and are used to power ships and for power generation. Asphalt is also a “bottom of the barrel” product.

Source: G

oogle images

Refinery Operations

Ownership of Refining AssetsRefineries can be owned by both integrated oil and gas companies (with upstream operations) as well as by independent refiners. The distribution of ownership is shown to the right.Chevron and Exxon Mobil are two examples of integrated oil companies, sometimes referred to as Big Oil. The primary advantage of Big Oil owning refineries is that these companies can supply refinery operations using their own crude supply, although this doesn’t happen that much. The disadvantage is less flexibility in procuring crude from different producers.Independent refiners can be publicly traded like Valero or Tesoro or be privately owned such as Sinclair or Wyoming Refining. These companies can more easily buy crude from different producers and shop for the best possible price. However, the lack of upstream operations exposes independent refiners to crude price spikes and potential supply problems.

Source: OGJ

US Refining Capacity, by Ownership

Public independent 4.7 MMBD

27%

Private independent 3.3 MMBD

19%Integrated 9.4 MMBD

54%

Geographical DivisionIn the U.S., refinery locations are divided into five separate Petroleum Administration for Defense Districts (PADDs). Each region has different benchmark margins and legal specifications. The map below illustrates the PADDs. The next slide shows the percent of total U.S. refining capacity in each PADD and the distribution of ownership within each PADD. The slide after that shows additional yield, complexity and ownership details within each PADD.


Topic (1) WTI – Brent, Too Much Crude in the Mid-Con

Source: MPC

Intermediate Solutions Reliant on RailRail Loading Capacity Announcements

Significant rail loading capacity is being added in 2012 in the Bakken. Barging increasing from Patoka.

HES 130kbd

Rangeland 100kbd

EDOG 100kbd

Musket 70kbd

Infrastructure bottlenecks could include access to trains and offloading capacity

Total Tariff from Bakken to St James Louisiana of $10-12/bbl.

PADD 2 production growing at 200kbd pa annualized from recent up-tick. There should be sufficient rail capacity to transport this by 2Q12.

Significant drilled but not completed well inventory in the Bakken.

Source for all charts: Credit Suisse estimates, Bloomberg, DOE

PADD 2 Crude Growth Through Jun-2011

45 050 0

55 060 0

65 070 0

75 080 0

Jan-

09

Mar

-09

May

-09

Jul-0

9

Sep-

09

Nov-0

9

Jan-

10

Mar

-10

May

-10

Jul-1

0

Sep-

10

Nov-

10

Jan-

11

Mar

-11

May

-11

M id w es t (P AD D 2) F ield Pro du c t ion o f C rud e O il (T h ou san d

0

100

200

300

400

500

600

70020

10

2011

1Q12

2Q12

3Q12

4Q12

2012

2013

2014

2015

2016

2017

(KBD

)

WTI-Brent to Peak This Winter, Structurally Wider For LongerWTI-Brent Spread Futures Curve

Widening WTI-Brent has been a key theme in 2011. We have a mid-cycle supply-demand file which suggests a need for 2-3 pipelines to the Gulf

The likely peak of WTI-Brent should be this

winter as mid-con refineries shut for winter

maintenance and demand falls

As we move into 2012, increased rail capacity becomes available - $10-12/bbl from Bakken to the Gulf providing an alternative for E&P producers.

In 2013, Keystone XL adds pipeline capacity subject to 2H11 permit approvals and a successful construction program.

We need another pipeline in addition to XL –Enbridge, Energy Partners, Seaway Reversal in the frame.

Margin for error on supply not huge given potential from new plays e.g. Utica

Longer term Canada Still Grows – Exports to the West ?

….equally important where does WTI-Brent settle after the pipelines are built ?...

Source: Credit Suisse estimates, Bloomberg, DOE

Mid-Con Supply Demand Chart

$ 0

$ 5

$ 1 0

$ 1 5

$ 2 0

$ 2 5

3Q 1 1 1Q 1 2 3 Q 12 1 Q1 3 3Q 1 3 1 Q 14 3 Q1 4 1Q 1 5 3 Q 15

0

50 0

1 ,00 0

1 ,50 0

2 ,00 0

2 ,50 0

3 ,00 0

3 ,50 0

4 ,00 0

4 ,50 0

20 10 20 11 2012 2 01 3 2 014 201 5 20 16 2017

(KBD

)

Re fin ing P ip eline Ra il

Ta nke r + Ba rge S upply Growth

Most Projects Still Work at $60 Oil, Bakken Most SensitiveRates of Return at the Current Futures Strip and $60 per Bbl Oil

At $60 oil, Marcellus moves to the front of the pack, but Granite Wash and Eagle Ford still exceed the 15% rate-of-return hurdle rate. Bakken and Barnett (liquids-rich) projects are more at risk.

At the current futures strip the Granite Wash, Eagle Ford, Marcellus and Bakken remain the highest returning plays in domestic onshore E&P.

Sou

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Com

pany

Dat

a an

d C

redi

t Sui

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Estim

ates

53%

50%

37%

35%

27%

27%

26%

24%

22%

21%

19%

18%

18%

15%

15%

14%

12%

10%

8% 8% 6% 4%

26%

24%

36%

37%

12%

27%

19%

26%

24%

22%

12% 14% 18

%

18%

13% 15

%

11%

9% 10%

8%

6% 4% 4%

54%

0%

10%

20%

30%

40%

50%

60%

Granite

Was

h - Liquids R

ich H

oriz.

Eagle

Ford Shale

- Liquids R

ich

Marcell

us Shale

- SW Liquids R

ich

Marcell

us Shale

- SW

Bakke

n Shale / T

hree Forks

Sanish

Barnett

Shale - C

ore

Cana W

oodford Shale

Marcell

us Shale

- NE

Horn R

iver B

asin

Pinedale

Barnett

Shale - S

outhern Liquids R

ichHuro

n Shale

Eagle

Ford Shale

- Dry

Gas

Haynes

ville

Shale - C

ore LA / T

XBarn

ett Shale

Fayett

eville

Shale

Woodford Shale

- Arko

ma

Picean

ce B

asin Vall

ey

Granite

Was

h - Horiz

.

Haynes

ville/

Bossier

Shale - N

E TX

Cotton Vall

ey Vert

ical

Cotton Vall

ey H

orizontal

Powder Rive

r CBM

Current Futures Strip $60/Oil and Nat Gas at Futures Strip

Even After Pipelines are Built to Gulf, Challenges RemainStructural Oversupply Versus Refining Capacity

Even after all required pipelines are built to the Gulf Coast, refinery bottlenecks need to be considered

The line on the chart shows the available light processing refining capacity in the Mid-Con and the Gulf after heavy processing capacity is stripped out

By 2014, onshore crude supply could exceed this light processing capacity.

Were this to occur, there would need to be crude exports from the Gulf to the North East

In this scenario WTI would trade $3-4/bbl below LLS but LLS would trade $2-3/bbl below Brent…i.e. a $5-7/bbl WTI-Brent spread into the longer term

POSITIVE LONGER TERM MARGINS AND FREE CASH FLOW FOR MID CON REFINERS AND IN THE GULF

SKITTISH EQUITY MARKET LIKELY WELCOME HEDGES

Source: Credit Suisse estimates, MPC

Theoretical Cost to Move EagleFord to PADD I

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

2009 2010 2011 2012 2013 2014 2015 2016 2017

KBD

GoM Padd 3 (Core)Texas (ex-Eagleford) BakkenPadd 2 (Core) Padd 4 (Core)Eagleford NiobaraMississippian UintaLight Crude Capacity

Division by Ownership Type and PADD

Source: OGJ.

US Refining Capacity, by PADD

PADD III 8.4 MMBD

48%

PADD IV0.6 MMBD

4%

PADD V, 3.1, 18%

PADD I1.6 MMBD

9%

PADD II3.6 MMBD

21%

PADD IPrivate independent 0.1 MMBD

6%

Public independent

1.1 MMBD67%

Integrated 0.4 MMBD

27%

PADD II

Private independent 0.7

MMBD20%

Public independent 0.8

MMBD21%

Integrated2.1 MMBD

59%

PADD III

Integrated4.9 MMBD

58%

Public independent

1.7 MMBD20%

Private independent

1.9 MMBD22%

PADD IV

Integrated0.3 MMBD

47%

Public independent0.1 MMBD

21%

Private independent

0.2 MMBD32%

PADD V

Integrated1.6 MMBD

52%Public

independent1.1 MMBD

34%

Private independent0.4 MMBD

14%

Refinery Summary, by PADD and Company

Source: Credit Suisse estimates.

Oil Product Marketing

Introduction to Marketing

Marketing is divided into wholesale and retail segments. Profits from the marketing division tend to be more stable than those from the refining division.The wholesale market component involves the trade between large customers in global markets or on exchanges. These products are then sold into the retail market.

The retail market encompasses the sale of petroleum products to end-use markets and serve end users on a spot, transactional basis. The most common form of retail distribution is through the service station Benchmark margins for the U.S. retail segment since 1995 are shown above.

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ates

Composite Retail Margins Historical 4-week moving average 1995-Present

-

10

20

30

40

50

60

70

Jan-

95Ma

r-95

Jun-

95Se

p-95

Dec-9

5Fe

b-96

May-

96Au

g-96

Nov-9

6Ja

n-97

Apr-9

7Ju

l-97

Oct-9

7De

c-97

Mar

-98

Jun-

98Se

p-98

Nov-

98Fe

b-99

May-9

9Au

g-99

Nov-

99Ja

n-00

Apr-0

0Ju

l-00

Oct-0

0De

c-00

Mar-0

1Ju

n-01

Sep-

01No

v-01

Feb-

02Ma

y-02

Aug-

02Oc

t-02

Jan-

03Ap

r-03

Jul-0

3Se

p-03

Dec-

03M

ar-0

4Ju

n-04

Aug-

04No

v-04

Feb-

05Ma

y-05

Aug-

05Oc

t-05

Jan-

06Ap

r-06

Jul-0

6Se

p-06

Dec-0

6Ma

r-07

Jun-

07Au

g-07

Nov-0

7Fe

b-08

May-

08Ju

l-08

Oct-0

8Ja

n-09

Apr-0

9Ju

n-09

Sep-

09De

c-09

Mar

-10

May-1

0Au

g-10

Nov-

10Fe

b-11

May-1

1Ju

l-11

Oct-1

1

(cent

s/gal)

Retail Margins Key to Profitability of the Marketing Business

The retail division tends to have a much greater percentage of the profit than the wholesale division owing to higher margins, so we focus on this part.Below, there are two charts of historical retail benchmark margins (excluding taxes). The left chart is for U.S. retail margins while the right chart is for retail margins in NorthWest Europe. The retail business is highly competitive and operators compete on both price and product quality.

Source: www.eia.doe.gov, Credit Suisse estimates

U.S. Retail Margins NorthWest Europe Retail Margins

2 0

3 0

4 0

5 0

6 0

7 0

8 0

Jan-

11

Jan-

11

Feb-1

1

Mar-1

1

Apr-1

1

May-1

1

Jun-1

1

Jul-1

1

Aug-

11

Sep-

11

Oct-1

1

Nov-1

1

Dec-1

1

(cen

ts/g

al)

5Y R A v g 20 11 20 10

-

1 0

2 0

3 0

4 0

5 0

6 0

Jan-

11

Feb-

11

Mar-1

1

Apr-1

1

May-1

1

May

-11

Jun-

11

Jul-1

1

Aug-

11

Sep-

11

Oct-1

1

Nov-1

1

Dec-1

1

(cen

ts/ga

l)

5 YR A vg 20 1 1 20 10

More on the Retail Segment

Previously a gas station used to be just that…a gas station. To attempt to generate additional profits many gas stations now have convenience storesselling merchandise and food.Retail operators purchase fuel under long-term or short-term supply agreements either with oil companies (called branded) or from independently owned distributors.Big Oil and Independent Refiners have marketing and distribution costs associated with gasoline normally making it more expensive. Using unbranded gasoline can allow a retail station a wider profit margin. However, the quality and public perception of branded gasoline versus unbranded gasoline is different.As of July 2011, the federal fuel tax in the U.S. was 18.40 cents per gallon for gasoline and 24.40 cents per gallon for diesel. The average state tax for fuel was around 30.50 cents per gallon for motor gasoline and 29.60 cents per gallon for diesel.

Retail Prices Tend to be Sticky

One final note about retail gasoline and diesel prices is that they tend to lag changes in wholesale prices, which makes the business somewhat seasonal.During the summer driving season, the run up in gasoline and diesel prices tend to support retail margins. Sharp moves up or down in crude can also narrow or expand retail margins, respectively.Total marketing margin = wholesale margin + retail margin

Source: Google Images

INVESTING IN BIG OIL

What is an Integrated Oil Company?

Integrated oil companies (IOCs) are present throughout the oil and gas chain, from upstream production to refining and distribution.

Typical divisions include E&P (exploration and production), R&M (refining and marketing), and sometimes chemicals, gas & power.

The Super Majors are global in scope, while Emerging Majors tend to be more local.

National Oil Companies (NOCs) in resource-rich regions are becoming more global.

Super Majors Other NOCs Emerging Majors

Source: Google images

Background

Super Majors– These large global integrated oil companies (IOCs) were formed from a wave of mergers that

took place between 1998 and 2003. – Typically show little volume growth and questions remain over reinvestment strategy.– Generous dividends and share buybacks characterized the upcycle.

Other– Smaller than the Super Majors and usually with a higher concentration of assets in select

regions (i.e. U.S., North Sea).– Usually more leveraged to commodity prices.

National Oil Companies (NOCs)– Fully or majority owned by national governments.– Some have recently started to reach beyond home areas.

Emerging Majors– Partially state-owned oil companies with public equity.– Have also begun to expand their operations beyond domestic borders.

Super Majors (XOM, ENI, CVX, COP, TOT, BP, RDS)

In spite of significant reserve bases, the Super Majors have found it hard to grow production recently versus their peers. They exhibit high return on capital, while Emerging Majors and NOCs dominate the production growth rankings.

The Super Majors are mainly focused on large projects that can substantially increase their reserve base and compensate for significant base production declines.

Total Oil & Gas reserves – Super Majors (mmboe)

Sour

ce: C

redi

t Sui

sse

estim

ates

78,214

82,873

85,527

90,10690,795

88,98589,892

91,643

87,82588,724

91,654 91,684

70,000

75,000

80,000

85,000

90,000

95,000

1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

Integrateds: Sensitivities

XOM Correlation

y = 0.2253x + 1.4425R2 = 0.9457

0

5

10

15

20

25

30

0 20 40 60 80 100 120 140WTI, US$/bbl

Net I

ncom

e, U

S$/b

bl

Typical Integrated Sensitivity vs Oil Price Typical Integrated Sensitivity vs Oil Price

12mth rolling Avg Oil 12mth rolling Avg Gas

Source: Credit Suisse estimates

% Net Incom e change for +1$/bbl change in OIL

0.0%

0.2%

0.4%

0.6%

0.8%

1.0%

1.2%

HES STL CVX BP MRO OMV XOM COP TOT BG RDS

% Net Incom e change for +1$/boe change in GAS

0.0%

0.2%

0.4%

0.6%

0.8%

1.0%

1.2%

BG CVX MRO STL COP BP HES XOM RDS TOT OMV

y = 0.4674x-0.9256

R2 = 0.7824

0.0%0.5%1.0%1.5%2.0%2.5%3.0%3.5%4.0%4.5%5.0%

0 20 40 60 80 100 120 140

Sens

itivi

ty

XOM Correlation

WTI, US$/bbl

Profitability – Upstream Driven

Total returns for the Integrated Oils are driven by the upstream segment, although chemicals has been on an upswing.

Even in their best years, the downstream and chemicals segment performances have generally not been comparable to the upstream.

ROGIC (%) – Segment*So

urce

: Cre

dit S

uiss

e es

timat

es

*US Integrated Oils only

0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

ROGIC - upstream ROGIC - downstream ROGIC - chemicals

Segment breakdown – Upstream Driven*

The upstream has been a consistent outperformer

The relative outperformance of the upstream has led integrated oil companies to increase reinvestment spending in the business

ROCE - Segments Segmental capex

Source: Company, Credit Suisse estimates.

*US Integrated Oils only

14.0%15.7%

20.2%

23.0% 23.3%

3.7%5.0%

7.4%

11.8%13.2%

4.9%

19.9%

10.1% 10.6%9.4%

0%

5%

10%

15%

20%

25%

2009 2010 3-yr avg 5-yr avg 10-yr avg

Upstream Downstream Chemicals

0

10

20

30

40

50

60

70

80

90

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010E 10-yravg

5-yr avg 3-yr avg

Cap

ex ($

bn)

Upstream Downstream Chemicals

-9%

0%

-11%

-21%

-5%

18%

5%

9%

-4%

17%

12%

18%

24%

15%

3%

-27%-30.0%

-25.0%

-20.0%

-15.0%

-10.0%

-5.0%

0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

30.0%

1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

RecessionRecession

Performance

The Integrated Oils are a classic defensive investment class. They generally outperform during broad market downturns as these periods often coincide with rising energy price environments.

Integrated Oils vs. S&P500

Source: Credit Suisse estimates.

*Estimated end of recession as per St. Louis Federal Reserve Bank

Characteristics

The Integrated Oils are the most conservative oil and gas investment compared to the more volatile Independent E&Ps and hyper-volatile Oilfield Service shares. They tend to perform better than the other oil and gas industries as the cycle shifts from peak to trough, but will likely underperform the highly leveraged E&Ps and Service companies when oil and gas fundamentals improve.

CVX

XOM

RDS

HES

MRO

SU

TOT

PCA

STO

REP

BG

IMO

ENICOP

BP

0.6

0.7

0.8

0.9

1

1.1

1.2

1.3

1.4

1.5

Average Integrateds Relative P/E vs. S&P500 Low Beta

Source: Company, Credit Suisse estimates.

0%

20%

40%

60%

80%

100%

120%

140%

160%

1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010

OUTLOOK FOR BIG OIL

Under-appreciated Cash Flow Growth

– XOM, RDS and COP should deliver best in class growth+dividend yield

Potential Longer Term Cash flow Growth and Divs

Source: IEA, JODI, Credit Suisse Estimates

CFPS Drives 2015 Multiples Lower

0.0%

2.0%

4.0%

6.0%

8.0%

10.0%

12.0%

14.0%

XOM CVX HES COP RDS MRO TOT ENI BP

10 - 17 CAGR - Adjusted Total CFPS 2011 Div Yield

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

XOM

COP

HES

TOT

EOG

RDS

ENI

BP OXY

MRO

CVX

Historical Multiple, 5 yr Average (IOCs)

Big Oil’s – Portfolio Shift and Performance Prize

Sou

rce

for a

ll ch

arts

: XO

M, C

redi

t Sui

sse

estim

ates

Portfolio Shifting to Long Duration Projects

Higher share of longer lived projects helps Big Oil manage the reinvestment treadmill. Longer lives should be correlated with higher multiples

On $120bn of upstream capex, a 10% performance improvement translates into 1% additional FCF yield

10% improvement in cost equals 1% FCF yield

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

50%

COP CVX XOM BP RDS TOT ENI

Shar

e of L

ong

Dura

tion

Long Duration, 2009 Long Duration, 2017

Higher Cash Margins on New Upstream ProjectsOperating Cash Flow per Barrel on Selected New Projects (2011-15 Start-ups)

Source: Credit Suisse Estimates

– Cash margins on projects starting up in 2011-15 are up to 30-40% higher than existing production

– Margins are highest on Canadian oil sands (mined), GTL, US GoM deepwater and offshore West African projects (partly due to the timing of cost recovery)

$-

$1 0

$2 0

$3 0

$4 0

$5 0

$6 0

$7 0OM

L 13

8/139

(Usa

n/UKO

T)

Jack

/St M

alo

Whe

atsto

ne

Kash

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Pear

l GTL

Akpo

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CLOV

Gorg

on

Bloc

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SVM

Quee

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Mars

B

Pazfl

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lock 1

7

APLN

G

AOSP

- Ba

se +

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Golia

t

Qatar

gas 4

Skar

v

Tupi

(BM

-S-11

)

Junin

5

Guar

a (B

M-S-

9)

Rum

aila

Yem

en LN

G

ACG

Grou

ndbir

ch

MLE

& C

AFC

(405

b)

Stocks are discounting a double dip

Sou

rce

for a

ll ch

arts

: Com

pany

dat

a, C

redi

t Sui

sse

estim

ates

Pessimism in future returns by company

Big Oil should generate CFROI of 6-8% at $80/bbl

Stocks are discounting only 2-5%CFROI

Big Oil would generate this CFROI on less than $60/bbl

Embedded returns lower than 2010

0

2

4

6

8

10

OXY

CVX

XOM

TOTF

HES

BP COP

RDSb

OMVV

STL

ENI

REP

MRO

CFROI, FY1 CFROI, Embedded

0.0

2.0

4.0

6.0

8.0

10.0

12.0

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011E

Embedded CR

FOI

(%)

0

20

40

60

80

100

120

140

($/bbl)

Average CFROI (LHS)Consensus Brent (RHS)

INVESTING IN E&P

Evaluating E&Ps: Key MetricsProducers seek to create value by adding, producing and selling oil and natural gas reserves at a return greater than their cost of capital. There are several key metrics that help quantify producer performance:

– Reserve per Share Growth: Basic measure of a producer’s ability to add reserves. Industry average growth over the past five years has been about 8-10% annually.

– Reserve Replacement Ratio: A measure of reserve adds compared to production. Reserve replacement of >100% indicates incremental reserves were added net of production.

– Reserve Life: Indication of inventory depth by comparing how many years of reserves a producer has at current production. Median industry reserve lives are currently ~12.0 years.

– Recycle Ratio: Compares cash flow ($ per Boe) with finding and development costs ($ per Boe). A recycle ratio of 1 is a “breakeven point,” indicating that a producer is replacing what was produced. Industry three-year median is 1.9x.

– Reinvestment Rate: Reinvestment rates of > 100% indicate a producer will be free cash flow negative.

– PUD Percentage: Measures proved undeveloped (PUD) against total reserves. Higher relative PUD percentage will likely mean higher future capital needs to develop existing reserves.

Evaluating E&Ps: Cost Considerations

All producers are essentially price-takers. Therefore a key differentiating factor among producers is the ability to control both capital and operating costs.

– Capital Costs – The costs associated with exploring for and developing oil & natural gas reserves. These include drilling and development costs (contracting a rig and crew), acreage costs, geological costs (seismic) and midstream (developing gathering lines).

Measured by finding & development (F&D) costs – unit cost to replace 1 unit of reserves.

The historical 3-year industry median F&D cost is ~$2.60 per Mcfe.

– Operating Costs – Producer cost structures include field level costs (LOE) related to the operation of a well, production taxes, DD&A, G&A, and interest expense.

LOE tends to mirror movements in commodity prices due to energy related inputs (eg. power/electricity, natural gas), but can sometimes be lagged and/or downward sticky.

Production taxes are calculated as a percent of revenues and are directly related to changes in prices.

The average industry total cost structure was about $5.63 per Mcfe as of 4Q10.

Evaluating E&Ps: Hedging

Producers use derivative instruments to protect against volatility in commodity prices.

Common instruments: (1) swaps, (2) collars, (3) floors, and (4) natural gas basis swaps

Basis swaps protect regional gas prices by locking in differentials to NYMEX.

Hedging only protects near term cash flows. As hedges roll off, producers are forced to re-hedge at prevailing commodity prices.

Timing of when to put on hedges is an important management consideration.

Sample Natural Gas Collar ($ per MMBtu)

$0.00

$2.00

$4.00

$6.00

$8.00

$10.00

$12.00

$14.00

Jun-08

Jul-0

8

Aug-08

Sep-08

Oct-08

Nov-08

Dec-08

Jan-09

Feb-09

Collar Floor protects against downside volatility

Source: Bloomberg, Credit Suisse.

Evaluating E&Ps: Valuation

The primary tools we use for valuing producers are Net Asset Value and Multiples.– Net Asset Value (NAV): An NAV is a discounted cash flow analysis of a producer’s

reserves.

In deriving an NAV, assumptions are made on future commodities prices, production rates, operating costs, finding & development costs, and life of reserves.

NAVs can be run on a producers 3P reserves (All-in NAV), proved reserves only, or proved-developed reserves. The choice of which NAV to use depends on the outlook for the producer to find, develop and produce out the reserves that will be discounted.

NAVs per share is compared to a producer’s stock price. Price to NAV > 100% suggests that a stock is over-valued (based on valuation assumptions).

– Multiples: The most commonly followed valuation multiple within the E&P sector is EV to EBITDA.

Recently, lack of visibility on future commodity prices have shifted valuation focus away from NAVs and placed EV to EBITDA multiples more in favor

Historically the group has traded at 6.0x EBITDA.

INVESTING IN OILFIELD SERVICES & DRILLING

OFS: The Traditional Upstream Spending Cycle

North America leads the upturn, international markets lag

Int'l markets, deepwater markets accelerate and cycle approaches peak earnings

Change in macro environment precipitates decline in commodity prices

North American independents curtail upstream spendingCycle begins with

upturn in commodity prices

North America generally leads in a resumption in upstream spending because more of the activity is conducted by smaller (and therefore more nimble) operators (E&P companies). With shorter time horizons, generally, the North American operators are also the first to curtail spending in a downturn

OFS: Oil Services Activities Through the Cycle

Production related services are the most resilient and the earliest to “revive”, but traditionally have the lowest Beta. Secular challenges related to hydrocarbon production have sustained higher-than-expected growth in the latest upcycle.

With more confidence in sustained higher commodity prices, drilling and completion related activity responds. Exploration is generally the last to strengthen and the first to fall in a downturn in oil prices.

As Drilling and Completions activity picks up, beneficiaries include rig count driven companies selling drilling materials (e.g. bits, fluids) - margins improve quickly as manufacturing absorption issues dissipate.

Companies with solid positions in International markets as well as deepwater/remote areas benefit from pick up in international activity. Key beneficiaries: Large caps, deepwater drillers

Oil companies increasingly focus on new Prospect Identification as existing prospects have been developed. Seismic companies are key beneficiary.

Companies that (1) Install Infrastructure for new developments (Production) and (2) provide new drilling rig equipment tend to see fastest earnings growth later in the cycle. Stocks respond to backlog growth in middle stages of the cycle.

Initial activity includes Well Servicing and Production Enhancement, i.e. the fastest way to take advantage of higher commodity prices is not through the drill bit. Beneficiaries: pressure pumpers, workover drilling contractors

Drilling Services companies experience price leverage as rig count rises and service utilization increases.

OFS: Stocks Directionally Correlated with Upstream Spending

Note the strong directional correlation between spending patterns and the stocks as expectations for future upstream spending have historically been a significant driver of relative OFS stock performance.

OFS stocks tend to be highly anticipatory and move ahead of changes in spending patterns.

02468

101214161820

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

Qua

lRig

($bi

l)(M

onth

ly D

rill.

& C

ompl

. Spe

ndin

g)

0.00.51.01.52.02.53.03.54.04.55.05.5

OFS

Rel

ativ

e St

ock

Inde

x

Worldwide QualRig OFS Relative Stock Performance

OFS: Gross Revenues Drive Upstream Spending

Spending trends tend to follow producer gross revenues (production times commodity prices)

Historically, spending trends tend to follow 18-month average of gross revenue at a reinvestment rate of approximately 11-12%.

20

40

60

80

100

120

140

160

180

200

220

240

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

E

2012

E

Mon

thly

WW

Pro

duce

r Gro

ss R

even

ue (1

8-M

o. A

vg)

2

4

6

8

10

12

14

16

18

20

22

24

Qua

lRig

($bi

l)M

onth

ly D

rillin

g &

Com

plet

ion

Spen

ding

($bi

l)

Worldw ide QualRig Average Yearly QualRig

OFS – Contract Drilling: Offshore Drillers

Dayrates and utilization are key drivers of driller earnings power

Worldwide Semi Dayrate/Utilization

Source: ODS-Petrodata

Worldwide Jackup Dayrate/Utilization

$0

$40,000

$80,000

$120,000

$160,000

$200,000

$240,000

$280,000

$320,000

$360,000

$400,000

$440,000

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-

11

WW

Sem

i Day

rate

s

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

WW

Sem

i Util

izat

ion

WW Semisubmersible Dayrates WW Semisubmersible Utilization WW Avg. Semisubmersible Utilization

Average = 83.9%

$0

$20,000

$40,000

$60,000

$80,000

$100,000

$120,000

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-

11

WW

Jac

kup

Day

rate

s

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

WW

Jac

kup

Util

izat

ion

WW Jackup Dayrates WW Jackup Utilization WW Avg. Jackup Utilization

Average Utilization = 83.3%

OFS – Contract Drilling: Offshore DrillersStocks are generally correlated with dayrate trends

Source: ODS-Petrodata

$0

$50,000

$100,000

$150,000

$200,000

$250,000

Dec-9

1

Dec-9

2

Dec-9

3

Dec-9

4

Dec-9

5

Dec-9

6

Dec-9

7

Dec-9

8

Dec-9

9

Dec-0

0

Dec-0

1

Dec-0

2

Dec-0

3

Dec-0

4

Dec-0

5

Dec-0

6

Dec-0

7

Dec-0

8

Dec-0

9

Dec-1

0

Offs

hore

Day

rate

s

0.00

2.00

4.00

6.00

8.00

10.00

12.00

14.00

16.00

CSFB OFS Index: Absolute Performance CSFB OFS Index: Relative Performance WW Offshore Dayrates (unweighted)

0.81

Relative R-squared = 0.79

Absolute R-squared =

OFS: Traditional Valuation Methodologies

Services – as an earnings momentum group, we believe shares have generally been valued on forward year P/E and to a lesser extent forward EV/EBITDA. During trough periods, P/E or EV/EBITDA is applied to normalized or “mid-cycle” earnings estimates

Equipment – the backlog visibility, which can extend out as far as three years, lends itself to DCF. However, forward earnings metrics are also used

Drillers – with high asset intensity associated with owning the rigs, and different depreciation methods used by the companies, the industry tends to use forward year P/CF (EV/EBITDA). In the recent upcycle, backlog visibility lends itself to DCF. In troughs, replacement value metrics are also used

Offshore Asset Replacement Cost Trend

Diversified Service Forward P/E Trend

0.0%

20.0%

40.0%

60.0%

80.0%

100.0%

120.0%

140.0%

160.0%

180.0%

Q19

7

Q39

7

Q19

8

Q39

8

Q19

9

Q39

9

Q10

0

Q30

0

Q10

1

Q30

1

Q10

2

Q30

2

Q10

3

Q30

3

Q10

4

Q30

4

Q10

5

Q30

5

Q10

6

Q30

6

Q10

7

Q30

7

Q10

8

Q30

8

Q10

9

Q30

9

Q11

0

Q31

0

Q11

1

Cur

rent

Current = 81%

Maximum = 166%

Minimum = 41%

0

5

10

15

20

25

30

Dec-

04Fe

b-05

Apr-0

5Ju

n-05

Aug-

05Oc

t-05

Dec-

05Fe

b-06

Apr-0

6Ju

n-06

Aug-

06Oc

t-06

Dec-

06Fe

b-07

Apr-0

7Ju

n-07

Aug-

07Oc

t-07

Dec-

07Fe

b-08

Apr-0

8Ju

n-08

Aug-

08Oc

t-08

Dec-

08Fe

b-09

Apr-0

9Ju

n-09

Aug-

09Oc

t-09

Dec-

09Fe

b-10

Apr-1

0Ju

n-10

Aug-

10Oc

t-10

Dec-

10Fe

b-11

Apr-1

1Ju

n-11

Aug-

11

P/E

Prior Cy cle('96-mid '98)High = 25.8xAv e. =

Nov '04 - Aug '08:High = 24.3xAv e. = 17.0x

Current = 11.6x

OFS: IndicatorsLeading Indicators– Seismic – Licensing rounds, Oil company exploration budgets, Sustained higher commodity

prices

– Drilling and Completion – Oil company spending budgets (generally set early in the calendar year, although they are revised intra-year), Permitting activity

Coincident Indicators– Oil and natural gas prices

– Earnings. As a traditionally earnings momentum-driven group, quarterly earnings matter.

– Pricing (day rates for drillers). Contract drilling shares are generally highly correlated with the trajectory of day rates.

– Rig count. North American rig counts are updated weekly (sources include Baker Hughes, M-I) or bi-weekly (The Land Rig Newsletter). Non-North American rig counts are updated monthly

OFS: Secular Trends

Resource Nationalism. The recent upcycle/strength in commodity prices facilitated/was coincident with several countries becoming less accommodating to outside oil companies; this manifested itself in both contractual changes to lower oil company ownership stakes and higher taxes.

New Frontiers. Related to the above, international oil companies are being pushed to explore/exploit more challenging and higher cost environments to access hydrocarbons in their quest to grow reserves/production, including more offshore (and deeper waters).

Gas Monetization. The upcycle has seen more natural gas development (20% of the non-North America (non-NAM) rig count versus 15-18% in the 1998 cycle). Although the OFS activities are essentially the same, natural gas tends to be more lucrative than oil as it is often deeper (=higher pressure and temperature) and presents corrosion challenges.

NAM unconventional gas. The recent upcycle has seen the “unlocking” of NAM gas shales, including the use of horizontal drilling and aggressive multi-zonal completion techniques (including very large fracturing jobs). The shales plays are thought to be 2-5x more service intensive than traditional wells.

Bundling. The combination of human resource constraints at oil companies, more challenging reservoirs and demonstrated efficiencies are leading to more tendering for products and services on a bundled basis. This is driving organizational changes to meet this demand within service companies.

INVESTING IN REFINING

Refining Margins Drive Refinery ValueRefining earnings are driven by refining margins (also called cracks or crack spreads). Cracks are normally quoted gross, for example, as the difference between the prices of refined products and the price of the crude feedstock, before operating costs.

Barrel of crude Finished productRefinery – processing center

There are four major determinants of margins. The first is crude cost, which is effectively the cost of goods sold. The second is finished or end product price. The higher this is, the wider the crack spreads. The third is refinery complexity or yield. More complex refiners run less attractive (cheaper) crudes and produce a higher yield of light products. The fourth determinant is regional supply/demand, mainly concerned with local market conditions and regulations.

Sou

rce:

Goo

gle

imag

es

How to Calculate Benchmark Refining Margins

Benchmark refining margins attempt to give a rough overview of the current profitability of the refining industry. To calculate a benchmark margin, we assume that one barrel of crude from a region is then transformed into a standard suite of refined products. For instance, the Gulf Coast benchmark 3:2:1 margin (for PADD III) assumes that three barrels of WTI crude oil are turned into two barrels of gasoline and one barrel of middle distillates. Above we show an example of this calculation.Benchmark margins vary for each region. For instance, the New York Harbor (PADD I) uses a 6:3:2:1 margin, which assumes that six barrels of Brent crude oil are turned into three barrels of gasoline, two barrels of distillate, and one barrel of “bottom of the barrel” products or residual fuels.

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US$/gal US$/bbl (x 42)Gasoline 1.95 81.90 x 2/3 54.60Distillate 1.74 72.93 x 1/3 24.31Product price 78.91WTI crude 68.59 x 1 68.59Gulf Coast 3:2:1 refining margin 10.32

Why We Use Theoretical Benchmark Margins

We can also look at individual crack spreads, such as what would one barrel of gasoline trade for above one barrel of WTI crude oil.One barrel of crude cannot actually transform into one barrel of gasoline (or any other product), however this is the convention in discussing gasoline cracks or distillate (heat) cracks. A NYMEX gasoline crack of $3.64/bbl means that one barrel of gasoline is currently trading at a $3.64 premium to one barrel of WTI crude. We illustrate recent gasoline and distillate crack spreads in the chart above.

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$(5)

$-

$5

$10

$15

$20

$25

$30

$35

1Q1999

4Q1999

3Q2000

2Q2001

1Q2002

4Q2002

3Q2003

2Q2004

1Q2005

4Q2005

3Q2006

2Q2007

1Q2008

4Q2008

3Q2009

2Q2010

1Q2011

$/bbl

Gasoline Distillate

Additional Variables: Utilization Rates

The actual throughput for a refinery is known as its crude run. Crude runs can be less than nameplate capacity due to planned or unplanned downtime or due to an economic decision to reduce operating rates in the face of weak margins. The crude run divided by the crude capacity is known as the utilization rate. If a refinery can process 100 KBD of crude but crude runs are only 90 KBD, then the utilization rate is 90%. Utilization rates are seasonal and usually increase in the summer when US demand for gasoline is greater.

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70

75

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95

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89

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91

Sep-

93

Sep-

95

Sep-

97

Sep-

99

Sep-

01

Sep-

03

Sep-

05

Sep-

07

Sep-

09

US

refin

ing

capa

city

dis

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tion

utili

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n %

Additional Variables: Complexity

Refineries are often divided into two categories: simple and complex. In reality complexity is measured on a continuum. One commonly used measure of complexity is the Nelson Complexity Index. The Nelson index dates from 1960 and assigns a separate complexity factor to each piece of equipment in a refinery (see LH picture below). The factor assigned is normally based on the piece’s cost relative to the crude distillation unit (CDU), which is assigned a complexity factor of 1.0.Below the complexity of Kuwait’s Mina Abdulla refinery is calculated. The index for vacuum distillation, for example, is 1.11, calculated as [134,000 / 242,000] x 2).

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-$0.10

$0.00$0.10

$0.20$0.30

$0.40

$0.50$0.60

$0.70$0.80

$0.90

1Q98

3Q98

1Q99

3Q99

1Q00

3Q00

1Q01

3Q01

1Q02

3Q02

1Q03

3Q03

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3Q04

1Q05

3Q05

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3Q06

1Q07

3Q07

1Q08

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3Q09

1Q10

Gas

olin

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Spr

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/gal

)

$0

$5

$10

$15

$20

$25

WTI

-May

a S

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d (U

S$/

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Gasoline-Resid WTI-Maya

Why Not Make Every Refinery Complex?

Complex refineries can run different types of crude, quickly change product slates and produce more higher value products, so why not make every refinery complex? The upfront capital costs to add complexity are high and maintenance can be expansive. For some locations, more simple refineries may make sense.Above, we show historic crude and product differentials. A greater differential in the light-heavy spread favors complex refineries who run heavier crude but produce a similar light product yield to a simpler refinery processing light crude. Higher differentials between gasoline and residual fuel oil favor complex refiners, many of whom do not produce any fuel oil as a final product.

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Example of the Economics for a Simple vs. Complex Refinery

As illustrated above using two hypothetical Singapore refineries, 2008 year-end product pricing, and Dubai crude, a complex refinery generates a substantially higher cash margin than a simple refinery. Note that the percentages do not add up to 100%, as some refinery fuel and energy is lost in the process.While the difference in margins is appreciable, so is the cost of building a complex plant. In practice, complex refiners adapt their yield patterns to suit the market conditions prevailing at the time.

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Singapore complexUS$/bbl Dubai Product Output Crude Gross Operating CashRefined products yield % prices value cost margin cost marginGasoline 26.6% x 36.75 = 9.78Naphtha 7.4% x 29.25 = 2.16Jet/Kerosene 4.0% x 54.15 = 2.17Gas oil 38.6% x 57.85 = 22.33Fuel oil 22.3% x 32.61 = 7.27

98.9% 43.71 - 37.02 = 6.69 - 3.50 = 3.19

Singapore simpleUS$/bbl Dubai Product Output Crude Gross Operating CashRefined products yield % prices value cost margin cost marginGasoline 11.9% x 36.75 = 4.37Naphtha 5.1% x 29.25 = 1.49Jet/Kerosene 9.9% x 54.15 = 5.36Gas oil 24.4% x 57.85 = 14.12Fuel oil 46.2% x 32.61 = 15.07

97.5% 40.41 - 37.02 = 3.39 - 2.00 = 1.39

A Few Final Notes about Refiner Profitability

Just because a refiner is complex does not mean that it can process heavier crudes. One must look into what is driving the higher complexity level. For instance, a plant may have extensive facilities to upgrade fuel oil or a lubricants plant but may not be able to process heavy or sour crudes.Competition is key for refiners. If a plant is in a relatively isolated market it will enjoy much higher margins than a plant in a merchant refining center.Operating costs are key to cash margins. These are driven by several factors including natural gas.

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US refiners are earnings momentum stocks

TesoroSunocoValero

When it comes to independent refining stocks, momentum often drives stock price movement. The charts above show how share price movements occurs after adjustments to EPS forecasts.

0.00.51.01.52.02.53.03.54.04.55.05.56.0

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0.00.51.01.52.02.53.03.54.04.55.05.56.06.57.07.58.08.59.0

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OUTLOOK FOR REFINING

US gasoline demand has likely peaked…..FOREVER

US future oil demand growth is now seen at negative 0.1%, from a positive rate of over 1% between 1998 and 2007

We expect a 0.6% annual decline in gasoline consumption between 2010 –2020 from new CAFE standards. Adopting the full RFS would give a 1.4% annual decline.

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US Gasoline demand Long Term

5,000

6,000

7,000

8,000

9,000

10,000

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

US

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D

Gasoline demand after CAFE Refiner Gasoline demand after CAFE and RFS

Economic bounce back slows decline in 2010

Over Capacity in the Industry

Significant new capacity and a collapse in demand have ushered in The Dark Ages

Some proposed new capacity has started to slip

Expect more movement in that direction, including fewer Middle East refineries

Source: C

redit Suisse

-1000

-500

0

500

1000

1500

2000

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2006 2007 2008 2009 2010 2011E 2012E 2013E 2014E 2015E

KB

D

North America OECD Europe South America FSU/Other Europe Africa Middle East OECD Pacific Other Asia Biofuels Demand growth

US Crude Over Supply Throws a Lifeline to Mid-Con RefinersStructural Oversupply Versus Refining Capacity

Even after all required pipelines are built to the Gulf Coast, refinery bottlenecks need to be considered

The line on the chart shows the available light processing refining capacity in the Mid-Con and the Gulf after heavy processing capacity is stripped out

By 2014, onshore crude supply could exceed this light processing capacity.

Were this to occur, there would need to be crude exports from the Gulf to the North East

In this scenario WTI would trade $3-4/bbl below LLS but LLS would trade $2-3/bbl below Brent…i.e. a $5-7/bbl WTI-Brent spread into the longer term

Each $1/bbl margin adds 8% to EBITDA for a refinery

Refining stocks are deeply undervalued

Source: Credit Suisse estimates, HOLT

Embedded Returns in US Refiners (HOLT)

0

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2009 2010 2011 2012 2013 2014 2015 2016 2017

KBD

GoM Padd 3 (Core)Texas (ex-Eagleford) BakkenPadd 2 (Core) Padd 4 (Core)Eagleford NiobaraMississippian UintaLight Crude Capacity

INVESTING IN MLPS

What is an MLP?

Real Assets

Real Cash Flow

Real Company

Housed in a master limited partnership structure

Source: Credit Suisse analysis

MLP

Typical MLP Structure

MLP Assets

Source: Spectra Energy website, American Petroleum Institute

An MLP must generate at least 90% of its income from qualifying sources (primarily natural resources activities) as defined in section 7704 of the internal revenue code

– Energy related assets include: Exploration and production, gathering and processing, transportation (e.g., pipelines), storage and terminals, refining, marine transportation, propane, and coal

– MLPs predominantly own midstream energy assets

*Credit Suisse definition

Master limited partnerships (MLPs) are limited partnerships that are publicly traded on US stock exchanges. They trade just like common stock. However, unlike corporations, these are pass-through entities that pay no corporate taxes. A high proportion of distributions are tax-deferred.

Limited Partner (LP): provides capital, receives distributions, has no role in managing the partnershipGeneral Partner (GP): manages partnership, 2% equity ownership, owns incentive distribution rights (IDRs)Distribution: Similar to dividends, distributions are paid quarterly and a large portion (typically 70% to 100%) is tax deferredIncentive Distribution Rights (IDRs): Entitle the GP to an increasing portion of distributions (up to50%) as target distribution levels are attainedDistributable Cash Flow (DCF)*: maximum amount of cash flow available to pay limited partners after taking into account maintenance capital requirements and the general partner entitlementSchedule K-1: Investors receive Schedule K-1s instead of Form 1099sUBTI: MLPs generate unrelated business taxable income (UBTI)

MLP Key Terms Defined

Cash Flow Characteristics– Gas pipelines and storage most stable and

secure cash flow given reservation fees – E&P/Refining least stable given commodity

price risk and depleting asset baseMaintenance Capex

– Too little can mean lower cash flow over timeCash Flow Coverage of Distribution

– More predictable cash flow streams = less need for excess distribution coverage

– Less predictable cash flow streams = greater need for excess distribution coverage

Source: Factset, Credit Suisse analysis

MLPs pay out majority of available cash flow

Access debt/equity markets needed to finance growthBenefit of business model:

Mandates financial discipline, transparency and focus on cash flowRisk to business model:

Reliance on capital markets for growth

MLP Business Model: Distribution Sustainability is Key

MLP Debt / Equity Issuance

5.7 5.37.0

8.311.1 11.5

20.2

16.2

4.9

8.3 9.2

19.1

5.6 6.8

15.1

7.8

0.0

5.0

10.0

15.0

20.0

25.0

2004 2005 2006 2007 2008 2009 2010 YTD

($bn

)

Debt Equity

Source: Factset, Bureau of Labor Statistics; Prices as of 09/02/11

High tax-advantaged yield Current yield of 6.6%

+ Distribution growth 2011E growth of 4.9%

= Attractive total returnExpect 10 to 13% total returns

MLP Value Proposition

Total Return CAGRs: MLPs: 15.7%, S&P 500: 6.1%, R2000: 6.4%

Energy MLPs Annual Distribution Growth vs CPI

4.9% 4.5% 4.3%

7.0%

3.6% 3.8%4.8%

9.1%8.2%

9.4% 8.8%

2.6% 3.0%

4.9% 5.4% 5.0%

6.8%

-2.0%

0.0%

2.0%

4.0%

6.0%

8.0%

10.0%

12.0%

14.0%

1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011E 2012E 2013E 2014E

Annu

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MLP Distribution Growth (Median) Y/Y Change in CPI

AMZ ML P Ind ex Y ie ld

4%

6%

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14%

16%

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8/2/96

2/28/97

9/26/97

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86/1

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10/5/0

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211

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6/27/03

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10/14/0

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/0910

/23/09

05/21/

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1

Total Return (Since 1996)

-200%0%

200%400%600%800%

1000%1200%

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11/19/

108/5

/11

AMZ MLP Index TR S&P500 TR Russell 2000 TR

164%

886%

153%

Follow the Cash, No One Really Cares About EarningsMLPs are primarily valued on their distributions, expectations for distribution growth

and perceived risk profile

Valuation MethodologiesDistribution Discount Model (DDM) Methodology

– Credit Suisse preferred methodology – Price target is based on a three-stage DDM model, which discounts five years of distribution forecast,

assumes a second stage of moderating distribution growth and a terminal value – To arrive at a discount rate we use a blended approach combining the discount rate implied by the

capital asset pricing model with the discount rate implied by investor’s required rate of return (yield plus expected distribution growth)

– Subjective factors are considered: asset mix, stability of cash flows and management track recordTarget Yield Methodology

– Price target derived by projecting a targeted yield on an expected distribution rate 12 months out – Yield spread comparisons are usually analyzed. Since 1999, MLPs have traded at 322 basis points

spread to the ten-year US treasury and 595 basis point spread to a high yield bond indexRelative Valuation Metrics

– Price / Distributable cash flow (DCF) multiple– Adjusted Enterprise Value / EBITDA multiple

Valuation Framework: DDM is Preferred Methodology

Source: Factset, Alerian website, Credit Suisse analysis; Prices as of 09/08/11

MLPs yield 6.6%, 459 bps more than treasuries, which is close to one standard deviation above the historical average. MLP yields remain compelling relative to investment grade bonds.On a price-to-distributable cash flow basis, MLPs remain within their historical +/- one standard deviation range of 10x to 14x.

Yield Spread AnalysisA M Z P r ic e/D C F (1 9 9 6-2 0 11 )

4x

6x

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1 0x

1 2x

1 4x

1 6x

1 8x

1/5/9

66/

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11/5

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110

/5/01

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32/2

7/04

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2/11

/058/5

/051/2

7/06

7/21

/061/1

2/07

7/6/07

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812

/12/08

6/5/0

911

/27/

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/21/10

11/1

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05/0

6/11

C u r re n t = 13 .2x

A v er ag e = 12 .0x

C S L U C I B B B 7-1 0 Y r Sp re a d to 1 0 -Y r T re a su ry (1 9 9 9 -2 0 1 1)

0

10 0

20 0

30 0

40 0

50 0

60 0

70 0

80 0

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/15/0

44/

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53/

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07/01

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C u r ren t Sp r ea d = 21 5

Av era g e Sp r ea d = 20 6

A M Z Y ie ld v s . 1 0 y r T r e as u ry (1 9 9 9 -2 0 1 1)

0

2 0 0

4 0 0

6 0 0

8 0 0

1 , 0 0 0

1 , 2 0 0

1 , 4 0 0

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15/0

63/9

/078/

31/07

2/22/0

88/

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6/09

7/31/0

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/22/1

007

/16/

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/07/1

107

/01/11

C u rr e n t S p re a d = 4 5 9A v e ra g e S p re a d = 3 2 2

AMZ Y ield vs. CS LUCI BBB 7-10 Yr (1999-2011)

-200-100

0100200300400500600700

1/15/9

97/

9/99

12/31

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6/23

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12/1

5/00

6/8/01

11/3

0/01

5/24/

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/15/

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/078/

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6/09

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/09

01/2

2/10

07/1

6/10

01/0

7/11

07/01

/11

A verag e = 118b psC urrent = 244ps

IG cred tis are att ractive vs. MLPs

M LPs are at tractive vs. IG credits

Disclosures

Companies Mentioned (Price as of 21 Sep 11) Alon USA Energy Inc. (ALJ, $7.61) Anadarko Petroleum Corp. (APC, $72.72) Atwood Oceanics, Inc. (ATW, $37.47, NEUTRAL [V], TP $45.00) Baker Hughes Inc. (BHI, $54.33, OUTPERFORM, TP $93.00) Berry Petroleum Co. (BRY, $43.71, OUTPERFORM, TP $70.00) BHP Billiton (BLT.L, 1888.50 p, NEUTRAL, TP 3160.00 p) Bill Barrett Corp (BBG, $41.21) Boardwalk Pipeline Partners, LP (BWP, $26.07, OUTPERFORM, TP $35.00) BP (BP.L, 404.05 p, OUTPERFORM, TP 610.00 p) Bristow Group Inc. (BRS, $42.65, OUTPERFORM, TP $53.00) Cabot Oil & Gas Corp (COG, $70.03) Cameron International Corp. (CAM, $47.58, OUTPERFORM, TP $74.00) Chesapeake Energy Corp. (CHK, $29.42) Chevron Corp. (CVX, $94.27, OUTPERFORM, TP $130.00) Cobalt International Energy (CIE, $8.78, OUTPERFORM [V], TP $17.00) Complete Production Services (CPX, $22.74, NEUTRAL [V], TP $52.00) ConocoPhillips (COP, $64.95, RESTRICTED) CONSOL Energy Inc. (CNX, $37.92, OUTPERFORM, TP $65.00) Delek US Holdings, Inc. (DK, $12.52, NEUTRAL, TP $17.00) Denbury Resources (DNR, $12.99, NEUTRAL, TP $30.00) Devon Energy Corp (DVN, $61.61) Diamond Offshore (DO, $60.22, UNDERPERFORM, TP $67.00) Dresser Rand Group Inc (DRC) Dril-Quip, Inc. (DRQ, $63.72) Duncan Energy Partners, LP (DEP, $41.22) EnCana Corp. (ECA, $21.64, OUTPERFORM, TP $36.00) Energy Transfer Equity, LP (ETE, $37.43, RESTRICTED) Energy Transfer Partners, L.P. (ETP, $43.89, RESTRICTED) ENI (ENI.MI, Eu12.88, NEUTRAL, TP Eu19.00) Ensco Plc. (ESV, $46.19, OUTPERFORM, TP $71.00) Enterprise GP Holdings, LP (EPE, $43.48) Enterprise Products Partners, LP (EPD, $42.26, OUTPERFORM, TP $46.00) EOG Resources (EOG, $83.43) EV Energy Partners LP (EVEP, $72.31) Exterran Holdings (EXH, $9.71, NEUTRAL, TP $17.00) ExxonMobil Corporation (XOM, $71.97, NEUTRAL, TP $95.00) FMC Technologies, Inc. (FTI, $41.13, NEUTRAL, TP $49.00) Forest Oil (FST, $17.62, OUTPERFORM [V], TP $29.00) Frontier Oil Corporation (FTO, $32.31) Gardner Denver, Inc. (GDI, $71.63, NEUTRAL, TP $91.00) Global Geophysical Services, Inc. (GGS, $8.20, OUTPERFORM [V], TP $21.00) Goodrich Petroleum Corp. (GDP, $14.91) Gulfport Energy Corporation (GPOR, $26.35) Halliburton (HAL, $35.09, OUTPERFORM, TP $66.00) Helmerich & Payne, Inc. (HP, $48.27, NEUTRAL, TP $69.00) Hercules Offshore (HERO, $3.63, OUTPERFORM [V], TP $6.50) Hess Corporation (HES, $56.49, OUTPERFORM, TP $115.00) Holly Corp. (HOC, $71.76) HollyFrontier Corp (HFC, $29.64, OUTPERFORM [V], TP $50.00) Husky Energy Inc. (HSE.TO, C$22.93, NEUTRAL, TP C$32.00) Kinder Morgan Energy Partners, L.P. (KMP, $70.70, NEUTRAL, TP $77.00) Kinder Morgan Management, LLC (KMR, $60.04, OUTPERFORM, TP $73.41) Kosmos Energy Ltd (KOS, $12.79, OUTPERFORM [V], TP $25.00) LUKOIL (LKOH.RTS, $56.90, OUTPERFORM, TP $105.20) Magellan Midstream Partners, LP (MMP, $61.29, NEUTRAL, TP $62.00) Marathon Oil Corp (MRO, $23.73, NEUTRAL, TP $36.00) Murphy Oil Corp. (MUR, $48.03) Nabors Industries, Ltd. (NBR, $15.63, OUTPERFORM, TP $35.00) National Oilwell Varco (NOV, $58.04, OUTPERFORM, TP $95.00) Neste (NES1V.HE, Eu7.16, NEUTRAL, TP Eu11.50) Newfield Exploration Co. (NFX, $44.30) Nexen Inc. (NXY.TO, C$17.28, NEUTRAL, TP C$27.00) Noble Corporation (NE, $33.41, OUTPERFORM, TP $51.00) Noble Energy (NBL, $77.09)

NuStar Energy LP (NS, $56.00, NEUTRAL, TP $68.00) NuStar GP Holdings LLC (NSH, $33.25, NEUTRAL, TP $36.00) Occidental Petroleum (OXY, $76.32, NEUTRAL, TP $128.00) Oceaneering Intl, Inc. (OII, $39.15, NEUTRAL, TP $48.00) Oil States International (OIS, $58.32, OUTPERFORM [V], TP $110.00) OMV (OMVV.VI, Eu25.04, UNDERPERFORM, TP Eu28.00) Patterson-UTI Energy, Inc. (PTEN, $19.54, OUTPERFORM, TP $42.00) Petrobras (PBR, $24.64, NEUTRAL, TP $38.00) Pioneer Natural Resources (PXD, $74.34) Plains All American Pipeline, L.P. (PAA, $60.04, OUTPERFORM, TP $67.00) Plains Exploration & Production Co. (PXP, $25.75) Quicksilver Resources, Inc. (KWK, $8.63, NEUTRAL, TP $12.00) Range Resources (RRC, $67.96, OUTPERFORM, TP $77.00) Repsol YPF SA (REP.MC, Eu19.52, OUTPERFORM, TP Eu29.50) Rex Energy Corp. (REXX, $14.28, NEUTRAL [V], TP $13.00) Rosetta Resources Inc. (ROSE, $43.01, OUTPERFORM [V], TP $71.00) Rowan Companies (RDC, $35.23, NEUTRAL, TP $46.00) Royal Dutch Shell PLC (ADR) (RDSa.N, $63.15, OUTPERFORM, TP $90.00) Schlumberger (SLB, $65.15, OUTPERFORM, TP $117.00) Seadrill (SDRL, NKr184.10, NEUTRAL, TP NKr178.00) Smith International, Inc. (SII, $38.84) Southwestern Energy Co. (SWN, $38.70) Spectra Energy Partners, LP (SEP, $28.77, NEUTRAL, TP $34.00) St. Mary Land (SM, $76.99) Statoil (STL.OL, NKr127.60, NEUTRAL, TP NKr159.00) Suncor Energy (SU.TO, C$28.13, OUTPERFORM, TP C$50.00) Sunoco Logistics Partners, L.P. (SXL, $88.22, OUTPERFORM, TP $93.00) Swift Energy Co. (SFY, $29.26, OUTPERFORM, TP $52.00) Tesoro Corp. (TSO, $21.47, OUTPERFORM [V], TP $36.00) Tidewater (TDW, $53.71, OUTPERFORM, TP $63.00) Total (TOTF.PA, Eu32.20, NEUTRAL, TP Eu46.00) Transocean Inc. (RIG, $56.30, NEUTRAL, TP $71.00) Tullow Oil (TLW.L, 1333.00 p, OUTPERFORM, TP 1804.00 p) Ultra Petroleum Corp. (UPL, $32.54) Valero Energy Corporation (VLO, $19.89, OUTPERFORM, TP $41.00) Weir Group (WEIR.L, 1768.00 p, OUTPERFORM, TP 2000.00 p) Western Refining Inc. (WNR, $14.35, NEUTRAL [V], TP $24.00) Whiting Petroleum Corp. (WLL, $41.04, OUTPERFORM, TP $73.00)

Disclosure Appendix Important Global Disclosures Arun Jayaram, CFA, Brad Handler & Edward Westlake each certify, with respect to the companies or securities that he or she analyzes, that (1) theviews 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 orher compensation was, is or wil l be directly or indirectly related to the speci fic recommendations or views expressed in this report. See the Companies Mentioned section for ful l company names. The analyst(s) responsible for preparing this research report received compensation that is based upon various factors including Credit Suisse's totalrevenues, 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 perceivedrisk) 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 totalreturn potential to its current share pr ice 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 industryfactors. For Latin American, Japanese, and non-Japan Asia stocks, ratings are based on a stock’s total return relative to the average total return ofthe relevant country or regional benchmark; for European stocks, ratings are based on a stock’s total return relative to the analyst's coverageuniverse**. For Austral ian and New Zealand stocks, 12-month rolling yield is incorporated in the absolute total return calculation and a 15% and a7.5% threshold replace the 10-15% level in the Outperform and Underperform stock rating definitions, respectively. The 15% and 7.5% thresholdsreplace the +10-15% and -10-15% levels in the Neutral stock rating definition, respectively. **An analyst's coverage universe consists of all companies covered by the analyst within the relevant sector.

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