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OIL & GAS PRIMER September 2011 The 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 United States Integrated Oils & Refiners Ed Westlake (New York)) Rakesh Advani (New York) Exploration & Production Arun Jayaram (New York) Mark Lear (New York) David Lee (New York) Oil Services Brad Handler (New York) Eduardo Royes (New York) Jonathan Sisto (New York) MLPs Yves Siegel (New York) Brett Reilly (New York) Utilities Dan Eggers (New York) Kevin Cole (New York) Matt Davis (New York) Katie Chapman (New York) Alternative Energy Satya Kumar (San Francisco) Ed Westlake (New York)) Patrick Jobin (New York) Specialist Sales Tom Marchetti (New York) Charlie Balancia (New York)
Canada Brian Dutton (Toronto) Andrew Kuske (Toronto) Courtney Morris (Toronto) Paul Tan Jason Frew (Calgary) Terence Chung (Calgary) David Phung (Calgary)
Russia/Emerging Europe Oil & Gas Mark Henderson (London) Andrey Ovchinnikov (Moscow) Utilities Anton Fedotov (Moscow)
+1 212-325 6751 +1 212 538 5084
[email protected] [email protected]
+1 212 538 8428 +1 212 538 0239 +1 212 325 6693
[email protected] [email protected] [email protected]
+1 212 325 0772 +1 212 538 7446 +1 212-325-1292
[email protected] [email protected] [email protected]
+1 212 325 8462 +1 212 538 3749
[email protected] [email protected]
+1 212 538 8430 +1 212 538 8422 +1 212 325 2573 +1 212 325 1261
[email protected] [email protected] [email protected] [email protected]
+1 415 249 7928 +1 212-325 6751 +1 212 325 0843
[email protected] [email protected] [email protected]
+1 212 325 0667 +1 212-325 6314
[email protected] [email protected]
+1 416 352 4596 +1 416 352 4561 +1 416 352 4595 +1 416 352 4593 +1 403 476 6022 +1 403 476 6024 +1 403 476 6023
[email protected] [email protected] [email protected] [email protected] [email protected] [email protected] [email protected]
+44 20 7883 6901
[email protected] +7 495 967 8360
[email protected] +7 495 967 8362
[email protected]
Europe Integrated Oils & Refiners Kim Fustier (London) Thomas Adolff (London) Exploration & Production Tao Ly (London) Ritesh Gaggar (London) Arpit Harbhajanka (London) Oil Services Tao Ly (London) Arpit Harbhajanka (London) Utilities Vincent Gilles (London) Mark Freshney (London) Stephen Deeley (London) Michel Debs (London) Mulu Sun (London) Zoltan Fekete (London) Specialist Sales Jason Turner (London) Mark Whitfeld (London)
+44 20 7883 0384 +44 20 7888 9114
[email protected] [email protected]
+44 20 7888 1778 +44 20 7888 0277 +44 20 7888 0151
[email protected] [email protected] [email protected]
+44 20 7888 1778 +44 20 7888 0151
[email protected] [email protected]
+44 20 7888 1926 +44 20 7888 0887 +44 20 7883 9534 +44 20 7883 9952 +44 20 7888 0269 +44 20 7888 0285
[email protected] [email protected] [email protected] [email protected] [email protected] [email protected]
+44 20 7888 1395 +44 20 7888 8038
[email protected] [email protected]
Latin America Oil & Gas Emerson Leite (Sao Paulo) +55 11 3841 6290 Utilities Vinicius Canheu (Sao Paulo) +55 11 3841 6310 Ethanol, Agribusiness and Transportation Luiz Campos (Sao Paulo) +55 11 3841 6312
[email protected] [email protected] [email protected]
Australia Sandra McCullagh (Melbourne) Nik Burns (Melbourne) Ben Combes (Melbourne)
+61 2 8205 4729 +61 3 9280 1641 +61 3 9280 1669
[email protected] [email protected] [email protected]
Asia-Pacific David Hewitt (Singapore) Horace Tse (Hong Kong) Edwin Pang (Hong Kong) Yang Song (Hong Kong Trina Chen (Hong Kong) Sanjay Mookim (Mumbai) Yuji Nishiyama (Tokyo) Siriporn Sothikul (Bangkok) Poom Suvarnatemee (Bangkok) A-Hyung Cho (Seoul) Annuar Aziz Kuala Lumpur) Sidney Yeh (Taipei)
+65 6212 3064 +852 2101 7379 +852 2101 6406 +852 2101 6550 +852 2101 7031 +91 22 6777 3806 +81 3 4550 7374 +66 2 614 6217 66 2 614 6210 +82 2 3707 3735 +603 2723 2085 +8862 2715 6368
[email protected] [email protected] [email protected] [email protected] [email protected] [email protected] [email protected] [email protected] paworamon.suvarnatemee@credit-suisse.
[email protected] [email protected] [email protected]
Source: Credit Suisse Page 2
Credit Suisse Global Energy Team
Toronto
London
Moscow
Tokyo
Source: Credit Suisse.
New York
Seoul Hong Kong Bangkok Singapore
Sao Paulo
Kuala Lumpur Sydney Johannesburg
Call us anywhere: we can help you
Page 3
Table of contents Industry Overview
Basics of Energy Investing
Crude Oil Crude Oil Overview Crude Oil Supply International Offshore Exploration Crude Oil Demand Global Oil Markets
6 12 19 27 32
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
Natural Gas Natural Gas Overview North American Natural Gas Shale Gas in Focus Liquefied Natural Gas (LNG)
39 45 57 67
The Upstream The Upstream Process Oil and Gas Reserves
83 99
The Midstream Natural Gas Crude Oil/Refined Products
107 111
Oilfield Services, Equipment and Drilling Products and Services Company Specific Details
116 136
The Downstream Refining Refinery Operations Oil Product Marketing
148 161 171
Page 4
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
Page 7
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
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.
Sour
4.5% Cold Lake
4.0% 3.5%
Maya
Sulfur Content
Crude oils with higher than
3.0% Arab Heavy
Arab Medium
2.5% Fateh 2.0% Iranian Heavy 1.5%
Basrah Light Arab Light
ANS
1.0%
Brent
0.5%
Cabinda WTI Bonny Light
Bonny Medium
Sweet
gravity, the lighter the crude. Crude oils with higher API gravity yield greater proportions of lighter petroleum products like gasoline. Source: DOE
0.0% 0
Heavy
5
10
15
20
25
30
API Gravity
35
40
Tapis 45
50
Light
Page 8
Source: BP Stats
Global Oil Reserves
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 nonOPEC 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. Page 9
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”).
Page 10
Source: BP Stats
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. Page 11
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
Page 13
Global Production Split: OPEC and Non-OPEC OPEC accounts for roughly 40% of
50% 30 40% 25 20
30%
15 20% 10 10% 5
2012E
2010E
2008
2006
2004
2002
2000
1998
1996
1994
1992
1990
1988
1986
1984
1982
1980
1978
0% 1976
0 1974
FSU) production grew rapidly in the 1960s, 1970s/80s and the 1990s. However, non-OPEC supply growth has slowed in recent years.
Market Share [RHS]
35 Crude Oil Production (MMBD)
Non-OPEC (ex-Former Soviet Union or
60% OPEC Supply [LHS]
Global Market Share (%)
global oil supply, a sharp increase from the trough of 1985, but still lower than its historical level of 55%+ pre-1973/74.
40
Non-OPEC’s restricted access to new reserves, combined with higher decline rates, are the reasons.
* Assumes no inventory change: 2009 - 2012
Page 14
Source: IEA, Credit Suisse estimates
OPEC Oil Production*
8.0
160
6.0
140 120 100
2.0 80 0.0 60 -2.0
40
-4.0 -6.0 Jan-01
20 0 Jan-02
Jan-03
Jan-04
Spare Capacity
Jan-05
Jan-06
Jan-07
Demand Less Supply Growth
Jan-08
Jan-09
Jan-10
Jan-11
WTI, $/bbl
Million Barrel Per Day
4.0
Source: IEA, Credit Suisse estimates – adjusted for Libya
OPEC’s Spare Capacity: a Key Measure
WTI (RHS)
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).
Page 15
Watching OPEC Capacity Additions OPEC Net Capacity Additions 1.80 1.30 0.80 0.30
Source: IEA, Credit Suisse estimates
-0.20 -0.70 -1.20
2013E
2012E
2011E
2010E
2009E
2008
2007
-1.70
Algeria
Angola
Ecuador
Iran
Iraq
Kuwait
Libya
Nigeria
Qatar
Saudi Arabia
UAE
Venezuela
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.
Page 16
Iraq: Significant potential, But Infrastructure a Challenge Iraqi oil production over time – rise and fall
Iraq – 9% of world reserves, 3% of world production
12500
25%
Implied potential
Oil projects awarded and growth Reserves (BB) 1st round awards Rumaila Zubair West Qurna Phase-1 Sub-total
Initial Rate (MMB/d)
Cost Recovery Floor (MMB/d)
Targeted Plateau Rate (MMB/d)
17.77 4.08 8.58 30.43
1.05 0.195 0.26 1.51
1.155 0.2145 0.286 1.66
2.85 1.125 2.325 6.30
0.046 0.000 0.003 0.000 0.000 0.000 0.000
Sub-total
12.58 12.88 4.10 0.86 0.11 0.81 0.86 32.19
0.175 0.120 0.070 0.035 0.015 0.030 0.020 0.465
1.800 1.800 0.535 0.230 0.170 0.120 0.110 4.765
Total
62.62
1.55
2nd round awards Majnoon W est Qurna Phase-2 Halfaya Garraf Badra Qaiyarah Najmah
Source: Department of Defense
0.05
11.07
Source: Iraq Oil Forum
Could change perception of long-term supply. Page 17
Nigeria
Libya
Kazakhstan
Iraqi Civilian Deaths Jan 2006 – Aug 2009
Russia
Source for top charts: IEA, industry data, Credit Suisse estimates
UAE
0%
Kurdistan
Venezuela
Plateau
2015E
2013E
2011E
2009E
2007
2005
2003
2001
1999
1997
2nd round projects
Saudi Arabia
1st round projects
1995
1993
1991
1989
5%
1987
0 1985
10% 1983
2500
1981
15%
1979
5000
Baseline
% World production
20%
7500
Kuwait
Gulf war II
% World reserves
Iraq
Gulf war
Iran
Iran/Iraq war 10000
Onshore Growth Accelerating; We Need Offshore Too Deepwater Hockey Stick
US Onshore Supply Growth and Infrastructure 4,500
Refining
Pip eline
Tanker + Barge
Supply Growth
Rail
14,000
4,000
Deepwater hockey stick
3,500
12,000 10,000
2,500 2,000
8,000
1,500
6,000
1,000 500
4,000
0 2010
2011
2012
2013
2014
2015
2016
2017
2,000 0 2000 West Africa
2002
2004
2006
US Gulf of Mexico
2008
2010E Brazil
2012E
2014E
2016E
Ghana
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
Source: IEA, Credit Suisse estimates
(KBD)
3,000
Other D
Page 18
International Offshore Exploration Success Improving
Brazil is Still the Largest Hot Spot
Source: 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)
Page 20
Ghana: Could Be Larger Than We Currently Think (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.
Page 21
French Guiana/Suriname – Zaedyus Game Changer
(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 Page 22
Source: APC, TLW
1st Successful Wildcat in Guyana Basin
Page 23
Source: APC, TLW
Africa : More Late Cretaceous
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
Testing Liberia, Sierra Leone, Cote D’Ivoire (APC)
Page 24
Source: APC, TLW
West Africa Exploration to the Forefront – Pre Salt Angola Angola Pre-Salt
Cobalt Pre-Salt – Drilling Cameia Currently
Page 25
Source: CIE
US Gulf of Mexico US GoM Reserves, 78% Held by Supermajors
• The US Gulf of Mexico contains significant resource but drawbacks are liability concerns and permitting delays
30 00 25 00 20 00 15 00 10 00
Source: Wood Mackenzie; CVX
5 00
ATP
ME
Maersk
Repsol YPF
Total
Noble Energy
Devon Energy
Nexen
14,000 12,000 10,000 Million BOE
COP
Marathon
Plains E&P
Eni
HESS
ExxonMobil
Petrobras
BHP Billiton
Anadarko
Statoil
Chevron
Shell
0 BP
Deepwater Gulf of Mexico Reserves, MB
35 00
8,000 6,000 4,000 2,000 0 Remaining Reserves in Production
Reserves in Appraisal
Recently Discovered
Future Geological Potential
Page 26
Crude Oil Demand
Oil Demand
Oil demand grew by a CAGR of 1.5% from 1992 to 2008.
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.
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 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.
Page 28
Oil Demand Correlation with Real GDP Growth (1969 - 2008) 7.0%
R2 = 0.5802 5.0% 4.0% 3.0% 2.0% 1.0% 0.0% -6.00%
-4.00%
-2.00%
0.00%
2.00%
4.00%
6.00%
8.00%
10.00%
Source: BP Stats, Credit Suisse estimates
World Real GDP Growth
6.0%
Worldwide Oil Consumption Growth
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).
Page 29
Oil Demand Growth & Oil Prices 8.9% 8.4%
9%
Demand growth
8.2% 7.2%
110
SPIKE
7.3%
100
SPIKE
90
7% 6%
80 70
4.2%
5% Global Oil Demand Growth
Saudis change policy
5.9%
5.5%
60 3.7%
4%
2.9% 2.7% 2.3% 1.6%
3% 1.7%
2%
1.2% 0.8%
1.4%
1.3%
1%
Collapse
0.6% 0.8% 0.5% 0.5%
0.3%
50
3.0% 2.8% 2.4% 2.2% 1.7% 1.4%1.4%
40
2.3% 2.1% 1.1% 0.9% 0.8%
1.9%
0.2%
-2%
The Good Old Days
-4%
-1.5%
-1.5%
Boom Recovery
-2.3% -2.9%
-4.1%
Boom
Recovery
Boom Recovery
Boom Recovery
-5%
Recession
Recession
Recession
Recession
Recovery Recession
1966 1967 1968 1969 1970 1971 1972 1973 1974 1975 1976 1977 1978 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010E
-6%
0
18 years of low and stable oil prices 1986-2004
-0.5%
-3%
20 10
0% -1%
30
Inflation adjusted Brent price US$ per bbl
8%
Real Brent Oil Price (USD/bbl), 2007
8.0%
Source: Credit Suisse Oil is a cyclical commodity (with managed characteristics). Higher oil prices during booms create deeper demand recessions afterwards.
Page 30
Source: BP Stats.
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. Page 31
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.
Page 33
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
Page 34
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 counter transaction, 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). Page 35
Oil Markets: Data Sources
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.
Source: IEA
Source: IEA
Page 36
Futures Curve: Backwardation vs. Contango
Futures Curve: Contango Example
Futures Curve: Backwardation Example
$80
$80
$72.04
$72.49 $73.04
$73.61
$77.09
$76.77 $77.09
$74.11 $74.62
Price per barrel
$75
$70
$65
$76.77$76.47 $76.10
$75.60
$75.10 $74.62
$75
$74.11 $73.61 $73.04
$72.49
$72.04
$70
Source: Bloomberg
Sep-10
Aug-10
Jul-10
Jun-10
May-10
Apr-10
Mar-10
Feb10
Jan10
Sep-10
Aug-10
Jul-10
Jun-10
May-10
Apr-10
Mar-10
Feb10
Jan10
Dec09
Nov09
$65
Oct09
Price per barrel
$75.10 $75.60
$76.10 $76.47
Dec09
Nov09
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: Contango A 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
Oct09
Source: Bloomberg
Page 37
NATURAL GAS
Natural Gas Overview
What is Natural Gas?
Source: Chesapeake Energy
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. Page 40
Global Natural Gas: Proved Reserves (2010)
Total Proved Reserves were over 6,600 trillion cubic feet at year-end 2010.
Europe & Eurasia 2,227 Tcf North America 350 Tcf Middle East 2,675 Tcf
Asia Pacific 575 Tcf
Africa 522 Tcf South & Central America 264 Tcf
Source: BP Statistical Review of World Energy 2011.
Page 41
World Energy: Natural Gas Has Gained Share of the Energy Pie
Source: BP Statistical Review of World Energy 2011
According to BP Statistical Energy Review, natural gas accounted for 24% of global primary energy consumption, the highest on record, in 2010.
Page 42
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).
Page 43
Substitutes for Natural Gas Coal
Source: www.britishcoalgasification.co.uk.
Oil
Source: ecotechdaily.com
Alternative Energy
Source: www.greengop.org.
There are numerous substitutes for natural gas including coal, oil, heating oil, 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.
Page 44
North American Natural Gas
1/2/2011
1/2/2010
1/2/2009
1/2/2008
1/2/2007
1/2/2006
1/2/2005
1/2/2004
1/2/2003
1/2/2002
1/2/2001
1/2/2000
1/2/1999
$0.00
Source: Bloomberg LP
$2.00
WTI Crude Oil to Henry Hub Natural Gas (x) 32.0x 28.0x Current (9/14/11): 23.0x
10-Year Average: 11.3x
24.0x 20.0x
12.0x 8.0x 4.0x
1/2/2011
1/2/2010
1/2/2009
1/2/2008
1/2/2007
1/2/2006
1/2/2005
1/2/2004
0.0x
Page 46
Source: Bloomberg LP
16.0x
1/2/2003
linked to crude owing to less liquid trading markets.
$4.00
1/2/2002
Outside of the U.S., prices tend to be
$6.00
1/2/2001
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).
$8.00
1/2/2000
In North America, oil and natural gas
$10.00
1/2/1999
prices have traded as low as $2-3 per MMBtu and as high as $14-15 per MMBtu.
$12.00
1/2/1998
Over the past 14 years, NYMEX gas
$14.00
1/2/1998
market with natural gas prices driven by demand trends (weather, economic growth) and the cost of new supply.
($ per MMBtu)
$16.00
1/2/1997
North America is mostly a “closed”
NYMEX Natural Gas Prices
1/2/1997
N. AM. Natural Gas Pricing
Source: Energy Information Administration
North American Natural Gas: Industry Overview
The process of bringing natural gas to market begins with exploration & production and 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.
Page 47
Upstream: Where is Natural Gas Located? Onshore: Shale
Source: U.S. Geological Survey.
Onshore: Tight Gas
Source: StatoilHydro.
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. Page 48
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
Page 49
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. Page 50
Source: American Clean Skies Foundation
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. Page 51
Natural Gas Marketing: What are Basis Differentials?
~$4.30/MMBtu
~$4.20/MMBtu
Source: www.nafsa.org
~$3.60/MMBtu
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.
Page 52
Source: Energy Information Administration
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. Page 53
U.S. Weekly Storage Report WORKING GAS IN STORAGE Change 9/2/2011 Producing Region Consuming East Consuming West Total U.S.
Week Ago 957 1,578 426 2,961
959 1,636 430 3,025
Change Bcf
0.2% 3.7% 0.9% 2.2%
Year Ago
2 58 4 64
%
Bcf
(1.2%) (4.2%) (9.9%) (4.2%)
(12) (71) (47) (131)
971 1,707 477 3,156
5-Year Avg 925 1,732 427 3,085
Differential % Bcf 3.7% (5.5%) 0.7% (1.9%)
34 (96) 3 (60)
Total U.S. Working Gas In Storage
4,500
2011 5-Yr Avg 2008 2009 2010
4,000
Billion Cubic Feet
%
3,500 3,000 2,500 2,000 1,500 1,000 500 1
4
7
10
13
16
19
22
25
28
31
34
37
40
43
46
49
52
Calendar Week Source: Energy Information Administration (EIA)
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. Page 54
Major End Markets for Natural Gas Residential Gas used in private dwellings for space and water heating, air conditioning, cooking and other household uses
Commercial Gas used by non-manufacturing establishments in the sale of goods or services
Industrial Gas used for heat, power or chemical feedstock for manufacturing. End products include petrochemicals, fertilizers, plastics, etc.
Electrical Power Gas used by power plants to generate electricity
Other smaller end-market uses of natural gas include 1) fuel (natural gas vehicles) and 2) oil & gas production. Source: Energy Information Administration
Page 55
80.0
60.0
50.0
40.0
10.0
Residential
30.0
Electric Power
20.0
Industrial
0.0 Source: Energy Information Administration
Jan-02 Mar-02 May-02 Jul-02 Sep-02 Nov-02 Jan-03 Mar-03 May-03 Jul-03 Sep-03 Nov-03 Jan-04 Mar-04 May-04 Jul-04 Sep-04 Nov-04 Jan-05 Mar-05 May-05 Jul-05 Sep-05 Nov-05 Jan-06 Mar-06 May-06 Jul-06 Sep-06 Nov-06 Jan-07 Mar-07 May-07 Jul-07 Sep-07 Nov-07 Jan-08 Mar-08 May-08 Jul-08 Sep-08 Nov-08 Jan-09 Mar-09 May-09 Jul-09 Sep-09 Nov-09 Jan-10 Mar-10 May-10 Jul-10 Sep-10 Nov-10 Jan-11 Mar-11 May-11
U.S. Natural Gas Demand By End Markets 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) 100.0
90.0
Commercial
70.0
Page 56
Natural Gas Upstream Trends: Shale Gas in Focus
Source: www.research.uky.edu.
Shale Gas in Focus
Shale is a fine-grained sedimentary rock that may contain high concentrations of
natural 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.
Page 58
Shale Basins in the U.S. Major shale plays include: Bakken, Barnett, Eagle Ford, Fayetteville, Haynesville, Marcellus and Woodford.
Source: Energy Information Administration.
Page 59
Source: USGS
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. Page 60
Barnett Shale Barnett Shale Natural Gas Production (MMcf/d)
5,500 4,863
5,000
5,060
4,416
4,500 4,000 3,500
3,025
3,000 2,500
1,964
2,000
1,000 500
727
952
1,041
2004
264
362
497
1999
2000
2001
2002
2003
––
37.1%
37.3%
46.3%
30.9%
0
Barnett Growth
9.4%
2005
2006
2007
2008
2009
32.9%
42.0%
54.0%
46.0%
10.1%
2010
4.1%
Source: Texas RRC
1,384
1,500
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. Page 61
Haynesville Shale ¾ Industry believes play spans some 3.5MM acres ¾ We believe much of the “greenfield” leasing has been done
r Cente of ity Activ
Source: Company data
¾ Ways to enter now are through acquisitions, joint ventures or farm-outs
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%. Page 62
Marcellus Shale High Pressure Area
Source: www.planetthoughts.org
Low Pressure Area
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. Page 63
Source: EIA
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 Petrohawk for $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. Page 64
Source: www.planetthoughts.org
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. Page 65
Source: Berry Petroleum
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. Page 66
Liquified Natural Gas (LNG)
Source: LNG One World
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.
Page 68
LNG: Industry Overview Transport
Source: StatoilHydro
Liquefaction
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 Source: www.oilonline.com
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]).
Regasification
Page 69
Source: StatoilHydro
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).
Page 70
LNG: Regasification LNG Carrier Source: Federal Energy Regulatory Commission
Storage Facility
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. Page 71
Source: Federal Energy Regulatory Commission
LNG: U.S. Import Terminals
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.
Page 72
Source: BP Statistical Review of World Energy
LNG: 2010 Imports / Exports by Region
LNG now accounts for 30.5% of the global gas trade
Page 73
Source: California Energy Commission
LNG: Major Importing Countries – Japan
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.
Page 74
Source: www.hydrocarbons-technology.com
LNG: Major Importing Countries – South Korea
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.
Page 75
Source: www.faqs.org
LNG: Major Importing Countries – Spain
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.
Page 76
Source: www.hydrocarbons-technology.com
LNG: Major Exporting Countries – Qatar
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. Page 77
Source: www.aceproject.org
LNG: Major Exporting Countries – Indonesia
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 Tangguh to build a third train, which should increase capacity by 0.6 Bcf/d. Like Australia, Indonesia primarily exports LNG to Asian markets. Page 78
Source: www.lngpedia.com
LNG: Major Exporting Countries – Australia
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. Page 79
THE UPSTREAM
Exploration & Production Oil Supply Chain
Natural Gas Supply Chain
Source: American Petroleum Institute.
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. Source: American Petroleum Institute.
Page 81
Exploration & Production: Industry Players The 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.
Integrated Oils
Independent E&Ps
Pipeline Focused
Source: Google images
Page 82
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) 2)
Acreage Acquisition: Producers begin by acquiring leases and drilling permits. Prospects include:
Locations contiguous to producing formations Unexplored areas Exploration & Appraisal: Producers will then begin to evaluate the acreage to see if there are commercially recoverable reserves.
3)
Involves sub-surface analysis, shooting seismic and drilling exploratory wells and appraisal wells. Wells drilled in previously unexplored areas are known as wildcats.
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 Page 84
The Upstream Process
Plug & Abandon Bad
START HERE Good Acquire acreage
Conduct seismic survey
Interpret data
Identify prospects
Drill exploration wells
Final Investment Decision
Evaluate results
Oil
Drill further wells appraisal
For Sale Go on to Development
Install platform/ rig or drilling ship
Sign gas sales contract
Negotiate gas sales contract
Begin drilling Install production wells facilities
Formulate Development Plan
Begin production
Examine gas sales options
Sell oil / gas for cash
Gas with no spot market
No market identified
Source: Google images.
Page 85
The first step producers take is to negotiate or bid for leases with 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
Source: www.realestateofpinedale.com
Source: www.realestateofpinedale.com
Acreage Acquisition: Exploration and Right to Drill
production threshold
Page 86
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
Geological Surveys
Source: Oil Shale Exploration Company.
Source: Cobalt Exploration.
Page 87
Exploration & Appraisal: Seismic Evaluation Seismic evaluation has greatly de-risked the
– –
Seismic waves (acoustic vibrations) are created.
–
The speed and nature of how the waves reflect are then interpreted to estimate subsurface geology.
Source: BP Energy
The waves migrate downward and reflect off of various layers of subsurface rock back to the surface where receivers "catch" the waves.
Please see Oilfield Services section for additional detail
Source: BP Energy
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:
Page 88
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
Source: Federal Institute of Geosciences and Natural
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
Page 89
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
Page 90
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 bit that 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 well and then plugged and abandoned.
Source: Schlumberger
Source: Encarta
Page 91
Development: Horizontal Drilling
Horizontal Well
Vertical Well Source: Energy Information Administration
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.
Horizontal Drilling reaches deeper into blanket formations Source: www.horizontaldrilling.org
Page 92
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: Schlumberger
Source: Halliburton
Source: Schlumberger
Page 93
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.
Source: C.S. Garber & Sons
Development: Well Stimulation
Additional fractures allow for better flow of oil and gas trapped within a formation
Page 94
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
Page 95
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. Sample Decline Curve for a Pinedale Tight Gas Well
Source: Ultra Petroleum.
Page 96
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.
Source: Schlumberger
Page 97
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.
Page 98
Oil and Gas Reserves
Exploration & Production: Reserves Producers can add reserves either 1) organically (drill-bit) or 2) through acquisitions Recognizing 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.
100% 80%
PDP
Proved
PUD
60% 40%
Probables
20%
Possibles
0% Source: Credit Suisse
Page 100
Exploration & Production: Estimating Reserves Oil 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.
Page 101
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.
Page 102
Exploration & Production: Reserve Life
80 200 70
68 60
58
60
46
50
37
40 30 20
11 10
A m N or th
W or ld
er ic a
si a A
m er ic a A La tin
Eu ro pe /E ur as ia
A fr ic a
dl e
Ea st
0
id
Years
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.
M
Source: BP Stats
Page 103
THE MIDSTREAM
Midstream
Source: American Petroleum Institute.
Midstream refers to all activities between the production of natural gas
and oil and the end-use markets Midstream activities include transporting, processing, fractionating, and storing
natural gas, natural gas liquids, crude oil and refined products Source: Enterprise Products Partners
Page 105
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.
Natural Gas Midstream
Crude Oil / Refined Products Midstream
El Paso
Enterprise
The Majors
Kinder Morgan
Spectra
Energy Transfer
Plains All American NuStar
Williams
Kinder Morgan
Colonial Pipeline
Sunoco Logistics
ONEOK
Boardwalk
Enbridge
Magellan Buckeye
Page 106
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”. Page 108
NGL Fundamental Drivers Natural gas production requires gathering and processing services Especially 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 production
Absolute level of natural gas produced Mix of natural gas production between rich gas (contains relatively more NGLs) and dry gas (contains small amounts of NGLs) Quarterly Gross Processing Spread (Average of Weekly Spreads)
Quarterly NGL Composite Price (Average of Weekly Prices)
$1.01 $1.03
$1.44
$1.36
1.40
($ / Gal)
1.20
$1.15
$1.04
1.00 0.80
$0.71
1.00
$1.40$1.40
$0.63
$0.73
$0.84
$1.03
$1.16 $0.97
$0.85
$0.81
0.80
$0.88
$0.82
$1.25 $1.08
($ / Gal)
1.60
1.20
$1.65 $1.65
1.80
$0.67 $0.65
$0.70
$0.67 $0.56
$0.58
0.60
$0.40
$0.65
$0.69 $0.59
$0.47
0.40
0.60 0.40
0.20
0.20 0.00
$0.15
$0.23
0.00 1Q08 2Q08 3Q08 4Q08 2008 1Q09 2Q09 3Q09 4Q09 2009 1Q10 2Q10 3Q10 4Q10 2010 1Q11 2Q113Q11TD
1Q08 2Q08 3Q08 4Q08 2008 1Q09 2Q09 3Q09 4Q09 2009 1Q10 2Q10 3Q10 4Q10 2010 1Q11 2Q113 Q11TD
Source: Bloomberg, Credit Suisse, as of 09/07/2011
Page 109
Natural Gas Pipelines & Storage Natural Gas Pipelines
Natural Gas Storage
Dry natural gas can move into interstate or intrastate pipelines or into storage Interstate 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 rates Two favorable characteristics of interstate pipelines: 1) The pipeline does not take title to the commodity and is thus not sensitive to commodity prices 2) Capacity reservation fees provide stable revenue regardless of volumes transported Source: EIA
Page 110
Crude Oil / Refined Products
Crude Oil: Lease Gathering & Marketing 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.
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. Source: American Petroleum Institute
Page 112
Crude Oil / Refined Products Pipelines Major Crude Oil Pipelines
Major Refined Products 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. Source: Allegro Energy Group
Page 113
Refined Products Pipelines: Batching R egular Gasoline R egular Gasoline
Premium Gasoline
Premium Gasoline Jet F uel
D iesel
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. Source: www.pipeline101.com
Page 114
OILFIELD SERVICES, DRILLING & EQUIPMENT
Products & Services
Oilfield Services: Industry Segments 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. The Industry is made up of several segments/life cycle categories. We list them by stage of a new oil & gas field:
1) Exploration/Seismic 2) Drilling 3) Completion 4) Production
2010 Western Service company total revenues: $259B Total Production 33%
Equipment/ Infrastructure 27%
Exploration/ Seismic 5%
Production Services 6%
Drilling Services 25%
Completion 15% Total Revenue: $259B
Contract Drilling 22%
Total Drilling 47%
Source: Spears & Associates
Page 117
OFS - Exploration: Seismic Seismic services and equipment include: Data Acquisition - collection of seismic data Data Processing - third party processing of
Receiver seismic data prior to interpretation vessel Library Sales - multiclient sales of nonexclusive seismic data Software - software products for seismic Streamer processing, interpretation, mapping, s reservoir modeling and characterization, petrophysical evaluation, and engineering analysis that can run on workstations or PCs Geophysical Equipment - data recorders, telemetry systems, geophones/hydrophones, energy sources (vibratory vehicles, air guns, etc.) used in data acquisition.
Marine Seismic Survey
Seismic Output
Source: Spears & Associates, BP Energy, Baker Hughes
Page 118
OFS – Exploration/Drilling: Wireline Logging/LWD Wireline logging includes both open and
Types of Log Measurements:
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).
Electrical properties – resistivity and conductivity Neutron density (porosity) Pressure testing Sonic properties Dimensional measurements Formation fluid sampling Spectroscopy (lithography)
Source: Spears & Associates, Schlumberger, American Association of Petroleum Geologists
Page 119
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: Schlumberger
Page 120
OFS – Contract Drilling: Offshore Rigs 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.
Semisubmersible
Drillship
Jackup
Source: ODS-Petrodata, Noble, Rowan
Page 121
OFS – Contract Drilling: Offshore Rigs by Geography Middle East, SE Asia are the
South America, West Africa, North Sea are the largest
largest jackup markets
floater markets Global jackup markets as % of total
Southeast Asia/Far East 20%
Global floater markets as % of total Other Australia/New Zealand 1% 3%
US GOM 17%
US GOM 12%
Southeast Asia/Far East 15%
Central/South America 10%
Middle East/India 4%
Central/South America 31%
North Sea 9% Med./Africa 19%
Middle East/India 31% Med./Africa 13%
North Sea 15%
Source: ODS-Petrodata, note figures exclude newbuilds
Page 122
OFS – Drilling: Bits Drill bits come in two main categories: Rollercone 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 or Tri-Cone
–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
Fixed Cutter or Polycrystalline Compact Diamond (PDC)
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.
Source: Spears & Associates
Page 123
OFS – Drilling: Fluid System Fluid Circulation 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:
– – – –
Fluid Enters the well at the Bit
Mud pump Mud mixer Shale shaker - to remove cuttings from the subsurface Mud pit – to collect used mud for recirculation
Page 124
OFS – Directional Drilling
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.
Rotary Steerable Technology
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. Source: www.horizontaldrilling.org, Halliburton
Page 125
OFS - Completions Completing the well is the process of
Perforating Casing/ Completion
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.
Reservoir Perforations
Casing
Packers
Completion System
Screen Layers
– Stimulation (see next page) 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
Source: Schlumberger, Halliburton
Page 126
OFS – Completion: Pressure Pumping Pressure pumping consists primarily of
Frac job
Proppants
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.
Frac unit
–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.
Cementing unit
In acidizing, acids can be used to etch away rock. Source: BJ Services, Carbo Ceramics, Independent Oil & Gas Service, Gulftex, ProPublica
Page 127
OFS – Hydraulic Fracturing Equipment Frac Truck
Treating Iron: temporary surface piping, valves and manifolds required to bring fluid treatment down to wellbore from the pump
Treating Iron
Frac Pump
Engine
Cooling System
Transmission
Frac Pump: a high pressure, high volume Frac Pump 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 Power End Expected Lifespan: Up to 2 years
Fluid End Expected Lifespan: Ranges from 500 to 1,400 hours Source: Jereh-PE, Weir SPM, Schlumberger
Page 128
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 Tree
Subsea Tree
– 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.
Umbilical
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 Production System Umbilicals Flowlines
Manifold
Subsea Tree
Source: FMC Technologies, Oceaneering International, Umbilical Manufacturers’ Federation
Page 129
OFS – Production: Offshore Systems Offshore production infrastructure includes:
Offshore Production Development Systems
– 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. Source: MMS, Credit Suisse
Page 130
OFS – Production: Artificial Lift Artificial Lift is a technology for mature oil and
Rod pump
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
ESP
PCP
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
Source: Spears & Associates, Weatherford, Independent Oil & Gas Service, Schlumberger
Page 131
OFS – Production: Compression Compression raises the pressure of natural
Compressor
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
Source: Exterran Holdings, Ariel
Page 132
OFS – Production: Well Servicing Workover rig
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
Coiled tubing unit
–Plug and Abandonment – the process of preparing a well to be permanently closed
Source: Schlumberger, MTG
Page 133
OFS – Drilling/Production: Offshore Logistics Helicopters are used for transporting personnel
Lift Boat
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 Boat
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.
Source: Bristow Group, Superior Energy, Wartstila, MMS
Page 134
OFS –Production: Offshore Construction Pipelay vessels use either the S-lay method in water depths 300')
Source: ODS-Petrodata, note figures exclude newbuilds
Page 144
1
OFS – Contract Drilling: Fleet Age & Growth Trends Established U.S. Drillers vs. Others’ Fleet Age 31.7
30.8
30
Established U.S. Drillers
Deepwater (4,500 ft.+) Rig Supply at year-end
35
Deepwater Expansion: Fleet more than doubling within 5 year span (2008 to 2013E)
= 48% Total Global Fleet
27.4
Average Rig Age (Years)
24.6
25
21.9
21.7 19.0
20
16.1
15 10 5
RDC
Other Avg.
ATW
ESV
RIG
NE
DO
HERO
0
240 6-year CAGR: 14%
200
160
120
80
40
219
2013E
2014E
140
120
99
214 187
174
0 2008
2009
2010
2011E
2012E
35 Fav orable global macro
Risk of obsolescence in light
env ironment and drilling
of commodity price stability +
fundamentals open the door
fav orable y ard economics
for new entrants
encourages established
20
Established Drillers: Floating Rigs Established Drillers: Jackups
6 1
1
2
1
10 6
2 2Q11
2
4Q10
2
3Q10
4
2Q10
3
1Q10
5 1
4Q09
3
3Q09
6 1
2 1 3 2Q09
4
1Q09
6
3
4Q08
1
11 4
3Q08
4
1
9 10
2Q08
4
4
5
1Q08
4
1 4
4Q07
4
1 3
6
3Q07
3
3 1 2
7
2Q07
6
1Q07
5
4Q06
4Q04
6
3 1
3Q06
3Q04
5
2 2
1
2Q06
2
3 3
1
1Q06
1
3
2Q05
1
1Q05
4 1
2Q04
0
11
1
4Q05
10
14
13
this too
8
6
3Q05
8
market entrants capitalize on
8
11
15
5
9
drillers to order again; new er
1Q04
Order Trends: Established U.S. Drillers vs. Others in Recent Order Cycles
# of Rigs Ordered
25
8
1Q11
30
Other Drilling Co's: Floating Rigs Other Drilling Co's: Jackups
Source: ODS-Petrodata, Company data, Credit Suisse estimates
Page 145
THE DOWNSTREAM
The Downstream 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 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. Page 147
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 unplanned reasons, such as fires or other accidents.
Exxon Mobil’s Baytown, TX refinery Sunoco’s Philadelphia, PA refinery BP’s Texas City, TX refinery
Source: www.houstonist.com Source: www.sunoco.com Source: www.state.tx.us
Page 149
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.
Source: www.eia.doe.gov
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 fractions or 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
Page 150
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
Page 151
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. Source: Bloomberg, Credit Suisse estimates
Source: www.zeonglobalenergy.com
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. Page 152
Basic Upgrading Units: Reformer & Desulfurizer Desulfurization unit Source: Marathon Oil
Reformer
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.
Page 153
Source: Marathon Oil
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.
Page 154
Advanced Upgrading Unit: Alkylation Unit
Source: Valero
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.
Page 155
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.
Source: Marathon Oil
Page 156
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
Page 157
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
Page 158
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. Source: www.eia.doe.gov
If crude or product is not being used immediately, then it is stored in fields similar to the one to the left.
Source: www.eia.doe.gov
Page 159
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. Source: Google images
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. Page 160
Refinery Operations
Ownership of Refining Assets
Refineries 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.
US Refining Capacity, by Ownership
Private independent 3.3 MMBD 19% Public independent 4.7 MMBD 27%
Integrated 9.4 MMBD 54%
Source: OGJ
Page 162
Geographical Division
In 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.
Source: www.eia.doe.gov
Page 163
Topic (1) WTI – Brent, Too Much Crude in the Mid-Con
Page 164
Source: MPC
Intermediate Solutions Reliant on Rail Rail Loading Capacity Announcements
700
(KBD)
600
Significant rail loading capacity is being added in 2012 in the Bakken. Barging increasing from Patoka.
500
HES 130kbd
400
Rangeland 100kbd
300
EDOG 100kbd
200
Musket 70kbd
100
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.
2017
2016
2015
2014
2013
2012
4Q12
3Q12
2Q12
1Q12
2011
2010
0
PADD 2 Crude Growth Through Jun-2011 M id w es t (P AD D 2) F ield Pro du c tion o f C rud e O il (T h ou s an d 80 0 75 0 70 0 65 0 60 0 55 0 50 0 May-11
Mar-11
Jan-11
Nov-10
Sep-10
Jul-10
May-10
Mar-10
Jan-10
Nov-09
Sep-09
Jul-09
May-09
Mar-09
Jan-09
45 0
Page 165
Source for all charts: Credit Suisse estimates, Bloomberg, DOE
WTI-Brent to Peak This Winter, Structurally Wider For Longer WTI-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 ?...
$25
$20
$15
$10
$5
$0 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
Mid-Con Supply Demand Chart 4 ,50 0
R e fin ing
P ip eline
Ta nke r + Ba rge
S up ply Grow th
Ra il
4 ,00 0 3 ,50 0
(KBD)
3 ,00 0 2 ,50 0 2 ,00 0 1 ,50 0 1 ,00 0 50 0 0 20 10
20 11
20 12
2 01 3
2 01 4
2 01 5
20 16
20 17
Page 166
Source: Credit Suisse estimates, Bloomberg, DOE
ra ni
10% 18% 18%
15% 15%
10% 10%
12% 9%
14% 11%
8% 8%
4% 4%
6% 4%
21%
22% 22%
18% 18%
15% 13%
26% 26%
27%
27% 27%
24% 24%
19%
19% 14%
12%
8% 6%
0% 24%
35%
37% 37%
36%
30%
12%
20% 50%
53%
54%
50%
26%
Current Futures Strip
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.
Page 167
Source: Company Data and Credit Suisse Estimates
te W Ea as h gl e M Fo Liq ar ui ce r ds l lu d S R ha s ic Sh le h -L al H or e B i ak - S qu iz . id ke W s M n L R ar Sh i ic ce q u h al id l lu e s /T s R S ic hr h ee hal e Fo B SW ar rk ne s S t C a an t S ha nis a h le W oo -C M d ar or ce for e d llu B Sh ar s ne al Sh H e tt or al Sh e n -N al R iv e E er -S B ou as th in er Pi n ne L d Ea iq al ui H ds e ay gle F ne H ur Ric sv ord h o ill S ha n S e Sh h le al - D ale e ry -C G or as e L B A a /T W Fa rne X oo tt ye df S t te ha or vi d lle le S Pi ha Sh ce H al an l e ay e A ce ne rk B sv Gra o as m ni ill a in e/ te B V W os a as lle si h y er C H Sh ot o al riz to e C n -N . ot V to al E l n TX Va ey V lle er tic Po y H al or w de iz r R on ta iv l er C B M
G
Most Projects Still Work at $60 Oil, Bakken Most Sensitive Rates of Return at the Current Futures Strip and $60 per Bbl Oil
60%
$60/Oil and Nat Gas at Futures Strip
40%
Even After Pipelines are Built to Gulf, Challenges Remain Structural Oversupply Versus Refining Capacity GoM Texas (ex-Eagleford) Padd 2 (Core) Eagleford Mississippian Light Crude Capacity
10,000 9,000 8,000
Padd 3 (Core) Bakken Padd 4 (Core) Niobara Uinta
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
7,000
KBD
6,000 5,000 4,000 3,000 2,000 1,000 0 2009
2010
2011
2012
2013
2014
2015
2016
2017
Theoretical Cost to Move EagleFord to PADD I
Page 168
Source: Credit Suisse estimates, MPC
Division by Ownership Type and PADD US Refining Capacity, by PADD
PADD IV 0.6 MMBD 4%
PADD V, 3.1, 18%
PADD I 1.6 MMBD 9%
Private independent 0.1 MMBD 6%
PADD I
Integrated 0.4 MMBD 27%
PADD II 3.6 MMBD 21%
PADD IV
PADD III Private independent 1.9 MMBD 22%
Private independent 0.2 MMBD 32% Integrated 4.9 MMBD 58%
Public independent 0.1 MMBD 21%
Private independent 0.7 MMBD 20% Public independent 0.8 MMBD 21%
Public independent 1.1 MMBD 67%
PADD III 8.4 MMBD 48%
Public independent 1.7 MMBD 20%
PADD II
Integrated 2.1 MMBD 59%
PADD V Private independent 0.4 MMBD 14%
Integrated 0.3 MMBD 47%
Public independent 1.1 MMBD 34%
Integrated 1.6 MMBD 52%
Source: OGJ.
Page 169
Refinery Summary, by PADD and Company
Source: Credit Suisse estimates.
Page 170
Oil Product Marketing
Introduction to Marketing Composite Retail Margins Historical 4-week moving average 1995-Present 70
(cents/gal)
50 40 30 20 10
Jan-95 Mar-95 Jun-95 Sep-95 Dec-95 Feb-96 May-96 Aug-96 Nov-96 Jan-97 Apr-97 Jul-97 Oct-97 Dec-97 Mar-98 Jun-98 Sep-98 Nov-98 Feb-99 May-99 Aug-99 Nov-99 Jan-00 Apr-00 Jul-00 Oct-00 Dec-00 Mar-01 Jun-01 Sep-01 Nov-01 Feb-02 May-02 Aug-02 Oct-02 Jan-03 Apr-03 Jul-03 Sep-03 Dec-03 Mar-04 Jun-04 Aug-04 Nov-04 Feb-05 May-05 Aug-05 Oct-05 Jan-06 Apr-06 Jul-06 Sep-06 Dec-06 Mar-07 Jun-07 Aug-07 Nov-07 Feb-08 May-08 Jul-08 Oct-08 Jan-09 Apr-09 Jun-09 Sep-09 Dec-09 Mar-10 May-10 Aug-10 Nov-10 Feb-11 May-11 Jul-11 Oct-11
-
Source: DOE, Credit Suisse estimates
60
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.
Page 172
Retail Margins Key to Profitability of the Marketing Business
U.S. Retail Margins
NorthWest Europe Retail Margins 80
50
70
40
60
5 YR A vg
20 1 1
5Y R A v g
20 10
20 11
Dec-11
Nov-11
Oct-11
Sep-11
Aug-11
Jul-11
Jun-11
May-11
Apr-11
Mar-11
Dec-11
Nov-11
Oct-11
Sep-11
Aug-11
Jul-11
Jun-11
20 May-11
-
May-11
30
Apr-11
10
Mar-11
40
Feb-11
20
Feb-11
50
Jan-11
30
Jan-11
(cents/gal)
60
Jan-11
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.
(cents/gal)
20 10
Source: www.eia.doe.gov, Credit Suisse estimates
Page 173
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 stores selling 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.
Page 174
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
Page 175
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
Page 177
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)
Emerging Majors
– Fully or majority owned by national governments. – Some have recently started to reach beyond home areas. – Partially state-owned oil companies with public equity. – Have also begun to expand their operations beyond domestic borders.
Page 178
Super Majors (XOM, ENI, CVX, COP, TOT, BP, RDS)
Source: Credit Suisse estimates
Total Oil & Gas reserves – Super Majors (mmboe) 95,000
90,106
91,643
90,795
91,654
91,684
2009
2010
89,892 88,985
90,000
87,825
88,724
85,527 85,000 82,873
80,000
78,214
75,000
70,000 1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
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.
Page 179
Integrateds: Sensitivities Typical Integrated Sensitivity vs Oil Price 30
Typical Integrated Sensitivity vs Oil Price
XOM Correlation
Sensitivity
Net Income, US$/bbl
25 20 15 10
y = 0.2253x + 1.4425 R2 = 0.9457
5
XOM Correlation
5.0% 4.5% 4.0% 3.5% 3.0% 2.5% 2.0% 1.5% 1.0% 0.5% 0.0% 0
0 0
20
40
60 80 WTI, US$/bbl
100
120
20
140
60
80
100
120
140
WTI, US$/bbl
12mth rolling Avg Oil 1.2%
40
y = 0.4674x -0.9256 R2 = 0.7824
12mth rolling Avg Gas 1.2%
% Net Incom e change for +1$/bbl change in OIL
1.0%
1.0%
0.8%
0.8%
0.6%
0.6%
0.4%
% Ne t Incom e change for +1$/boe change in GAS
0.4%
0.2%
0.2%
0.0% HES
STL
CVX
BP
MRO
OMV
XOM
COP
TOT
BG
RDS
0.0% BG
CV X
MRO
STL
COP
BP
HES
XOM
RDS
TOT
OMV
Source: Credit Suisse estimates
Page 180
Profitability – Upstream Driven ROGIC (%) – Segment*
Source: Credit Suisse estimates
ROGIC - upstream
ROGIC - downstream
ROGIC - chemicals
25.0% 20.0% 15.0% 10.0% 5.0% 0.0% 2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
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. *US Integrated Oils only
Page 181
Segment breakdown – Upstream Driven* Segmental capex
ROCE - Segments Upstream
Downstream
25%
Chemicals 23.3%
23.0% 19.9% 20.2%
Upstream
90
20%
Downstream
Chemicals
80
15.7%
70
14.0%
13.2% 11.8% 10.1%
10.6%
10%
9.4%
7.4%
5%
4.9% 3.7%
60 Capex ($bn)
15%
50 40 30
5.0%
20 10
0%
0
2009
2010
3-yr avg
5-yr avg
10-yr avg
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010E
10-yr avg
5-yr avg 3-yr avg
Source: Company, Credit Suisse estimates.
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
*US Integrated Oils only
Page 182
Performance Integrated Oils vs. S&P500 30.0% 24%
25.0% 18%
20.0%
18%
17%
15.0%
15% 12%
9%
10.0% 5% 5.0%
3%
0.0% 0% -5.0%
-4%
-5% -10.0%
-9% -11%
-15.0% -20.0%
Recession
-21%
Recession
-25.0%
-27%
-30.0% 1995
1996 1997
1998
1999
2000 2001
2002
2003
2004 2005
2006
2007
2008 2009
2010
Source: Credit Suisse estimates.
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.
*Estimated end of recession as per St. Louis Federal Reserve Bank
Page 183
Characteristics Average Integrateds Relative P/E vs. S&P500
Low Beta 1.5
160%
1.4
140%
MRO PCA
1.3 HES
120%
SU
1.2
100%
COP ENI
1.1
80%
1
STO
RDS
CVX
60%
BG 0.9
BP
TOT
REP
IMO
40%
0.8 XOM
20%
0.7 0% 1990
1992
1994
1996
1998
2000
2002
2004
2006
2008
0.6
Source: Company, Credit Suisse estimates.
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. Page 184
2010
OUTLOOK FOR BIG OIL
Under-appreciated Cash Flow Growth Potential Longer Term Cash flow Growth and Divs
14.0%
10 - 17 CAGR - Adjusted Total CFPS
2011 Div Yield
CFPS Drives 2015 Multiples Lower
7.0
Historical Multiple, 5 yr Average (IOCs)
6.0
12.0% 10.0%
5.0
8.0%
4.0
6.0%
3.0
4.0%
2.0
2.0%
1.0
0.0%
CVX
MRO
OXY
BP
BP
ENI
ENI
TOT
RDS
MRO
EOG
RDS
TOT
COP
HES
HES
COP
CVX
XOM
0.0 XOM
Source: IEA, JODI, Credit Suisse Estimates
– XOM, RDS and COP should deliver best in class growth+dividend yield
Page 186
Big Oil’s – Portfolio Shift and Performance Prize 10% improvement in cost equals 1% FCF yield
Portfolio Shifting to Long Duration Projects Long Duration, 2009
Long Duration, 2017
Source for all charts: XOM, Credit Suisse estimates
50% 45%
Share of Long Duration
40% 35% 30% 25% 20% 15% 10% 5% 0% COP
CVX
XOM
BP
RDS
TOT
ENI
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
Page 187
Higher Cash Margins on New Upstream Projects Operating Cash Flow per Barrel on Selected New Projects (2011-15 Start-ups) $7 0
$6 0
$5 0
$4 0
$3 0
$2 0
$1 0
MLE & CAFC (405b)
Groundbirch
ACG
Yemen LNG
Rumaila
Guara (BM-S-9)
Junin 5
Tupi (BM-S-11)
Skarv
Qatargas 4
Goliat
AOSP - Base + Ph 1
APLNG
Pazflor Block 17
Mars B
Queensland Gas
Block 31 PSVM
Gorgon
CLOV
Akpo/Egina
Pearl GTL
Kashagan
Wheatstone
Jack/St Malo
OML 138/139 (Usan/UKOT)
$-
Source: Credit Suisse Estimates
– Cash margins on projects starting up in 2011-15 are up to 30-40% higher than existing production – Margins are highest on Canadian oil sands (mined), GTL, US GoM deepwater and offshore West African projects (partly due to the timing of cost recovery)
Page 188
Stocks are discounting a double dip 10
CFROI, FY1
Embedded returns lower than 2010 Average CFROI (LHS) Consensus Brent (RHS)
12.0
CFROI, Embedded
10.0
140 120 100
8.0
6
80
6.0
60 4.0
4
($/bbl)
(%)
8
40
2.0
20
0.0
0
MRO
REP
ENI
STL
OMVV
RDSb
COP
BP
HES
TOTF
XOM
CVX
OXY
Embedded CRFOI
2011E
2010
2009
2008
2007
2006
2005
0
2004
2003
2002
2001
2000
2
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 $60/bbl
Page 189
Source for all charts: Company data, Credit Suisse estimates
Pessimism in future returns by company
INVESTING IN E&P
Evaluating E&Ps: Key Metrics Producers seek to create value by adding, producing and selling oil and natural gas reserves at a return greater than their cost of capital. There are several key metrics that help quantify producer performance:
– Reserve per Share Growth: Basic measure of a producer’s ability to add reserves. Industry average growth over the past five years has been about 8-10% annually.
– Reserve Replacement Ratio: A measure of reserve adds compared to production. Reserve replacement of >100% indicates incremental reserves were added net of production.
– Reserve Life: Indication of inventory depth by comparing how many years of reserves a producer has at current production. Median industry reserve lives are currently ~12.0 years.
– Recycle Ratio: Compares cash flow ($ 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.
Page 191
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 $5.63 per Mcfe as of 4Q10.
Page 192
Evaluating E&Ps: Hedging Producers use derivative instruments to protect against volatility in commodity prices. Common instruments: (1) swaps, (2) collars, (3) floors, and (4) natural gas basis swaps
Basis swaps protect regional gas prices by locking in differentials to NYMEX. Hedging only protects near term cash flows. As hedges roll off, producers are forced to re-hedge at prevailing commodity prices.
Timing of when to put on hedges is an important management consideration. Sample Natural Gas Collar ($ per MMBtu) $14.00 $12.00 $10.00 $8.00 $6.00 $4.00
Collar Floor protects against downside volatility
$2.00
Fe b09
Ja n09
ec -0 8 D
ov -0 8 N
ct -0 8 O
Se p08
ug -0 8 A
Ju l-0 8
Ju n08
$0.00
Source: Bloomberg, Credit Suisse.
Page 193
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.
Page 194
INVESTING IN OILFIELD SERVICES & DRILLING
OFS: The Traditional Upstream Spending Cycle
North Am erica leads the upturn, international markets lag
Cycle begins with upturn in comm odity prices
Int'l m arkets, deepwater markets accelerate and cycle approaches peak earnings
Change in m acro environm ent precipitates decline in com modity prices
North American independents curtail upstream spending
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
Page 196
OFS: Oil Services Activities Through the Cycle Com panies with solid positions in International m arkets as well as deepwater/rem ote areas benefit from pick up in international activity. Key beneficiaries: Large caps, deepwater drillers Oil com panies increasingly focus on new Prospect Identification as existing prospects have been developed. Seismic companies are key beneficiary.
As Drilling and Completions activity picks up, beneficiaries include rig count driven com panies selling drilling materials (e.g. bits, fluids) - margins im prove quickly as m anufacturing absorption issues dissipate.
Initial activity includes W ell Servicing and Production Enhancement, i.e. the fastest way to take advantage of higher com m odity prices is not through the drill bit. Beneficiaries: pressure pum pers, workover drilling contractors
Drilling Services com panies experience price leverage as rig count rises and service utilization increases.
Companies that (1) Install Infrastructure for new developm ents (Production) and (2) provide new drilling rig equipm ent tend to see fastest earnings growth later in the cycle. Stocks respond to backlog growth in m iddle stages of 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.
Page 197
OFS: Stocks Directionally Correlated with Upstream Spending 5.5 4.5
16
4.0
14
3.5
Worldwide QualRig
2011
2010
2009
2008
0.0 2007
0 2006
0.5 2005
2 2004
1.0
2003
4
2002
1.5
2001
6
2000
2.0
1999
8
1998
2.5
1997
10
1996
3.0
1995
12
OFS Relative Stock Index
5.0
18
1994
QualRig ($bil) (Monthly Drill. & Compl. Spending)
20
OFS Relative Stock Performance
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.
Page 198
6
40
4
20
2
Worldw ide QualRig
QualRig ($bil) Monthly Drilling & Completion Spending ($bil)
60
2012E
8
2011E
80
2010
10
2009
100
2008
12
2007
120
2006
14
2005
140
2004
16
2003
160
2002
18
2001
180
2000
20
1999
200
1998
22
1997
220
1996
24
1995
240
1994
Monthly WW Producer Gross Revenue (18Mo. Avg)
OFS: Gross Revenues Drive Upstream Spending
Average Yearly QualRig
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%.
Page 199
OFS – Contract Drilling: Offshore Drillers Dayrates and utilization are key drivers of driller earnings power Worldwide Semi Dayrate/Utilization $440,000
Worldwide Jackup Dayrate/Utilization 100%
Average = 83.9%
$400,000
90%
80%
80% $100,000
70%
50% $200,000 40% $160,000 30%
$120,000
WW Jackup Dayrates
60% $240,000
70%
WW Semi Utilization
$280,000
$80,000
60% 50%
$60,000 40% $40,000
30%
20%
$80,000
20% $20,000
10%
WW Semisubmersible Dayrates
WW Semisubmersible Utilization
WW Avg. Semisubmersible Utilization
WW Jackup Dayrates
WW Jackup Utilization
Jan-11
Jan-10
Jan-09
Jan-08
Jan-07
Jan-06
Jan-05
Jan-04
Jan-03
Jan-02
Jan-01
Jan-00
Jan-99
Jan-98
Jan-97
Jan-96
Jan-95
Jan-94
Jan-93
0% Jan-92
$0 Jan-91
Jan-11
Jan-10
Jan-09
Jan-08
Jan-07
Jan-06
Jan-05
Jan-04
Jan-03
Jan-02
Jan-01
Jan-00
Jan-99
Jan-98
Jan-97
Jan-96
Jan-95
Jan-94
Jan-93
Jan-92
Jan-91
0% Jan-90
$0
10%
Jan-90
$40,000
WW Avg. Jackup Utilization
Source: ODS-Petrodata
Page 200
WW Jackup Utilization
$320,000 WW Semi Dayrates
$120,000
90%
$360,000
100%
Average Utilization = 83.3%
OFS – Contract Drilling: Offshore Drillers
Stocks are generally correlated with dayrate trends
16.00
$250,000
$200,000
14.00
Absolute R-squared =
0.81
Relative R-squared =
0.79
Offshore Dayrates
12.00 10.00
$150,000
8.00 $100,000
6.00 4.00
$50,000 2.00
CSFB OFS Index: Absolute Performance
CSFB OFS Index: Relative Performance
Dec-10
Dec-09
Dec-08
Dec-07
Dec-06
Dec-05
Dec-04
Dec-03
Dec-02
Dec-01
Dec-00
Dec-99
Dec-98
Dec-97
Dec-96
Dec-95
Dec-94
Dec-93
Dec-92
0.00 Dec-91
$0
WW Offshore Dayrates (unweighted)
Source: ODS-Petrodata
Page 201
OFS: Traditional Valuation Methodologies Services – as an earnings momentum group, we
Prior Cy cle ('96-mid '98)
10 5
High =
Nov '04 - Aug
25.8x
'08:
Av e. =
High = 24.3x
Current = 11.6x
Av e. = 17.0x Dec-04 Feb-05 Apr-05 Jun-05 Aug-05 Oct-05 Dec-05 Feb-06 Apr-06 Jun-06 Aug-06 Oct-06 Dec-06 Feb-07 Apr-07 Jun-07 Aug-07 Oct-07 Dec-07 Feb-08 Apr-08 Jun-08 Aug-08 Oct-08 Dec-08 Feb-09 Apr-09 Jun-09 Aug-09 Oct-09 Dec-09 Feb-10 Apr-10 Jun-10 Aug-10 Oct-10 Dec-10 Feb-11 Apr-11 Jun-11 Aug-11
0
Offshore Asset Replacement Cost Trend 180.0%
Maximum = 166%
160.0%
Current = 81%
140.0% 120.0% 100.0% 80.0% 60.0% 40.0%
Minimum = 41%
20.0%
Q111
Current
Q310
Q110
Q309
Q109
Q308
Q108
Q307
Q107
Q306
Q106
Q305
Q105
Q304
Q104
Q303
Q103
Q302
Q102
Q301
Q101
Q300
Q100
Q399
Q199
0.0% Q398
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
15
Q198
Drillers – with high asset intensity associated with
20
Q397
extend out as far as three years, lends itself to DCF. However, forward earnings metrics are also used
25
Q197
Equipment – the backlog visibility, which can
30
P/E
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 “midcycle” earnings estimates
Diversified Service Forward P/E Trend
Page 202
OFS: Indicators
Leading 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
Page 203
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.
Page 204
INVESTING IN REFINING
Refining Margins Drive Refinery Value
Refining 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. Refinery – processing center
Finished product Source: Google images
Barrel of crude
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.
Page 206
US$/gal 1.95 1.74
US$/bbl (x 42) 81.90 72.93
x 2/3 x 1/3
68.59
x1
Gasoline Distillate Product price WTI crude Gulf Coast 3:2:1 refining margin
Source: Bloomberg, Credit Suisse estimates
How to Calculate Benchmark Refining Margins 54.60 24.31 78.91 68.59 10.32
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.
Page 207
Why We Use Theoretical Benchmark Margins Distillate
Source: Bloomberg, Credit Suisse estimates
Gasoline
$35 $30 $25
$/bbl
$20 $15 $10 $5 $$(5) 1Q2011
2Q2010
3Q2009
4Q2008
1Q2008
2Q2007
3Q2006
4Q2005
1Q2005
2Q2004
3Q2003
4Q2002
1Q2002
2Q2001
3Q2000
4Q1999
1Q1999
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. Page 208
Source: DOE, Credit Suisse estimates
1 00 95 90 85 80 75
Sep-09
Sep-07
Sep-05
Sep-03
Sep-01
Sep-99
Sep-97
Sep-95
Sep-93
Sep-91
70 Sep-89
US refining capacity distillation utilization %
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. Page 209
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).
Source: www.ogj.com
Page 210
$0.70
$20
$0.60 $0.50
$15
$0.40 $0.30
$10
$0.20 $0.10
$5
$0.00
Gasoline-Resid
3Q09 1Q10
3Q08 1Q09
1Q07 3Q07 1Q08
1Q06 3Q06
1Q05 3Q05
1Q04 3Q04
3Q02 1Q03 3Q03
3Q01 1Q02
3Q00 1Q01
$0 3Q99 1Q00
-$0.10
WTI-Maya Spread (US$/bbl)
$25
$0.80
1Q98 3Q98 1Q99
Gasoline-Resid Spread (US$/gal)
$0.90
Source: Bloomberg, Credit Suisse estimates
Why Not Make Every Refinery Complex?
WTI-Maya
Complex refineries can run different types of crude, quickly change product slates and produce more higher value products, so why not make every refinery complex? The upfront capital costs to add complexity are high and maintenance can be expansive. For some locations, more simple refineries may make sense. Above, we show historic crude and product differentials. A greater differential in the light-heavy spread favors complex refineries who run heavier crude but produce a similar light product yield to a simpler refinery processing light crude. Higher differentials between gasoline and residual fuel oil favor complex refiners, many of whom do not produce any fuel oil as a final product. Page 211
Example of the Economics for a Simple vs. Complex Refinery
Singapore complex US$/bbl Refined products Gasoline Naphtha Jet/Kerosene Gas oil Fuel oil
Dubai yield % 11.9% x 5.1% x 9.9% x 24.4% x 46.2% x 97.5%
Product prices 36.75 29.25 54.15 57.85 32.61
Dubai yield % 26.6% x 7.4% x 4.0% x 38.6% x 22.3% x 98.9%
Product prices 36.75 29.25 54.15 57.85 32.61
= = = = =
= = = = =
Output value 4.37 1.49 5.36 14.12 15.07 40.41 -
Crude cost
Output value 9.78 2.16 2.17 22.33 7.27 43.71 -
Crude cost
37.02 =
37.02 =
Gross margin
3.39 -
Gross margin
6.69 -
Operating cost
2.00 =
Operating cost
3.50 =
Cash margin
1.39
Cash margin
Source: Credit Suisse estimates
Singapore simple US$/bbl Refined products Gasoline Naphtha Jet/Kerosene Gas oil Fuel oil
3.19
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. Page 212
Source: Google Images
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. Page 213
9.0 8.5 8.0 7.5 7.0 6.5 6.0 5.5 5.0 4.5 4.0 3.5 3.0 2.5 2.0 1.5 1.0 0.5 0.0
VLO EPS forecast VLO share price 75 70 65 60 55 50 45 40 35 30 25 20 15 10 5 0 SUN NTM EPS
VLO share price
9.0 8.5 8.0 7.5 7.0 6.5 6.0 5.5 5.0 4.5 4.0 3.5 3.0 2.5 2.0 1.5 1.0 0.5 0.0 95
85
65
55
45
35
25
15
6.0 5.5 5.0 4.5 4.0 3.5 3.0 2.5 2.0 1.5 1.0 0.5 0.0 TSO EPS forecast TSO share price
50
40
30
20
10
0
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.
Page 214
TSO share price
Sunoco
9/22/2006 12/15/2006 3/09/2007 6/01/2007 8/24/2007 11/16/2007 2/08/2008 5/02/2008 7/25/2008 10/17/2008 1/09/2009 4/03/2009 6/26/2009 9/18/2009 12/11/2009 3/05/2010 5/28/2010 8/20/2010 11/12/2010 2/04/2011 4/29/2011 7/22/2011
75 TSO NTM EPS
SUN EPS forecast SUN share price
SUN share price
Valero
9/22/2006 12/15/2006 3/09/2007 6/01/2007 8/24/2007 11/16/2007 2/08/2008 5/02/2008 7/25/2008 10/17/2008 1/09/2009 4/03/2009 6/26/2009 9/18/2009 12/11/2009 3/05/2010 5/28/2010 8/20/2010 11/12/2010 2/04/2011 4/29/2011 7/22/2011
9/22/2006 12/15/2006 3/09/2007 6/01/2007 8/24/2007 11/16/2007 2/08/2008 5/02/2008 7/25/2008 10/17/2008 1/09/2009 4/03/2009 6/26/2009 9/18/2009 12/11/2009 3/05/2010 5/28/2010 8/20/2010 11/12/2010 2/04/2011 4/29/2011 7/22/2011
VLO NTM EPS
US refiners are earnings momentum stocks Tesoro 70
60
OUTLOOK FOR REFINING
US gasoline demand has likely peaked…..FOREVER US Gasoline demand Long Term
Source: Credit Suisse estimates
US gasoline consumption KBD
10,000
Economic bounce back slows decline in 2010
9,000
8,000
7,000
6,000
5,000 2007
2008
2009
2010
2011
2012
Gasoline demand after CAFE
2013
2014
2015
2016
2017
2018
2019
2020
Refiner Gasoline demand after CAFE and RFS
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. Page 216
Over Capacity in the Industry 3000
2500
2000
Source: Credit Suisse
KBD
1500
1000
500
0
-500
-1000 2006 North America
2007 OECD Europe
2008 South America
2009 FSU/Other Europe
2010 Africa
2011E Middle East
2012E OECD Pacific
2013E Other Asia
2014E Biofuels
2015E Demand growth
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 Page 217
US Crude Over Supply Throws a Lifeline to Mid-Con Refiners Structural Oversupply Versus Refining Capacity GoM Texas (ex-Eagleford) Padd 2 (Core) Eagleford Mississippian Light Crude Capacity
10,000 9,000 8,000
Padd 3 (Core) Bakken Padd 4 (Core) Niobara Uinta
7,000
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
KBD
6,000 5,000 4,000 3,000 2,000 1,000 0 2009
2010
2011
2012
2013
2014
2015
2016
2017
Embedded Returns in US Refiners (HOLT)
Page 218
Source: Credit Suisse estimates, HOLT
INVESTING IN MLPS
What is an MLP? Typical MLP Structure
Real Assets
Real Cash Flow
Real Company Housed in a master limited partnership structure
MLP
Source: Credit Suisse analysis
Page 220
MLP Assets 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
Source: Spectra Energy website, American Petroleum Institute
Page 221
MLP Key Terms Defined 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 partnership General 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 deferred Incentive Distribution Rights (IDRs): Entitle the GP to an increasing portion of distributions (up to 50%) as target distribution levels are attained Distributable Cash Flow (DCF)*: maximum amount of cash flow available to pay limited partners after taking into account maintenance capital requirements and the general partner entitlement Schedule K-1: Investors receive Schedule K-1s instead of Form 1099s UBTI: MLPs generate unrelated business taxable income (UBTI)
*Credit Suisse definition
Page 222
MLP Business Model: Distribution Sustainability is Key MLPs pay out majority of available
Cash Flow Characteristics
cash flow Access debt/equity markets needed to finance growth
Benefit of business model:
– Too little can mean lower cash flow over time
transparency and focus on cash flow
Cash Flow Coverage of Distribution
Risk to business model:
Reliance on capital markets for growth MLP Debt / Equity Issuance 25.0 20.2
19.1
15.1
($bn)
15.0 10.0 5.0
8.3 5.7 4.9
5.3
9.2 7.0
secure cash flow given reservation fees – E&P/Refining least stable given commodity price risk and depleting asset base
Maintenance Capex
Mandates financial discipline,
20.0
– Gas pipelines and storage most stable and
– More predictable cash flow streams = less need for excess distribution coverage – Less predictable cash flow streams = greater need for excess distribution coverage
16.2
11.5
11.1 8.3 5.6
7.8
6.8
0.0 2004
2005
2006
2007 Debt
2008
2009
2010
YTD
Equity
Source: Factset, Credit Suisse analysis
Page 223
AMZ ML P Ind ex Y ield
MLP Value Proposition
16% 14% 12% 10% 8% 6%
High tax-advantaged yield
5/9 8/2 6 2 / /9 6 28 9 / /97 26 4/ /97 2 1 1 4 /9 /2 8 0 6/ /9 8 18 1/1 / 99 4 8/1 / 00 1/0 3/ 0 9/0 10 1 /5 /0 5 1 11 /3/0 /29 2 6 / /02 27 1 / /03 23 8 / /04 20 3/ /04 1 1 0 8 /0 /1 5 4 5/1 /0 5 2/ 12 06 /8/ 0 7/ 6 6/ 0 2/ 7 1 8 / /0 8 29 3 / /08 2 10 7 /09 /23 05 /09 /2 12 1/ 10 /1 0 7 7/ 1 /1 0 5/1 1
1/
Current yield of 6.6%
4%
Energy MLPs Annual Distribution Growth vs CPI 14.0%
+ Distribution growth 2011E growth of 4.9%
Annual Dist Growth
12.0% 9.1%
10.0% 7.0%
8.0% 6.0% 4.9% 4.5% 4.3% 4.0%
9.4% 8.2%
8.8% 6.8%
3.6% 3.8%
4.9%
4.8%
5.4% 5.0%
2.6% 3.0%
2.0% 0.0% -2.0%
1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011E 2012E 2013E 2014E MLP Distribution Growth (Median)
1200%
Y/Y Change in CPI
Total Return (Since 1996) 886%
1000% 800%
= Attractive total return Expect 10 to 13% total returns
600% 400%
164%
200%
153%
0%
12 /29 / 9/1 95 3/9 5/3 6 0/ 2/1 97 3 10 /98 /30 / 7/1 98 6/9 3/3 9 1 12 /00 /15 / 8/3 00 1/0 5/1 1 7/ 1/3 02 1 10 /03 /17 /0 7/2 3 / 3/1 04 8/0 12 5 /2/ 8/1 05 8/0 5/4 6 / 1/1 07 8/0 10 8 /3/ 6/1 08 9/0 3/5 9 11 /10 /19 /1 8/5 0 /11
-200%
AMZ MLP Index TR
Source: Factset, Bureau of Labor Statistics; Prices as of 09/02/11
S&P500 TR
Russell 2000 TR
Total Return CAGRs: MLPs: 15.7%, S&P 500: 6.1%, R2000: 6.4%
Page 224
Valuation Framework: DDM is Preferred Methodology Follow the Cash, No One Really Cares About Earnings MLPs are primarily valued on their distributions, expectations for distribution growth and perceived risk profile
Valuation Methodologies Distribution 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 record
Target 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 index
Relative Valuation Metrics
– Price / Distributable cash flow (DCF) multiple – Adjusted Enterprise Value / EBITDA multiple
Page 225
Yield Spread Analysis
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 )
A M Z P r ic e/D C F (1 9 9 6-2 0 11 ) 1 8x
1, 40 0 C u rr e n t S p re a d = 4 5 9
1, 20 0
1 6x
A v e ra g e S p re a d = 3 2 2
C S L U C I B B B 7-1 0 Y r S p re a d to 1 0 -Y r T re a su ry (1 9 9 9 -2 0 1 1) 700 600 500 400 300 200 100 0 -100 -200
C u r ren t Sp r ea d = 21 5
70 0
A v era g e Sp r ea d = 20 6
60 0 50 0 40 0 30 0 20 0 10 0 07/01/11
01/07/11
07/16/10
01/22/10
7/31/09
2/6/09
8/15/08
2/22/08
8/31/07
3/9/07
9/15/06
3/24/06
4/8/05
9/30/05
4/23/04
10/15/04
5/9/03
10/31/03
5/24/02
11/15/02
6/8/01
11/30/01
6/23/00
12/15/00
12/31/99
7/9/99
1/15/99
0
AMZ Y ield vs. CS LUCI BBB 7-10 Y r (1999-2011) C urrent = 2 44 ps A ve rag e = 1 18b ps M LPs are attractive vs. IG cre dits
IG cred tis are attra ctive vs. ML Ps 1/15/99 7/9/99 12/31/99 6/23/00 12/15/00 6/8/01 11/30/01 5/24/02 11/15/02 5/9/03 10/31/03 4/23/04 10/15/04 4/8/05 9/30/05 3/24/06 9/15/06 3/9/07 8/31/07 2/22/08 8/15/08 2/6/09 7/31/09 01/22/10 07/16/10 01/07/11 07/01/11
80 0
A v er ag e = 12 .0x
1/5/96 6/28/96 12/20/96 6/13/97 12/5/97 5/29/98 11/20/98 5/14/99 11/5/99 4/28/00 10/20/00 4/12/01 10/5/01 3/28/02 9/20/02 3/14/03 9/5/03 2/27/04 8/20/04 2/11/05 8/5/05 1/27/06 7/21/06 1/12/07 7/6/07 12/28/07 6/20/08 12/12/08 6/5/09 11/27/09 05/21/10 11/12/10 05/06/11
07/01/11
01/07/11
07/16/10
01/22/10
2/6/09
7/31/09
8/15/08
2/22/08
3/9/07
8/31/07
9/15/06
3/24/06
4/8/05
9/30/05
4/23/04
10/15/04
4x 5/9/03
0 10/31/03
6x 5/24/02
20 0
11/15/02
8x
6/8/01
40 0
11/30/01
1 0x
6/23/00
60 0
12/15/00
1 2x
7/9/99
80 0
12/31/99
1 4x
1/15/99
1, 00 0
C u r re n t = 13 .2x
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.
Source: Factset, Alerian website, Credit Suisse analysis; Prices as of 09/08/11
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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) the views expressed in this report accurately reflect his or her personal views about all of the subject companies and securities and (2) no part of his or her compensation was, is or will be directly or indirectly related to the specific recommendations or views expressed in this report. See the Companies Mentioned section for full company names. The analyst(s) responsible for preparing this research report received compensation that is based upon various factors including Credit Suisse's total revenues, a portion of which are generated by Credit Suisse's investment banking activities. Analysts’ stock ratings are defined as follows: Outperform (O): The stock’s total return is expected to outperform the relevant benchmark* by at least 10-15% (or more, depending on perceived risk) over the next 12 months. Neutral (N): The stock’s total return is expected to be in line with the relevant benchmark* (range of ±10-15%) over the next 12 months. Underperform (U): The stock’s total return is expected to underperform the relevant benchmark* by 10-15% or more over the next 12 months. *Relevant benchmark by region: As of 29th May 2009, Australia, New Zealand, U.S. and Canadian ratings are based on (1) a stock’s absolute total return potential to its current share price and (2) the relative attractiveness of a stock’s total return potential within an analyst’s coverage universe**, with Outperforms representing the most attractive, Neutrals the less attractive, and Underperforms the least attractive investment opportunities. Some U.S. and Canadian ratings may fall outside the absolute total return ranges defined above, depending on market conditions and industry factors. For Latin American, Japanese, and non-Japan Asia stocks, ratings are based on a stock’s total return relative to the average total return of the relevant country or regional benchmark; for European stocks, ratings are based on a stock’s total return relative to the analyst's coverage universe**. For Australian and New Zealand stocks, 12-month rolling yield is incorporated in the absolute total return calculation and a 15% and a 7.5% threshold replace the 10-15% level in the Outperform and Underperform stock rating definitions, respectively. The 15% and 7.5% thresholds replace 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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