credit suisse - oil & gas primer
TRANSCRIPT
OIL & GAS PRIMER September 2011The Credit Suisse Energy Team
DISCLOSURE APPENDIX CONTAINS IMPORTANT DISCLOSURES, ANALYST CERTIFICATIONS, INFORMATION ON TRADE ALERTS, ANALYST MODEL PORTFOLIOS AND THE STATUS OF NON-U.S ANALYSTS. FOR OTHER IMPORTANT DISCLOSURES, visit www.credit-suisse.com/ research disclosures or call +1 (877) 291-2683. U.S. Disclosure: Credit Suisse does and seeks to do business with companies covered in its research reports. As a result, investors should be aware that the Firm may have a conflict of interest that could affect the objectivity of this report. Investors should consider this report as only a single factor in making their investment decision.
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Credit Suisse Global Energy Team
Source: Credit Suisse
United States EuropeIntegrated Oils & Refiners Integrated Oils & Refiners Ed Westlake (New York)) +1 212-325 6751 [email protected] Kim Fustier (London) +44 20 7883 0384 [email protected] Rakesh Advani (New York) +1 212 538 5084 [email protected] Thomas Adolff (London) +44 20 7888 9114 [email protected] & Production Exploration & Production Arun Jayaram (New York) +1 212 538 8428 [email protected] Tao Ly (London) +44 20 7888 1778 [email protected] Mark Lear (New York) +1 212 538 0239 [email protected] Ritesh Gaggar (London) +44 20 7888 0277 [email protected] David Lee (New York) +1 212 325 6693 [email protected] Arpit Harbhajanka (London) +44 20 7888 0151 [email protected] Services Oil Services Brad Handler (New York) +1 212 325 0772 [email protected] Tao Ly (London) +44 20 7888 1778 [email protected] Eduardo Royes (New York) +1 212 538 7446 [email protected] Arpit Harbhajanka (London) +44 20 7888 0151 [email protected] Jonathan Sisto (New York) +1 212-325-1292 [email protected] UtilitiesMLPs Vincent Gilles (London) +44 20 7888 1926 [email protected] Yves Siegel (New York) +1 212 325 8462 [email protected] Mark Freshney (London) +44 20 7888 0887 [email protected] Brett Reilly (New York) +1 212 538 3749 [email protected] Stephen Deeley (London) +44 20 7883 9534 [email protected] Michel Debs (London) +44 20 7883 9952 [email protected] Dan Eggers (New York) +1 212 538 8430 [email protected] Mulu Sun (London) +44 20 7888 0269 [email protected] Kevin Cole (New York) +1 212 538 8422 [email protected] Zoltan Fekete (London) +44 20 7888 0285 [email protected] Matt Davis (New York) +1 212 325 2573 [email protected] Specialist Sales Katie Chapman (New York) +1 212 325 1261 [email protected] Jason Turner (London) +44 20 7888 1395 [email protected] Energy Mark Whitfeld (London) +44 20 7888 8038 [email protected] Satya Kumar (San Francisco) +1 415 249 7928 [email protected] Ed Westlake (New York)) +1 212-325 6751 [email protected] Patrick Jobin (New York) +1 212 325 0843 [email protected] Latin AmericaSpecialist Sales Oil & Gas Tom Marchetti (New York) +1 212 325 0667 [email protected] Emerson Leite (Sao Paulo) +55 11 3841 6290 [email protected] Charlie Balancia (New York) +1 212-325 6314 [email protected] Utilities
Vinicius Canheu (Sao Paulo) +55 11 3841 6310 [email protected], Agribusiness and Transportation
Canada Luiz Campos (Sao Paulo) +55 11 3841 6312 [email protected] Brian Dutton (Toronto) +1 416 352 4596 [email protected] Andrew Kuske (Toronto) +1 416 352 4561 [email protected] Courtney Morris (Toronto) +1 416 352 4595 [email protected] Australia Paul Tan +1 416 352 4593 [email protected] Sandra McCullagh (Melbourne) +61 2 8205 4729 [email protected] Jason Frew (Calgary) +1 403 476 6022 [email protected] Nik Burns (Melbourne) +61 3 9280 1641 [email protected] Terence Chung (Calgary) +1 403 476 6024 [email protected] Ben Combes (Melbourne) +61 3 9280 1669 [email protected] David Phung (Calgary) +1 403 476 6023 [email protected]
Asia-PacificRussia/Emerging Europe David Hewitt (Singapore) +65 6212 3064 [email protected] & Gas Horace Tse (Hong Kong) +852 2101 7379 [email protected] Mark Henderson (London) +44 20 7883 6901 [email protected] Edwin Pang (Hong Kong) +852 2101 6406 [email protected] Andrey Ovchinnikov (Moscow) +7 495 967 8360 [email protected] Yang Song (Hong Kong +852 2101 6550 [email protected] Trina Chen (Hong Kong) +852 2101 7031 [email protected] Anton Fedotov (Moscow) +7 495 967 8362 [email protected] Sanjay Mookim (Mumbai) +91 22 6777 3806 [email protected]
Yuji Nishiyama (Tokyo) +81 3 4550 7374 [email protected] Siriporn Sothikul (Bangkok) +66 2 614 6217 [email protected] Poom Suvarnatemee (Bangkok) 66 2 614 6210 paworamon.suvarnatemee@credit-suisse. A-Hyung Cho (Seoul) +82 2 3707 3735 [email protected] Annuar Aziz Kuala Lumpur) +603 2723 2085 [email protected] Sidney Yeh (Taipei) +8862 2715 6368 [email protected]
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Johannesburg
MoscowLondon
New York
Toronto
Sao Paulo
Hong Kong
SeoulTokyo
Call us anywhere: we can help you
Credit Suisse Global Energy Team
Kuala Lumpur
Sydney
BangkokSingapore
Sou
rce:
Cre
dit S
uiss
e.
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Crude OilCrude Oil Overview 6Crude Oil Supply 12International Offshore Exploration 19 Crude Oil Demand 27Global Oil Markets 32
Natural GasNatural Gas Overview 39
North American Natural Gas 45Shale Gas in Focus 57Liquefied Natural Gas (LNG) 67
The UpstreamThe Upstream Process 83
Oil and Gas Reserves 99
The MidstreamNatural Gas 107Crude Oil/Refined Products 111
Oilfield Services, Equipment and DrillingProducts and Services 116
Company Specific Details 136
The DownstreamRefining 148
Refinery Operations 161Oil Product Marketing 171
Table of contents
Investing in Big Oil 176
Outlook for Big Oil 185
Investing in E&P 190
Investing in OFS 195
Investing in Refining 205
Outlook for Refining 215
Investing in MLPs 219
Industry Overview Basics of Energy Investing
CRUDE OIL
Crude Oil Overview
Page 7
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
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Crude Oil Composition
Crude oil ranges from almost clear water-like fluids to black viscous semi-solids.Crude oil can be categorized into various API degrees of gravity. The higher the API gravity, the lighter the crude. Crude oils with higher API gravity yield greater proportions of lighter petroleum products like gasoline.
Arab LightIranian HeavyBasrah Light
Fateh
ANS
Tapis
Brent
Bonny LightCabindaBonny Medium
Arab Heavy Arab Medium
Maya
WTI
Cold Lake
0.0%
0.5%
1.0%
1.5%
2.0%
2.5%
3.0%
3.5%
4.0%
4.5%
0 5 10 15 20 25 30 35 40 45 50
Heavy API Gravity Light
Sw
eet
Sul
fur C
onte
ntS
our
Crude oils with higher than average sulfur content are known as “sour.” Those with low sulfur levels are called “sweet.”The majority of global reserves are light/medium and slightly sour.
Source: DOE
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Global Oil ReservesS
ourc
e: B
P S
tats
The majority of the world’s current proved oil reserves are in OPEC countries.The BP Statistical Energy Review states that 956 billion barrels or 76% of the world’s proved reserves are held by OPEC. 754 billion of these are in the Middle East.The remaining 302 billion barrels or 24% of the world’s proved reserves are in non-OPEC regions. The former Soviet Union holds 42% of non-OPEC proved reserves.Additionally, the Canadian oil sands contain 150.7 billion barrels of proved reserves.
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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”).
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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.
Sou
rce:
BP
Sta
ts
Crude Oil Supply
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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
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Global Production Split: OPEC and Non-OPEC
OPEC accounts for roughly 40% of global oil supply, a sharp increase from the trough of 1985, but still lower than its historical level of 55%+ pre-1973/74.
Non-OPEC (ex-Former Soviet Union or FSU) production grew rapidly in the 1960s, 1970s/80s and the 1990s. However, non-OPEC supply growth has slowed in recent years.
Non-OPEC’s restricted access to new reserves, combined with higher decline rates, are the reasons.
Sou
rce:
IEA
, Cre
dit S
uiss
e es
timat
es
OPEC Oil Production*
* Assumes no inventory change: 2009 - 2012
0
5
10
15
20
25
30
35
40
1974
1976
1978
1980
1982
1984
1986
1988
1990
1992
1994
1996
1998
2000
2002
2004
2006
2008
2010
E
201
2E
Cru
de O
il Pr
oduc
tion
(MM
BD
)
0%
10%
20%
30%
40%
50%
60%
Global M
arket Share (%)
OPEC Supply [LHS] Market Share [RHS]
Page 15
OPEC’s Spare Capacity: a Key Measure
Most of the time OPEC withholds existing supply from the market, creating spare capacity’ i.e., oil which could be produced, but is offline.
Anticipated levels of future spare capacity have important effects on crude prices generating more or less fear about supply (see markets and pricing section).
Sou
rce:
IEA
, Cre
dit S
uiss
e es
timat
es –
adju
sted
for L
ibya
-6.0
-4.0
-2.0
0.0
2.0
4.0
6.0
8.0
Jan-01 Jan-02 Jan-03 Jan-04 Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11
Millio
n Ba
rrel P
er D
ay
0
20
40
60
80
100
120
140
160
WTI
, $/b
bl
Spare Capacity Demand Less Supply Growth WTI (RHS)
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Watching OPEC Capacity Additions
OPEC’s current policy appears to be to add new capacity only in line with expected increases in demand: “investing behind the demand curve.”
OPEC capacity additions between 2011-2012 are expected to be modest.
OPEC Net Capacity Additions
Sou
rce:
IEA
, Cre
dit S
uiss
e es
timat
es
-1.70
-1.20
-0.70
-0.20
0.30
0.80
1.30
1.80
2007
2008
2009
E
2010
E
2011
E
2012
E
2013
E
Algeria Angola Ecuador Iran Iraq KuwaitLibya Nigeria Qatar Saudi Arabia UAE Venezuela
Page 17
Iraq: Significant potential, But Infrastructure a Challenge
Could change perception of long-term supply.
0%
5%
10%
15%
20%
25%
Sau
diA
rabi
a
Iran
Iraq
Kuw
ait
Ven
ezue
la
UA
E
Rus
sia
Liby
a
Kaz
akhs
tan
Nig
eria
% World reserves % World production
Iraqi oil production over time – rise and fall Iraq – 9% of world reserves, 3% of world production
Source for top charts: IEA, industry data, Credit Suisse estimates
Iraqi Civilian Deaths Jan 2006 – Aug 2009 Oil projects awarded and growth
Source: Iraq Oil Forum
0
2500
5000
7500
10000
12500
1979
1981
1983
1985
1987
1989
1991
1993
1995
1997
1999
2001
2003
2005
2007
2009
E
2011
E
2013
E
2015
E
Pla
teau
Baseline 1st round projects 2nd round projects Kurdistan
Iran/Iraq warGulf war
Gulf war II
Impliedpotential
Reserves (BB)Initial Rate (MMB/d)
Cost Recovery Floor (MMB/d)
Targeted Plateau Rate (MMB/d)
1st round awardsRumaila 17.77 1.05 1.155 2.85Zubair 4.08 0.195 0.2145 1.125West Qurna Phase-1 8.58 0.26 0.286 2.325Sub-total 30.43 1.51 1.66 6.30
2nd round awardsMajnoon 12.58 0.046 0.175 1.800West Qurna Phase-2 12.88 0.000 0.120 1.800Halfaya 4.10 0.003 0.070 0.535Garraf 0.86 0.000 0.035 0.230Badra 0.11 0.000 0.015 0.170Qaiyarah 0.81 0.000 0.030 0.120Najmah 0.86 0.000 0.020 0.110Sub-total 32.19 0.05 0.465 4.765
Total 62.62 1.55 11.07
Source: Department of Defense
Page 18
Onshore Growth Accelerating; We Need Offshore Too
Non-OPEC supply expected to be lacklustre through 2014 even with onshore growth in the US
A surge in deepwater projects helps lift Non-OPEC supply beyond 2014
US Onshore Supply Growth and Infrastructure
Sou
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IEA
, Cre
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uiss
e es
timat
es
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
2010 2011 2012 2013 2014 2015 2016 2017
(KBD
)
Refining Pipeline Rail
Tanker + Barge Supply Growth
Deepwater Hockey Stick
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
2000 2002 2004 2006 2008 2010E 2012E 2014E 2016E
West Africa US Gulf of Mexico Brazil Ghana Other D
Deepwater hockey stick
International Offshore Exploration Success Improving
Page 20
Brazil is Still the Largest Hot SpotS
ource: Petrobras
BM-S-22
Focus area has been Santos Basin (Tupi Cluster)
Blocks BMS-8, 9, 21, 22 (Sugar Loaf) area, together with BMS-11 (Tupi) and BMS-24 (Jupiter)
Page 21
(1) Teak could potentially be larger than the market expects. The third and fourth appraisal wells could create a standalone development
(2) The left chart shows Tullow presentation of Teak in August. The Right shows KOS view. Appraisal will determine how large Teak truly is.
(3) The are large fans underneath the giant Tweneboa Discovery that have yet to be tested
(4) Cedrela will test the Cenomanian fairway in which HES has enjoyed success
(5) Other targets in 2012 include Wawa, Wassa, Sapele in Deepwater Tano Block and new Albian prospects are being worked up.
Ghana: Could Be Larger Than We Currently Think
Page 22
French Guiana/Suriname – Zaedyus Game Changer
Source: APC, TLW
(1) Tullow believes Zaedyus discovery could be 700mmboe, with 5-6 more similar prospects in the near vicinity.
(2) Tullow believe the fan structure is larger than the entire Tano basin in Ghana
(3) Matamata is an additional large structure in the West of this block
(4) Further drilling activity in Block 47, Georgetown offshore Suriname
Page 23
1st Successful Wildcat in Guyana Basin
Source: APC, TLW
Page 24
Africa : More Late Cretaceous
Testing Liberia, Sierra Leone, Cote D’Ivoire (APC)
Large multi-hundred million barrel prospects being targets by APC, Tullow, CVX in Sierra Leone, Liberia and Cote D’Ivoire in 2H11/1H12
CVX spuds Liberia acreage in 4Q11
Montserrado Deep is important – potentially opens up a new basin in Liberia
Source: APC, TLW
Page 25
West Africa Exploration to the Forefront – Pre Salt AngolaAngola Pre-Salt
Source: CIE
Cobalt Pre-Salt – Drilling Cameia Currently
Page 26
US Gulf of Mexico S
ource: Wood M
ackenzie; CVX
US GoM Reserves, 78% Held by Supermajors
0
5 00
10 00
15 00
20 00
25 00
30 00
35 00BP
Shell
Chev
ron
Stato
il
Anad
arko
BHP
Billit
on
Petro
bras
Exxo
nMob
il
HESS En
i
Plain
s E&P
Mar
athon
COP
Nexe
n
Devo
n En
ergy
Noble
Ene
rgy
Total
Reps
ol YP
F
Mae
rsk ME
ATP
Deep
wate
r Gulf
of M
exico
Res
erve
s, M
B
• The US Gulf of Mexico contains significant resource but drawbacks are liability concerns and permitting delays
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
RemainingReserves inProduction
Reserves inAppraisal
RecentlyDiscovered
Future GeologicalPotential
Millio
n BO
E
Crude Oil Demand
Page 28
Oil Demand
Oil demand grew by a CAGR of 1.5% from 1992 to 2008.
We expect global oil demand to rise by about 1.9% in 2010.
We expect oil demand to grow at 1.4% per annum from 2011 to 2017.
Oil demand growth has been historically correlated with GDP growth, but not exclusively so. Price, taxation and fuel switching have all driven significant changes in consumption patterns.
The future of oil demand growth is presumed to be outside the OECD: mainly in China, India and other developing economies.
The principal uses for oil are transportation, power generation, and heating.
The highest value use of oil today is as a transportation fuel. As countries become richer they tend to reduce or phase out their industrial uses of oil.
Oil demand is price elastic: different consuming zones exhibit different price elasticity to crude prices. This is partly due to different end user taxation levels (the United States and China have low taxes, Europe has high taxes) and partly due to the relative availability of substitute fuels.
Page 29
Oil Demand Correlation with Real GDP Growth (1969 - 2008)S
ource: BP S
tats, Credit S
uisse estimates
Global GDP trends are a clear underlying driver of oil demand.
However, the relationship is uneven and consuming regions exhibit very different demand multipliers to GDP (~1 in emerging economies, ~0.5 in the OECD).
R2 = 0.5802
0.0%
1.0%
2.0%
3.0%
4.0%
5.0%
6.0%
7.0%
-6.00% -4.00% -2.00% 0.00% 2.00% 4.00% 6.00% 8.00% 10.00%
Worldwide Oil Consumption Growth
Wor
ld R
eal G
DP G
row
th
Page 30
Oil Demand Growth & Oil Prices
Source: Credit Suisse
7.2%
8.4%
5.5%
7.3%
8.0%
-1.5%
1.3%
5.9%
-4.1%
-2.3%
1.4%
0.3%
2.7%2.3%
0.8% 0.9%0.8%
2.2%2.4%2.8%
1.7%1.4%
0.2%
-1.5%
1.9%1.6%
2.9%
-0.5%
1.7%
0.6%
8.9%8.2%
3.7%
4.2%
3.0%
1.1%0.8%1.2%
0.5%
-2.9%
2.3%2.1%
0.5%
1.4%
-6%
-5%
-4%
-3%
-2%
-1%
0%
1%
2%
3%
4%
5%
6%
7%
8%
9%19
6619
6719
6819
6919
7019
7119
7219
7319
7419
7519
7619
7719
7819
7919
8019
8119
8219
8319
8419
8519
8619
8719
8819
8919
9019
9119
9219
9319
9419
9519
9619
9719
9819
9920
0020
0120
0220
0320
0420
0520
0620
0720
0820
0920
10E
Glo
bal O
il D
eman
d G
row
th
0
10
20
30
40
50
60
70
80
90
100
110
Infla
tion
adju
sted
Bre
nt p
rice
US$
per
bbl
Demand growth Real Brent Oil Price (USD/bbl), 2007
Recovery
Recession Recession
SPIKE
Collapse
Recovery
Saudis change policy
18 years of low and stable oil prices 1986-2004
Recession
Recovery
Boom
Recession
BoomBoom
Recession
Recovery
Boom
SPIKE
The Good Old Days
Recovery
Oil is a cyclical commodity (with managed characteristics).
Higher oil prices during booms create deeper demand recessions afterwards.
Page 31
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.
Sour
ce: B
P St
ats.
Global Oil Markets
Page 33
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 34
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 35
Oil Markets: Trading
Futures trading: standardized, exchange-traded contracts in which the contract buyer agrees to take delivery, from the seller, a specific quantity of crude oil at a predetermined price on a future delivery date.
Over-the-Counter Swaps etc: instead of trading via a futures exchange, buyers and sellers of crude oil can enter into an over the countertransaction, often known as a swap. These contacts have become more popular than futures trading in recent years, but can prove difficult to liquidate at times of market dislocation.
Term contracts: private contracts to buy specified quantities of crude oil at prices based on regional benchmarks. These contracts are not traded in any form. Most Kuwaiti crude oil is sold on term contracts, with the price of Kuwaiti crude oil tied to Saudi Arabian Medium (for western customers) and a monthly average of Dubai and Oman crudes (for Asian buyers).
Page 36
International Energy Agency (IEA): Every month, the IEA releases the “Oil Market Report,” which contains information on supply, demand, stocks, prices, and refinery activity. U.S. Department of Energy: The DOE provides weekly information on crude and principal petroleum products in regards to factors such as supply, imports, inventories and refinery activity. Market participants utilize these types of data sources in order to form opinions on companies as well as the expected direction of the commodity.
Oil Markets: Data Sources
Source: IEA
Source: IEA
Page 37
Futures Curve: Backwardation vs. Contango
$77.09
$72.04$72.49 $73.04 $73.61
$74.11 $74.62$75.10 $75.60
$76.10 $76.47 $76.77
$65
$70
$75
$80
Oct
09
Nov
09
Dec
09
Jan
10
Feb
10
Mar
-10
Apr
-10
May
-10
Jun-
10
Jul-1
0
Aug
-10
Sep
-10
Pric
e pe
r ba
rrel
The shape of the 12-month futures curve is often an indication of current supply/demand balances.An upward sloping curve suggests higher expected prices and implicitly higher demand relative to supply in the future: ContangoA downward sloping curve suggests current demand is outpacing current supply with the expectation that the imbalance will become less pronounced in the coming time period: Backwardation
Source: Bloomberg
Futures Curve: Contango Example Futures Curve: Backwardation Example
Source: Bloomberg
$72.04
$77.09 $76.77$76.47 $76.10$75.60$75.10 $74.62
$74.11 $73.61$73.04
$72.49
$65
$70
$75
$80
Oct
09
Nov
09
Dec
09
Jan
10
Feb
10
Mar
-10
Apr
-10
May
-10
Jun-
10
Jul-1
0
Aug
-10
Sep
-10
Pric
e pe
r ba
rrel
NATURAL GAS
Natural Gas Overview
Page 40
What is Natural Gas?
Natural Gas is a combustible, colorless and odorless gas that is made up of a mixture of hydrocarbons.Methane (which is dry gas) is the most commercially marketable component of the natural gas stream. Other components of the typical well-head natural gas stream (wet gas) include heavier “liquids” such as ethane, propane and butane. Natural Gas is measured on a unit basis in thousands of cubic feet (Mcf). The benchmark spot price is Henry Hub, which is quoted on a $ per Millions of British Thermal Units basis (MMBtu). An Mcf is a volume unit, while MMBtu is an energy measurement.Because of the need for extensive pipeline systems and difficulty in shipping, natural gas is most used in regions with indigenous supply. Meanwhile, the ability to ship gas in liquid form (LNG) is gaining traction.
Source: Chesapeake Energy
Page 41
Global Natural Gas: Proved Reserves (2010)
North America350 Tcf
Asia Pacific575 Tcf
South & Central America264 Tcf
Middle East2,675 Tcf
Source: BP Statistical Review of World Energy 2011.
Europe & Eurasia2,227 Tcf
Total Proved Reserves were over 6,600 trillion cubic feet at year-end 2010.
Africa522 Tcf
Page 42
World Energy: Natural Gas Has Gained Share of the Energy Pie
According to BP Statistical Energy Review, natural gas accounted for 24% of global primary energy consumption, the highest on record, in 2010.
Source: BP Statistical Review of World Energy 2011
Page 43
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 44
Substitutes for Natural Gas
There are numerous substitutes for natural gas including coal, oil, heatingoil, naphtha and alternative energy (such as wind, solar and nuclear power).
A global movement towards clean energy has put natural gas more in favor versus coal and oil, due to inherently lower CO2 emissions.
Coal Oil Alternative Energy
Source: www.britishcoalgasification.co.uk. Source: ecotechdaily.com Source: www.greengop.org.
North American Natural Gas
Page 46
N. AM. Natural Gas PricingNorth America is mostly a “closed”market with natural gas prices driven by demand trends (weather, economic growth) and the cost of new supply.
Over the past 14 years, NYMEX gas prices have traded as low as $2-3 per MMBtu and as high as $14-15 per MMBtu.
In North America, oil and natural gas do not exhibit a strong pricing relationship as the two fuels don't compete much (oil is not used much for power while gas is not used much for transportation).
Outside of the U.S., prices tend to be linked to crude owing to less liquid trading markets.
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North American Natural Gas: Industry Overview
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The process of bringing natural gas to market begins with exploration & productionand ends with the retail distribution of gas to end markets.Along the way, gas is gathered and processed for removal of oil, water, natural gas liquids (NGLs) and sulfur. It is then transported and stored while awaiting distribution.
Page 48
Upstream: Where is Natural Gas Located?
Source: U.S. Geological Survey. Source: StatoilHydro.
Onshore: Shale Onshore: Tight Gas Offshore
Source: Department of Primary Industries, Australia.
Exploration & Production (also known as the upstream) of natural gas is a global venture and producers operate in both onshore and offshore environments.
Natural gas is located underground and below seabeds.
Producers often drill thousands of feet beneath the surface to reach natural gas reservoirs.
In North America, onshore unconventional resources like shale and tight gas sands have become a growing source of production in recent years as traditional and lower cost sources have matured.
Page 49
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 50
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 51
The Midstream: Transporting Natural Gas
Natural gas in the U.S. is delivered via a complex web of interstate and intrastate pipelines estimated by the American Gas Association to extend ~2.4 million miles.Pipeline companies charge regulated fees (tariffs) for moving gas.Major pipelines include the Transcontinental, Northwest, Rockies Express (REX) and Ruby pipelines. The Ruby Pipeline, which was completed in July 2011, provides westbound transport from the Rockies region with 1.5 Bcf/d of capacity.
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Natural Gas Marketing: What are Basis Differentials?
The NYMEX natural gas price (Henry Hub, Louisiana) is not necessarily what producers receive for their gas. The actual price received (well-head price) is different throughout the country. The difference relative to NYMEX is called a basis differential.
Regional prices are a function of local supply and demand balances and the transport cost to the consuming markets in the Northeast.
Historically, Rockies gas trades at the widest discount (given little local demand and long pipeline distances) while Appalachia gas trades at a premium (given proximity to high demand areas on the east coast). However, differentials across the U.S. have narrowed in recent quarters as a result of expanded pipeline capacity.
~$4.20/MMBtu
~$3.60/MMBtu ~$4.30/MMBtu
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Natural Gas Storage: The U.S. has a Deep Storage System
Before being transported for local distribution, natural gas is stored in underground facilities such as depleted reservoirs, salt caverns and aquifers.Total natural gas storage capacity in the U.S. is approximately 4.1-4.2 Tcf. Storage is located primarily in the Gulf Coast and the ‘consuming’ areas in the Midwest and Northeast.
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U.S. Weekly Storage Report
Natural gas in storage fluctuates from the withdrawal season (November to March) when cold weather typically results in storage withdrawals to the refill season(April to October) when lower demand leads to net storage injections.Every Thursday at 10:30am ET, the EIA reports the storage injection / draw for the prior week. The amount of injection or draw can have a material affect on gas prices as it indicates supply / demand trends relative to previous years.
WORKING GAS IN STORAGE
Change Change Differential9/2/2011 Week Ago % Bcf Year Ago % Bcf 5-Year Avg % Bcf
Producing Region 959 957 0.2% 2 971 (1.2%) (12) 925 3.7% 34Consuming East 1,636 1,578 3.7% 58 1,707 (4.2%) (71) 1,732 (5.5%) (96)Consuming West 430 426 0.9% 4 477 (9.9%) (47) 427 0.7% 3Total U.S. 3,025 2,961 2.2% 64 3,156 (4.2%) (131) 3,085 (1.9%) (60)
Source: Energy Information Administration (EIA)
Total U.S. Working Gas In Storage
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Page 55
Major End Markets for Natural Gas
ResidentialGas used in private dwellings for space and water heating, air conditioning, cooking and other household uses
Electrical PowerGas used by power plants to generate electricity
CommercialGas used by non-manufacturing establishments in the sale of goods or services
IndustrialGas used for heat, power or chemical feedstock for manufacturing. End products include petrochemicals, fertilizers, plastics, etc.
Other smaller end-market uses of natural gas include 1) fuel (natural gas vehicles) and 2) oil & gas production.
Source: Energy Information Administration
Page 56
U.S. Natural Gas Demand By End Markets
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Natural gas demand trends are highly seasonal. Because natural gas is used as a heating fuel, demand rises materially in the winter/cold weather months.
U.S. Natural Gas Demand by User (Bcf/d)
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Natural Gas Upstream Trends:Shale Gas in Focus
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Shale Gas in Focus
Shale is a fine-grained sedimentary rock that may contain high concentrations ofnatural gas.Producers drill into shale beds and break open the rock using advanced drilling techniques and tremendous energy (pressure pumping). Shale is a growing source of current and future natural gas production in the U.S. It currently represents about 13-15 Bcf/d (~20-22%) of total U.S. production.
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Shale Basins in the U.S.Major shale plays include: Bakken, Barnett, Eagle Ford, Fayetteville, Haynesville, Marcellus and Woodford.
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Bakken Shale
The Bakken Shale is an unconventional resource play located in the Williston Basin in North Dakota, Montana and Saskatchewan. An oil-based shale play that offers one of the highest rate of returns in the industry.Major players include BEXP, CLR, DNR, EOG, NFX, WLL, XTO/XOM and KOG. Transporting produced volumes out of the Williston remains an issue for the industry, but recent capacity additions have provided some relief. Significant rise in completed well costs (+35% since 2009) is the biggest concern.
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Barnett Shale Barnett Shale Natural Gas Production (MMcf/d)
Includes Denton, Tarrant, Wise, Hood, Johnson, Parker, Hill, Bosque, Sommervell, and Ellis Counties.
The Barnett Shale is an unconventional resource play located in North Central Texas.
Production growth has slowed to less than 5% in 2010 after growing 36% per annum over the 2004 – 2009 timeframe showing that the play is maturing.
~3MM total acres with DVN, XTO/XOM, EOG and CHK as the major players.
Wells can be drilled in 15-20 days, much quicker than some other shale plays.
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264 362 497727
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Center of
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Industry believes play spans some 3.5MM acres
We believe much of the “greenfield” leasing has been done
Ways to enter now are through acquisitions, joint ventures or farm-outs
Haynesville Shale
The Haynesville Shale is an unconventional resource play located in East Texas / North Louisiana. Production has ramped up quickly and some industry sources indicate it could total 1.6 Bcf/d today. Major players include ECA, CHK, PXP, RDS and HK. IP rates are typically 10-15 MMcf/d and have been as high as 30 MMcf/d, but first year decline rates are 80-90%.
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Marcellus Shale
The Marcellus Shale is an unconventional resource play located in Appalachia. Recent upward well EUR revisions in the SW PA region has pushed it to be one of the highest rate-of-return plays in the industry. IP rates typically range 2-10 MMcf/d.Play consists of ~60MM acres with EQT, RRC, APC, CVX, UPL, CNX, COG and CHK as the major players. Takeaway capacity concerns are being addressed with increased processing and pipeline buildouts.The Marcellus is currently producing ~3 Bcf/d and should continue to ramp into 2012.
Low Pressure AreaHigh Pressure Area
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Eagle Ford Shale
The Eagle Ford Shale is an unconventional resource play located in South Texas.It has gained significant attention with BHP Billiton’s recent acquisition of Petrohawkfor $12.1 billion (a 65% premium).Concerns over takeaway capacity (lack of pipelines and trucks) remain a key issue, but are currently being addressed.EOG, APC, CHK, NFX, SM, SFY, ROSE and BHP are major players. IP rates typically range 8-12 MMcfe/d.
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Emerging Plays - Utica
The Utica Shale is an unconventional resource play located in Eastern Ohio.It is considered an analog to the Eagle Ford with oil, wet gas/volatile oil and dry gas windows. Current focus has been on liquids-rich and volatile oil parts of the play.There has been significant exploratory activity and deal flow with recent JV’s and acquisitions (CNX/HES) that have valued the Utica at ~$9,000/acre.CHK, EVEP, DVN, APC, GPOR, REXX, PETD, CNX and HES are major players. IP rates are speculated to be 20+ MMcf/d.
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Emerging Plays – Uinta and Other Basins
The Uinta Shale is an unconventional resource play located in Northern Utah.BBG/BRY have announced an initial well and NFX has announced five wells to date with impressive early results.The Brown Dense is a new oil/gas play in Southern Arkansas and Northern Louisiana with no results announced to date. SWN and DVN are first movers in the play.The Tuscaloosa is a new play in Southeastern Mississippi/Eastern Louisiana with DNR, GDP, DVN and ECA have established acreage in the play.
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Liquified Natural Gas (LNG)
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Liquefied Natural Gas (LNG)
Liquefied Natural Gas (LNG) is natural gas (methane) that is chilled to liquid form.Natural Gas as a liquid occupies 1/600th of the space versus ambient gas, making it easier to store and transport on cargoes. LNG can be transported by ship or truck to destinations that can’t be easily reached by pipelines.
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LNG: Industry Overview
LNG is exported from regions that have an abundant supply of natural gas, but without significant local markets.
LNG facilities are highly capital intensive ($5-10B) and LNG vessels are $200-300MM each.
While most LNG projects operate under long-term contracts (20-25 years), there is a growing spot market of ~5-6 Bcf/d.
Spot shipments are delivered to regions with the highest netback prices (i.e., offer the highest bids for LNG cargoes).
Contracted import prices are often based on a oil-indexed contract (such as Japanese Crude Cocktail [JCC]).
LiquefactionTransport
Regasification
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LNG: Liquefaction
Liquefaction is the process by which natural gas is converted to liquid form.Methane gas is piped to a liquefaction facility where it is chilled to -260°F, at which point the vapor condenses to liquid. The liquefied gas is then loaded on to a carrier and transported to import markets.Construction of a liquefaction facility can take five to seven years.Key LNG Supply Markets: Pacific Basin (Australia, Indonesia, Malaysia), Atlantic Basin (Algeria, Nigeria, Trinidad), and Middle East (Qatar, Egypt, Oman).
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LNG: Regasification
Imported LNG is received as shipments at terminals with regasification (“regas” ) capabilities.Regasification involves bringing natural gas back to its gaseous form through thermal energy. The gas is then stored and distributed to local end-users through pipelines.Key Import Markets: Asia (Japan, Korea, Taiwan, India, China), Europe (U.K., Spain, Belgium) and U.S. (bidder of last resort). New markets are emerging in Southeast Asia, Latin America and the Middle East.
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U.S. LNG import terminals (with regas facilities) include Cove Point, Elba Island, Everett, Freeport, Lake Charles, Cameron, Peñuelas, Sabine and Golden Pass.COP and MRO closed the Kenai LNG plant in October 2011, the only LNG export terminal (with liquefaction facilities) in the U.S. The largest supplier of LNG to the U.S. is Trinidad.
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LNG now accounts for 30.5% of the global gas trade
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Page 74
Japan is currently the largest importer of LNG globally, importing 9.0 Bcf/d in 2010 as the country has few domestic means to satisfy natural gas demand.Imports primarily come from Australia, Indonesia and Malaysia.Total regasification capacity is currently approximately 25 Bcf/d with one terminal (Sodegaura) capable of importing 3.9 Bcf/d, one of the largest in the world.
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LNG: Major Importing Countries – Japan
Page 75
South Korea is currently the second largest importer of LNG globally, importing 4.3 Bcf/d in 2010.Current regasification capacity is roughly 10 Bcf/d with imports primarily from Qatar, Indonesia and Malaysia.Similarly to Japan, Korea has minimal domestic natural gas production and relies on LNG to fill the gap.
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LNG: Major Importing Countries – South Korea
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Spain is currently the third largest importer of LNG globally, importing 2.7 Bcf/d in 2010.Current regasification capacity is roughly 5.9 Bcf/d and is set to rise to nearly 7 Bcf/d over the next five years or so.Spain relies on LNG imports (~3.0 Bcf/d) and pipeline gas (0.9 Bcf/d) to satisfy natural gas demand.
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LNG: Major Importing Countries – Spain
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Qatar is currently the largest exporter of LNG globally, exporting 7.3 Bcf/d in 2010.Liquefaction capacity currently stands at ~10.2 Bcf/d and should continue to grow through 2012 as two recently completed projects have yet to reach plateau.Qatar exports gas to most markets including Japan, Korea, Spain, U.K. and the U.S.Exported gas is primarily sourced from the large North Field, which has estimated recoverable natural gas reserves of more than 900 Tcf.
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Page 78
Indonesia is currently the second largest exporter of LNG globally, exporting 3.0 Bcf/d in 2010.Liquefaction capacity currently stands at ~4.2 Bcf/d with the majority (3 Bcf/d) from the large Bontang LNG facility that includes eight processing trains.Indonesia plans to reduce future LNG exports from traditional LNG trains due to increasing domestic demand for gas, but recently granted project approval to Tangguhto build a third train, which should increase capacity by 0.6 Bcf/d.Like Australia, Indonesia primarily exports LNG to Asian markets.
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Australia is currently the fourth largest exporter of LNG globally, exporting 2.5 Bcf/d in 2010.While liquefaction capacity only stands at ~3.2 Bcf/d currently, future projects are set to raise liquefaction capacity to 10-15 Bcf/d by 2020.Australia primarily exports its gas to Asian markets such as Japan, China and Korea.The $37B, 2.0 Bcf/d Gorgon LNG project is currently being developed with first production expected in 2014 or 2015. Gorgon will be Australia’s largest resources project.
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LNG: Major Exporting Countries – Australia
THE UPSTREAM
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Exploration & Production
Exploration & Production is the first link in the oil & gas supply chain and involves:1) Search and discovery of oil & gas reserves. 2) Extraction of oil & gas resources.
Oil Supply Chain Natural Gas Supply Chain
Source: American Petroleum Institute.
Source: American Petroleum Institute.
Page 82
Exploration & Production: Industry PlayersThe industry is made up of several categories of players who participate in exploration and production for oil and natural gas.
1) Integrated Oils: Are involved in all links of the supply chain, including the upstream.
2) Independent E&P: Primary business is to engage in exploration & production.
3) Pipeline Companies: Focus mainly on natural gas transmission but often have upstream segments as well.
Independent E&Ps Pipeline FocusedIntegrated Oils
Source: Google images
The Upstream Process
Page 84
The Upstream Process (E&P)
Exploration & Production involves the search for and development and production of oil and gas reservoirs. The process is broken down into five primary phases:
1) Acreage Acquisition: Producers begin by acquiring leases and drilling permits. Prospects include:Locations contiguous to producing formationsUnexplored areas
2) Exploration & Appraisal: Producers will then begin to evaluate the acreage to see if there are commercially recoverable reserves.
Involves sub-surface analysis, shooting seismic and drilling exploratory wells and appraisal wells. Wells drilled in previously unexplored areas are known as wildcats.
3) Development: Once the commercial viability of a prospect is determined, rigs and equipment will be contracted and wells are drilled and completed.
4) Production: Full scale production involves the ongoing collection of hydrocarbons. Oil and gas are produced from within the well and transported to processing facilities via pipelines.
5) Plugging and Abandonment: When a well has produced out its economically recoverable reserves, the well is decommissioned and equipment is removed from within the wellbore.
Source: www.directnews.co.uk, Gardner Denver ,Texas A&M University
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The Upstream Process
Acquire acreage
Conduct seismic survey
Interpret data
Identify prospects
Drill exploration
wellsEvaluate results
Good
Bad
Plug & Abandon
Drill further wells -
appraisal
Oil
Gaswith no spot
market
Examine gas sales options
For Sale
Negotiate gas sales contract
Sign gas sales
contract
START HERE
Formulate Development
PlanNo market identified
Final Investment Decision
Begin drilling wells
Install platform/ rig or drilling
ship
Begin production
Install production facilities
Sell oil / gas for cash
Go on to Development
Source: Google images.
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Acreage Acquisition: Exploration and Right to Drill
The first step producers take is to negotiate or bid for leaseswith governments, states or spare private land owners. Producers then acquire drilling permits / necessary regulatory approvals (from federal/state/local governments) for the right to drill.
Lease terms vary widely between countries but leases typically include:
1) A royalty payment to land owners that represent a percentage of gross production (typically 12.5-30.0% in the U.S.), OR
2) In some countries, leases are commonly awarded as Production Sharing Contracts or Agreements (PSCs, PSAs)
Lease terms can range from:1) Short-term: 3-5 years
2) Long-term: approximately 10 years
3) Held by production: lease can be held based on a minimum production threshold
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Exploration & Appraisal: Finding Hydrocarbons
Among various techniques, producers use geological surveys and seismic evaluation to determine the likely existence of hydrocarbons before drilling a well.Geological surveys involve surface level analysis of the geology of an area to assess if sufficient oil and gas reserves are likely to be beneath the surface.Seismic evaluation allows producers to develop a subsurface image of a play.
Seismic Evaluation
Source: Cobalt Exploration.
Geological Surveys
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Exploration & Appraisal: Seismic Evaluation
Seismic evaluation has greatly de-risked the exploration process. Seismic is one of the most widely used exploration tools today and is used both onshore and offshore.Seismic evaluation involves the creation of a subsurface area image that can indicate hydrocarbon accumulations.The process: – Seismic waves (acoustic vibrations) are created.
– The waves migrate downward and reflect off of various layers of subsurface rock back to the surface where receivers "catch" the waves.
– The speed and nature of how the waves reflect are then interpreted to estimate subsurface geology.
Please see Oilfield Services section for additional detail
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Exploration & Appraisal: Drilling Test Wells
Once a target is chosen, producers will drill a prospect to confirm the existence of hydrocarbons. In areas where the existence of oil and gas reserves are unproven, producers will drill an exploratory well to confirm pre-drilling test data (geological surveys and seismic).– Successful exploration wells are capitalized as part of
the project’s overall cost.
– Unsuccessful exploration wells are known as “dry holes” and their cost is generally immediately expensed.
For higher risk offshore production, producers will often drill appraisal wells to test flow rates and determine the commercial viability of the reservoir.
Resources (Germany): Kansas University Geological Survey
Source: Federal Institute of Geosciences and Natural
Page 90
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 91
Development: Drilling the Well
The most common technique used to drill a well is rotary drilling. As the name implies, rotary drilling uses a sharp drill bitthat drills through the Earth’s crust.Wells are drilled with rigs and equipment that is often contracted from an oilfield service company, to which producers pay day rates and fees for services rendered.Once a well is drilled, its commercial viability is determined. If a well contains sufficient oil and gas, it is completed and production commences.If a well does not contain sufficient hydrocarbons, it is designated a dry welland then plugged and abandoned.
Source: Schlumberger
Source: Encarta
Page 92
Development: Horizontal Drilling
An advanced drilling technique used by producers is directional drilling, which allows the well to be drilled at varied angles to access reservoirs that would otherwise be difficult to reach using traditional vertical drilling. Horizontal drilling is a widely used variation of directional drilling and has been a key to unlocking gas from shale formations.Horizontal drilling allows producers to access more difficult reservoirs, albeit it at higher costs.
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Vertical Well
Horizontal Drilling reaches deeper into blanket formations
Horizontal Well
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Development: Well Completions
The process of completing a well involves installing casing to provide support for the wellbore (to prevent it from caving in). Well casing also serves to prevent leakage of oil and gas.Well casing is typically made of steel, which makes producers susceptible to movements in steel prices.Once the casing is installed, the well is perforated via explosive charges that are lowered into the well, which produce holes for hydrocarbons to flow into.
Source: Schlumberger
Source: Halliburton Source: Schlumberger
Page 94
Development: Well Stimulation
If a reservoir contains hydrocarbons which are high in viscosity or have limited fissures to move through, producers may need to stimulate the reservoir with hydraulic fracturing (“frac job”).
Frac jobs involve pumping fracturing fluid (a combination of water and sand) into the well at high pressures, creating fractures in the formation that allow oil and gas to flow through and into the wellbore.
The goal of fracturing is to increase flow of oil and natural gas. S
ourc
e: C
.S. G
arbe
r &
Son
s
Additional fractures allow for better flow of oil and gas
trapped within a formation
Page 95
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 96
Production: Decline Rates
Production will come on at an initial production rate (IP rate) and decline as natural pressure dissipates and the well produces out.Production decline rates will vary among different fields, with some gas shales exhibiting very steep declines within the first year (80-90%) and long life tails. Decline rates force producers to consider the time-value of a play.
Source: Ultra Petroleum.
Sample Decline Curve for a Pinedale Tight Gas Well
Page 97
Production: Enhanced Oil Recovery
As natural pressure fades during primary recovery, production falls leaving a significant amount of unrecovered oil remaining in the reservoir. Enhanced Oil Recovery (EOR) methods can be used to restore pressure within oil wells and regenerate flow (secondary and tertiary recovery). Secondary recovery involves pumping water into the well to restore pressure and stimulate oil flow. Secondary recovery can restore flow to a well for 10-15 years.Tertiary recovery involves pumping CO2 to increase recovery. CO2 restores pressure to the well, and also make oil less viscous and therefore easier to produce.
Sou
rce:
Sch
lum
berg
er
Page 98
Abandonment
At the end of its productive life, a well or field area is abandoned.
In the onshore segment, the tubing may be removed from the well and sections of well bore filled with cement. The surface around the wellhead is then excavated, the wellhead and casing are cut off, and a cap is welded in place and then buried.
In the offshore segment, the process is sometimes referred to as “decommissioning.”Platforms are de-activated and either removed or dropped to the seabed as prescribed.
Source: The Fairweather Group.
Oil and Gas Reserves
Page 100
Exploration & Production: Reserves
Producers can add reserves either 1) organically (drill-bit) or 2) through acquisitionsRecognizing Reserves:1) Proven Reserves (1P) – Estimated quantities of oil and gas that are reasonably certain(80%-90% confidence) to be recoverable under today’s technology and prices. 1P can be broken down into:
- Proven Developed (PDP): Reserves expected to be recovered from existing wells, existing equipment and/or improved recovery techniques.
- Proven Undeveloped (PUD): Reserves that will require further development and that are expected to be recovered from undrilled acreage or existing wells that require recompletion work.
. 2) Probable (2P) – Unproven reserves that are more than likely to be recoverable (50% confidence). Probables cannot be booked under current SEC guidelines.3) Possible (3P) – Unproven reserves that are less likely to be recovered than probables. Possibles cannot be booked under current SEC guidelines. Possibles
Probables
PUD
PDP
0%
20%
40%
60%
80%
100% Proved
Source: Credit Suisse
Page 101
Exploration & Production: Estimating ReservesOil in place or gas in place refers to the amount of oil or gas in a subsurface reservoir.
Only a fraction of this oil can be recovered from a reservoir and is known as the recovery factor. The portion that can be removed is considered in the calculation of reserves.
There are three general categories for estimating oil reserves:
1. Volumetric Method: This method attempts to determine the amount of oil/gas-in-place by using the size of the reservoir as well as the physical properties of its rocks and fluids. Then a recovery factor is assumed, using assumptions from fields with similar characteristics. This method is most useful early in the life of the reservoir, before significant production has occurred.
2. Materials Balance Method: The materials balance method for an oil field uses an equation that relates the volume of oil, water and gas that has been produced from a reservoir, and the change in reservoir pressure, to calculate the remaining oil/gas. It requires some production to occur (typically 5% to 10% of ultimate recovery), unless reliable pressure history can be used from a field with similar rock and fluid characteristics.
3. Production Decline Curve Method: The decline curve method uses production data to fit a decline curve and estimate future oil production. It is assumed that the production will decline on a reasonably smooth curve, and so allowances must be made for wells shut in and production restrictions.
Page 102
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 103
Exploration & Production: Reserve Life
This is the length of time that remaining reserves would last if production were to continue at current levels.Calculated as the reserves remaining at the end of any year divided by the production in that year.
Source: BP Stats
68
58
46
37
11
60
200
0
10
20
30
40
50
60
70
80
Middle Eas
t
Africa
Europe/E
urasia
Latin A
merica
AsiaNorth
Ameri
ca
World
Year
s
THE MIDSTREAM
Page 105
Midstream
Midstream refers to all activities between the production of natural gas and oil and the end-use marketsMidstream activities include transporting, processing, fractionating, and storing natural gas, natural gas liquids, crude oil and refined products
Source: Enterprise Products Partners
Source: American Petroleum Institute.
Page 106
Midstream: Industry Players
The industry is made up of several categories of players but may generally be split by hydrocarbon
1) Natural Gas Midstream: Involved in transporting natural gas and natural gas liquids to end-use markets.
2) Crude Oil / Refined Products Midstream: Involved in transporting crude oil and refined products to end-use markets.
Crude Oil / Refined Products MidstreamNatural Gas Midstream
El Paso
Spectra
Williams
ONEOK
Enterprise
Energy Transfer
Kinder Morgan
Boardwalk
The Majors
Plains All American
Colonial Pipeline
Enbridge
Kinder Morgan
NuStar
Sunoco Logistics
Magellan
Buckeye
Natural Gas
Page 108
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 109
NGL Fundamental Drivers
Source: Bloomberg, Credit Suisse, as of 09/07/2011
Natural gas production requires gathering and processing servicesEspecially rich gas from unconventional resource plays
The relationship between natural gas prices (the feedstock for NGLs) and crude oil prices affect natural gas processing economics
NGL price - Natural Gas price = Processing Margin
Drivers of natural gas liquids productionAbsolute level of natural gas producedMix of natural gas production between rich gas (contains relatively more NGLs) and dry gas (contains small amounts of NGLs)
Quarterly NGL Composite Price(Average of Weekly Prices)
$1.44
$0.71$0.63
$0.73$0.84
$1.04
$0.81
$1.15$1.03 $0.97
$1.16$1.08
$1.25$1.40$1.40
$1.65 $1.65
$1.36
0.00
0.20
0.40
0.60
0.80
1.00
1.20
1.40
1.60
1.80
1Q08 2Q08 3Q08 4Q08 2008 1Q09 2Q09 3Q09 4Q09 2009 1Q10 2Q10 3Q10 4Q10 2010 1Q11 2Q113Q11TD
($ /
Gal)
Quarterly Gross Processing Spread(Average of Weekly Spreads)
$0.67$0.65
$0.15$0.23
$0.40
$0.56$0.67
$0.47
$0.70$0.65$0.59
$0.82
$0.69
$0.88
$1.01$1.03
$0.85
$0.58
0.00
0.20
0.40
0.60
0.80
1.00
1.20
1Q08 2Q08 3Q08 4Q08 2008 1Q09 2Q09 3Q09 4Q09 2009 1Q10 2Q10 3Q10 4Q10 2010 1Q11 2Q113Q11TD
($ / G
al)
Page 110
Dry natural gas can move into interstate or intrastate pipelines or into storageInterstate pipelines are regulated by the Federal Energy Regulatory Commission (FERC)Intrastate pipelines are regulated at the state level (and FERC in certain instances)Storage facilities may be FERC-regulated or have market-based ratesTwo favorable characteristics of interstate pipelines:1) The pipeline does not take title to the commodity and is thus not sensitive to commodity prices2) Capacity reservation fees provide stable revenue regardless of volumes transported
Natural Gas Pipelines & Storage
Source: EIA
Natural Gas Pipelines Natural Gas Storage
Crude Oil / Refined Products
Page 112
Crude Oil: Lease Gathering & Marketing
Source: American Petroleum Institute
Purchase and sales are typically entered into nearly simultaneously to mitigate commodity price exposure. Although lease gathering contracts are usually for short periods of 30 days, producers tend not to switch and remain loyal because the crude gatherer also provides field and administrative services to the producer.
Midstream companies purchase crude from producers at or near the wellhead (lease) and sell that crude to refiners or third party marketers. Typically the crude is gathered by trucks or small diameter pipelines.
Page 113
~200,000 miles of pipelines in the U.S. transport about two-thirds of the petroleum consumed (water carriers (28%), trucks (4%), and rail (2%) represent the balance). Pipelines must be dedicated to either crude or refined products, but not both. Liquids pipelines do not take title to the commodities transported; their revenue streams depend on tariffs and the volume of product transported.Tariffs may be market based or regulated by the FERC.– Pipelines are allowed to adjust tariffs each July based on the producer price index for finished
goods for the prior calendar year plus 2.65%.– This index methodology is reviewed every 5 years; current calculation is set through June 2012.
Crude Oil / Refined Products Pipelines
Source: Allegro Energy Group
Major Crude Oil Pipelines Major Refined Products Pipelines
Page 114
Refined Products Pipelines: Batching
Source: www.pipeline101.com
Products that meet certain specifications can be mixed (batched) and transported together in sequence. A batch is a quantity of one product or grade that will be transported before the injection of a second product or grade. Transmix is created at the interface point where two batches meet. This new mixture must be moved to a separate storage facility and reprocessed.
R egular Gasoline
Premium Gasoline
Premium Gasoline
R egular Gasoline
D iese l
Jet F uel
OILFIELD SERVICES, DRILLING & EQUIPMENT
Products & Services
Page 117
Oilfield Services: Industry Segments
The Industry is made up of several segments/life cycle categories. We list them by stage of a new oil & gas field:
1) Exploration/Seismic2) Drilling3) Completion4) Production
Oil Service companies aid independent exploration and production companies (E&Ps), international oil companies (IOCs) and national oil companies (NOCs) in the exploration and production of oil and natural gas.
2010 Western Service company total revenues: $259B
Source: Spears & Associates
Completion15%
Production Services
6%
Contract Drilling22%
Drill ing Services25%
Exploration/ Seismic
5%Equipment/
Infrastructure27%
Total Revenue: $259B
Total Drilling 47%
Total Production 33%
Page 118
Source: Spears & Associates, BP Energy, Baker Hughes
Streamer
s
Receiver
vessel
Seismic services and equipment include:Data Acquisition - collection of seismic dataData Processing - third party processing of seismic data prior to interpretationLibrary Sales - multiclient sales of non-exclusive seismic dataSoftware - software products for seismic processing, interpretation, mapping, reservoir modeling and characterization, petrophysical evaluation, and engineering analysis that can run on workstations or PCsGeophysical Equipment - data recorders, telemetry systems, geophones/hydrophones, energy sources (vibratory vehicles, air guns, etc.) used in data acquisition.
OFS - Exploration: SeismicMarine Seismic Survey
Seismic Output
Page 119
Source: Spears & Associates, Schlumberger, American Association of Petroleum Geologists
Types of Log Measurements:
Electrical properties – resistivity and
conductivity
Neutron density (porosity)
Pressure testing
Sonic properties
Dimensional measurements
Formation fluid sampling
Spectroscopy (lithography)
Wireline logging includes both open and cased hole services. Open hole logging occurs during the drilling process and measures characteristics of the rock and the fluids contained therein. Cased hole logging refers to measurements taken in a well after a casing or liner has been set in the well. It is often applied in old wells to help operators determine what to do next (e.g. where to drill a side track well).
OFS – Exploration/Drilling: Wireline Logging/LWD
Page 120
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 121
Source: ODS-Petrodata, Noble, Rowan
Jackup
OFS – Contract Drilling: Offshore RigsSemisubmersible
Drillship
Drillship A floating mobile offshore drilling vessel that operates in the midwater, deepwater and ultra-deepwater and is typically dynamically positioned.Semisubmersible A floating mobile offshore drilling platform that operates in the midwater, deepwater and ultra-deepwater and can be conventionally moored (anchored) or dynamically positioned. Jackup A mobile offshore drilling platform that operates in shallow water and rests on the oceanfloor when in operation. 2 types:– Independent Leg -Anchored by “legs”
that extend down to the seabed– Mat - Anchored by a mat-like structure
that rests on the sea bed.
Page 122
OFS – Contract Drilling: Offshore Rigs by Geography
Middle East, SE Asia are the largest jackup markets
Global jackup markets as % of total Global floater markets as % of total
Source: ODS-Petrodata, note figures exclude newbuilds
South America, West Africa, North Sea are the largest floater markets
US GOM17%
Central/South America10%
North Sea9%
Med./Africa13%
Middle East/India31%
Southeast Asia/Far East20%
US GOM12%
Central/South America31%
North Sea15%
Med./Africa19%
Middle East/India4%
Southeast Asia/Far East15%
Australia/New Zealand3%
Other1%
Page 123
Roller or Tri-Cone
Fixed Cutter or Polycrystalline
Compact Diamond (PDC)
OFS – Drilling: Bits
Drill bits come in two main categories: Roller-cone and fixed cutter (PDC). Technology advancement has led to steady share gains by PDC bits and is moving the market to buy on a $/ft drilled basis (i.e. a “rental” model).–Roller cone bits have teeth typically made of milled
steel or tungsten-carbon inserts mounted on three roller cone assemblies. They are best used in hard and medium strength formations.
–Fixed cutter bits usually use Polycrystalline Compact Diamond (PDC) inserts mounted on the body of the bit. Fixed cutter bits are often custom engineered for specific formation characteristics. PDC bits have typically been used for soft formations, but advancing technology now puts them in hard, abrasive rock.
Source: Spears & Associates
Page 124
OFS – Drilling: Fluid System
The drilling fluid, also known as drilling mud, is one of the major factors in the success or failure of the drilling operation. Drilling fluid serves three functions:
– Lifts cuttings to the surface
– Cools the drill bit
– Supports the integrity of the wellbore and prevents hydrocarbon “kicks” by providing weight/pressure that is generally greater than that of the reservoir (known as an “over-balanced” condition).
The fluids handling system re-circulates the drilling mud and includes:
– Mud pump
– Mud mixer
– Shale shaker - to remove cuttings from the subsurface
– Mud pit – to collect used mud for recirculation
Fluid Circulation System
Fluid Enters the well at the Bit
Page 125
Directional and Horizontal Wells
Directional drilling entails drilling in a direction other than vertical. There are two methods:
– Conventional uses a bend near the bit and a steerable mud motor. Drilling fluid is pumped through the mud motor, turning the bit and thereby allowing it to drill in the direction the bit points (unlike conventional [vertical] drilling, the drill string does not rotate).
– Rotary Steerable Tools (RST) allow the driller to “point” or “push” the bit without stopping drill pipe rotation, allowing for faster and smoother hole construction.
Drilling directionally entails use of steering systems (Measurement While Drilling or MWD) and Logging While Drilling or FEWD or LWD). LWD measurements are generally similar to those taken in wireline logging.
OFS – Directional Drilling
Rotary Steerable Technology
Source: www.horizontaldrilling.org, Halliburton
Page 126
Completing the well is the process of accessing the reservoir including:
– Installation of casing and liner. Casing is large diameter steel pipe that is cemented into the well bore to ensure stability of the formation.
– Perforating the casing to access the reservoir. A series of “chargers” are deployed to where the well accesses the reservoir.
– Stimulation (see next page)
OFS - Completions
Casing
Reservoir
Perforations
Perforating Casing/ Completion
Other key products include:– Packers and plugs to isolate zones
– Screens to keep sands away from production
– Isolation valves to manage flows from multiple completion zones
Screen Layers
Source: Schlumberger, Halliburton
Completion System
Packers
Page 127
Source: BJ Services, Carbo Ceramics, Independent Oil & Gas Service, Gulftex, ProPublica
Frac job
Frac unit
Cementing unit
OFS – Completion: Pressure Pumping
Pressure pumping consists primarily of cementing and various forms of production stimulation.
–Cementing of Casing (approx 20% of P.P revenue) -As described in the completions section, casing is cemented in place in the well bore. Cement is pumped thru the casing to the end of the section and forced back up the well in the annulus (between outer wall and well) where it sets and hardens.
–Stimulation (80%) – Services include hydraulic fracturing (dominant), acidizing and nitrogen injection.
In fracturing, fluid is pumped at high pressures into the well bore to create/widen fractures in the formation so oil/gas can flow into the well. Proppants are used to keep fractures open and can be sand, resin-coated sand, and/or ceramic.
In acidizing, acids can be used to etch away rock.
Proppants
Page 128
OFS – Hydraulic Fracturing Equipment
Source: Jereh-PE, Weir SPM, Schlumberger
Treating Iron
Frac Pump Transmission
EngineCooling System
Power EndExpected Lifespan:Up to 2 years
Fluid EndExpected Lifespan:Ranges from 500 to 1,400 hours
Frac Pump: a high pressure, high volume
pump used in hydraulic fracturing
• Manufacturers include independents
such as Gardner Denver (GDI) and Weir
SPM (WEIR.LN) and vertically integrated
providers such as Halliburton (HAL) and
FracTech
Treating Iron: temporary surface piping,
valves and manifolds required to bring fluid
treatment down to wellbore from the pump
Frac Truck
Frac Pump
Page 129
Source: FMC Technologies, Oceaneering International, Umbilical Manufacturers’ Federation
Subsea TreeSurface Tree
OFS – Production: Subsea
A Christmas tree is a set of valves that sit on top of the wellhead and control the flow of pressure of a producing well.
– Surface trees are installed on land and on offshore platforms.
– Subsea trees are installed on the sea bed.
Manifolds house equipment and pipes that control, direct and measure the flow of fluids to/from the subsea well.
Umbilicals are used for the control of subsea production systems. Umbilicals are made of either steel or thermoplastic tubes that contain fluid conduits for hydraulic power and chemical injection.
Subsea TreeManifold
UmbilicalsFlowlines
Subsea TreeManifold
UmbilicalsFlowlines
Subsea Production System
Umbilical
Page 130
Source: MMS, Credit Suisse
OFS – Production: Offshore SystemsOffshore production infrastructure includes:– Fixed Platforms consist of a jacket driven into the
seabed with a deck; water depths up to 1,500ft.
– Compliant Towers can sustain significant lateral deflections; water depths 1,000-2,000ft.
– Tension Leg Platforms float but connected to the sea floor by vertical tendons; water depths up to 4,000 ft.
– SPAR Platforms have a large single vertical cylinder supporting a deck; water depths beyond 4,000 ft.
– Floating Production Systems are semi-submersibles anchored by wire rope and chain, or dynamically positioned; water depths beyond 4,000 ft.
– Floating Production, Storage & Offloading Systems (FPSO) are large tanker vessels moored to the seafloor; process and stow production from subsea wells and offload to a small tanker; suited for remote deepwater areas with no pipeline infrastructure; water depths beyond 4,000 ft.
Offshore Production Development Systems
Page 131
Source: Spears & Associates, Weatherford, Independent Oil & Gas Service, Schlumberger
Rod pump
OFS – Production: Artificial Lift
Artificial Lift is a technology for mature oil and gas wells that need to boost fluids out of the wellbore, particularly as they produce water. 90% of existing producing oil wells and gas wells requiring water removal utilize some type of artificial lift. Main types of artificial lift include:
– Reciprocating rod pumps – a plunger and valve assembly driven by surface motor
– Electric Submersible Pumps (ESPs) – typically several centrifugal pump stages to access different wellbore sections driven by a downhole electric motor
– Progressive Cavity Pumps (PCPs) – a surface motor rotates the sucker rods using a stator and rotor to cause fluid to flow upward
ESP PCP
Page 132
Source: Exterran Holdings, Ariel
Compressor
OFS – Production: Compression
Compression raises the pressure of natural gas in the reservoir so that it will flow into pipelines and other facilities. There are three segments to the field compression market:
–wellhead
–gas gathering
–processing
Compressors have historically been owned and operated by oil companies, but the U.S. is now approximately 1/3 outsourced to contract compression providers.
Gas Gathering Compression
Page 133
OFS – Production: Well Servicing
Well Servicing refers to the maintenance procedures that take place on a well after the well has been completed and production from the reservoir has begun. It is done to sustain and enhance the productivity of the well. Key products/services include:
–Workover – the process of performing major maintenance or remedial treatment on a well.
–Coiled tubing – tubing used for the placement of fluids or manipulation of tools during workover
–Snubbing – the process of putting drill pipe into the wellbore when the BOPs are closed and pressure is contained in the well
–Plug and Abandonment – the process of preparing a well to be permanently closed
Source: Schlumberger, MTG
Workover rig
Coiled tubing unit
Page 134
Source: Bristow Group, Superior Energy, Wartstila, MMS
Supply Boat
OFS – Drilling/Production: Offshore LogisticsHelicopters are used for transporting personnel between onshore bases and offshore platforms, drilling rigs, and installations.
Lift Boats are self-propelled, self-elevating vessels with a relatively large, open deck for carrying equipment in support of offshore exploration and production, and which can serve as a platform from which maintenance and construction work can be conducted.
Supply Boats are ships specifically designed to transport goods (i.e. drilling mud, cement, diesel fuel, chemicals, water, tools, etc) and personnel to and from offshore oil platforms and other offshore structures.
Lift Boat
Page 135
Source: CalDive, Oceaneering
OFS –Production: Offshore ConstructionPipelay vessels use either the S-lay method in water depths <2K ft where pipe is laid into the water horizontally and bends twice in an S-shape, or the J-lay method in deep water where pipe is laid vertically and only bends once as it hits the seabed.Derrick barges have cranes used to lift heavy structures such as platforms/topsides.Diving support vessels (DSVs) support divers performing inspection, maintenance, repair (IMR) and welding. Surface divingcan be performed in depths up to 200 ft; saturation diving can be performed in 200-1,000 ft depths. Offshore Support Vessels (OSVs) are equipped with Remotely Operated Vehicles (ROVs) , tethered underwater robots used for IMR, construction and drill support in deep water.
Combination Pipelay/Derrick Barge
ROV
Company Specific Detail
Page 137
OFS: Life Cycle Exposure and Selected Co’sLife Cycle Stage Oil Services Activities Examples of OFS Co's Life Cycle Stage Oil Service Activities Examples of OFS CO'sExplorationProspect ID Seismic Acq./Processing SLB, PGS.NO, CGV, DWSN Evaluation Open Hole Wireline Logging SLB, BHI, HAL
Reservoir Imaging HAL Coring CLBProduction Testing SLB, Expro
DrillingContract Drilling Land NBR, PTEN, HP Drilling Services Bits SLB, BHI, NOV
Shallow Water HERO, RDC Fluids SLB, HAL, BHIDeepwater RIG, DO, SDRL OCTG TS, X
Directional Drilling SLB, HAL, BHI, WFT
CompletionCasing Handling WFT, TESO"Tools" HAL, BHI ,SLB, WFTPressure Pumping HAL, SLB, BHI, CRR, CPX
ProductionOngoing Chemicals BHI, Nalco Well Servicing Workover Rigs KEG, NBR, BAS (Enhancement) Artificial Lift WFT, SLB, BHI LUFK Coiled Tubing/Intervention BHI, CPX, SPN
Nat Gas Compression EXH, NGS Fishing SLB, BHICased Hole Wireline Logging SPN
Logistical Support Supply Boats TDW, CKHHelicopter BRS
Equipment/InfrastructureDevelopment Engineering/Design TEC.FP, ACGY, SPM.IM Capital Equipment Rig Equipment NOV, Aker, CAM
Fabrication GIFI, MDR Drill Pipe NOV, VallourecInstallation HLX, GLBL Seismic Equipment IO, CGV
Production Unit/Equipment OISProduction Subsea/Surface Equip. FTI, CAM, Aker, TTS
Umbilicals OII, TEC.FPRisers/Flowlines GE (OG), DRQ
Page 138
Geographic Revenue Segmentation (2010) Life Cycle Segmentation (2010)
Diversified Service Revenue by Product (2010)Diversified Service Revenue by Region (2010)
Source: Spears & Associates, Company data, Credit Suisse estimates
OFS: Diversified Service Segmentation
30%12% 6% 12%
64%84%
67%67%
6% 4%26% 21%
0%
20%
40%
60%
80%
100%
SLB HAL WFT BHI
Ex ploration Dev elopment Production
25%45% 40% 46%
33%
20% 37% 16%
42% 35%23%
38%
0%10%20%30%40%50%60%70%80%90%
100%
SLB HAL WFT BHI
NAM Land Intl Land Offshore
21%
48%37%
49%20%
13%16%
12%23%
20%
13%18%9%
3%
7%
5%18%11%
20%9%
8% 6% 6% 8%
0%
10%
20%30%
40%
50%
60%
70%80%
90%
100%
SLB HAL WFT BHI
Other E Hemi
Middle East
Russia/FSU
Eur/Afr
LAM
NAM 6% 5%
16%6%
6% 10%
3%
3% 7%
15%
15%10%
16%
13%
12% 7%28%
21% 40%
12% 20%
3%
15%
7%16%
3% 13%8%
19%4%
17% 14%
6%2%
0%10%20%30%40%50%60%70%80%90%
100%
SLB HAL WFT BHI
Other
Artificial Lift
Interv ention
Completion
Pumping
Other Drilling
Fluids
Dir Drilling
Bits
Wireline
Geophy sical
Com
pl.Pr
od'n
Drilli
ngEx
plor.
Page 139
Source: Company data, Credit Suisse estimates
OFS: Equipment/InfrastructureCameron (CAM) FMC Technologies (FTI)National Oilwell Varco (NOV)
Oceaneering (OII) Dril-Quip (DRQ) Dresser Rand Corp (DRC)2010 Revenues = $12.7B 2010 Revenues = $6.1B 2010 Revenues = $4.1B
2010 Revenues = $1.9B 2010 Revenues = $0.6B 2010 Revenues = $1.9B
Rig Technology
55%
Distribution Serv ices
12%
Petroleum Serv ices &
Supply33%
Subsea26%
Rig Equipment17%
Process & Compression
Systems19%
Valves & Measurement
21%
Surface17%
Remotely Operated Vehicles (ROVs)
34%
Subsea Projects
13%
Adv anced Technology
12%
Subsea Products
29%
Inspection & NDT12%
Subsea Equipment
65%
Offshore Rig Equipment
16%
Serv ices14%
Surface Equipment
5%
Upstream50%
Other5%
Env ironmental15%
Dow nstream20%
Midstream10%
Surface16%
Subsea65%
Energy Processing
Sy stems19%
Page 140
OFS: Market Shares for Key Services/Products
HAL29%
SLB24%
Trican5%
WFT4%
Calfrac4%
NBR1%
Others17%
Frac Tech5%
BHI11%
Pressure Pumping
Fluids Completions Artificial Lift Bits
Directional DrillingSeismic Wireline
Source: Spears & Associates
2010 Revenues = $25.0B 2010 Revenues = $11.8B 2010 Revenues = $9.4B 2010 Revenues = $9.5B
2010 Revenues = $8.3B 2010 Revenues = $6.6B 2010 Revenues = $6.5B 2010 Revenues = $3.5B
BHI14%
SLB54%
SPN3%
WFT6%
Ex pro2%
China OFS2%
J-W Wireline
2%
Others6%
HAL11%
SLB36%
HAL20%
BHI18%
Scientific Drilling
4%
Others15%
WFT7%
SLB37%
Others8%
NOV2%
WFT2%
China OFS2%
NR7%
HAL27%
BHI11%
TTI4%
SLB29%
BHI28%
NOV19%
Others4%
HAL14%
Varel6%
HAL34%
BHI32%
SLB17%
Ex pro3%WFT
12%
Others2%
CGV25%
SLB17%
PGS9%
Fugro7%
Others22%
GGS2%
TGS5%
GOK5%
HAL8%
WFT20%
BHI17%
SLB16%
Others19%
Dov er6%
LUFK7%
Borets8%
WG.LN7%
Page 141
OFS: Market Shares for Equipment/InfrastructureOffshore Construction
Compression
Surface Equipment
Subsea Tree Orders
Subsea Equipment
Source: Spears & Associates, Quest Offshore Resources
2010 Revenues = $29.9B 2010 Revenues = $10.9B
2010 Revenues = $2.4B
2010 Revenues = $3.6B
2010 Tree Orders = $6.7B
Saipem20%
KBR13%
MDR9%
Subsea 77%
OII2%
Others18%
DVR2%
GLBL2%
Technip3%
Fugro4%
Aker6%
SBMO7%
ACGY7%
CAM31%
FTI18%WG.LN
10%
Aker6%
Others21%
Weir SPM3%
TTES4%
GE7%
FTI25%
Technip17%
CAM15%
GE7%
Others9%
Aker14%
OII5%
WSM.LN4%
DRQ4%
EXH45%
Valerus5%
Others27%
Compr . Systems
6% J-W8%
CDM Resource
9%
FTI59%CAM
17%
AKER16%
GE8%
Page 142
OFS: Market Shares for Rig EquipmentBlowout Preventers (BOP)
Top DrivesCementing Skids
Mud Pumps
Source: Spears & Associates, ODS Petrodata, Oceaneering
Total since ‘05 = 183 BOPs Total since ‘05 = 169 Mud Pumps
Total since ‘05 = 219 Skids Total since ‘05 = 167 Top Drives
Rig Equipment
2010 Revenues = $13.2B
Drill Support ROVs
Total = 747 Vehicles
NOV53%
CAM8%
Aker5%
OIS3%
Others24%
Bentec2%
GE5%
CAM43%
Hydril27%
Shaffer22%
NOV7%
CIW1%
NOV53%
LEWCO20%
Wirth20%
Others7%
NOV60%
Maritime Hydraulics
19%
Hydralift7%
Others14%
OII35%
Subsea 720%
Sonsub8%
Fugro7%
Canyon6%
Other24%
HAL41%
BHI23%
SLB34%
Other2%
Page 143
OFS: Market Shares for Contract Drilling/OtherOffshore Contract Drilling
Petroleum Aviation Well Servicing
Land Contract DrillingSupply Vessels
Source: Spears & Associates
2010 Revenues = $37.2B 2010 Revenues = $19.3B
2010 Revenues = $3.9B 2010 Revenues = $3.3B
2010 Revenues = $6.5B
CPX8%
KEG15%
NBR17%
Integra6%
BAS6%
PDS5%
Others43%
Maersk 12%
Bourbon14%
TDW16%
TRMA7%
CKH12%
Gulfmark5%
Others34%
PTEN6%
HP10%
PDC6%
ESI6%
WFT5%
Saipem4%
SLB4%
Other44%
NBR15%RIG
24%Other32%
ESV5%
SDRL9%
DO9%
NE7%
China OFS4%
PDE4%
KCA Deutag
3%
Maersk3%
Rotorcraft4%
BRS31%
Petroleum9%
CKH6%
Heli-Union2%
Others9%
CHC Helicopter
39%
Page 144
OFS – Contract Drilling: Fleet Profiles
Fleet Profile by Company (all rigs)
Fleet Profile by Company (Floaters)
Source: ODS-Petrodata, note figures exclude newbuilds
Fleet Profile by Company (Jackups)
64
45 49
13 1428
3
50
17
23
5
4632
6
5
14
4
7
1
16
2
3
2
0
20
40
60
80
100
120
140
RIG ESV NE HERO DO SDRL RDC ATW
Jackup Semisubmersible Drillship Other (excl. platforms and barges)45 48
3036
71
18
2
11
1
16
2
7
22
214
0
10
20
30
40
50
60
70
RIG
HER
O
ESV
NE
RD
C
SDR
L
DO
ATW
NA
DL
Standard (< 300') Premium (> 300')
11
13
9
7
716
4 32
12
8
13
4
31
6
98
10
0
10
20
30
40
50
60
70
80
RIG DO ESV NE SDRL.OL ATW
Shallow Water Mid Water Deepwater Ultra Deepwater
Page 145
OFS – Contract Drilling: Fleet Age & Growth TrendsEstablished U.S. Drillers vs. Others’ Fleet Age Deepwater Expansion: Fleet more than doubling
within 5 year span (2008 to 2013E)
Source: ODS-Petrodata, Company data, Credit Suisse estimates
219187174
140
99
214
120
0
40
80
120
160
200
240
2008 2009 2010 2011E 2012E 2013E 2014E
Dee
pwat
er (4
,500
ft.+
) Rig
Sup
ply
at y
ear-
end
6-year CAGR:14%
Order Trends:
Established U.S. Drillers
vs. Others in Recent
Order Cycles
31.7 30.8
27.424.6
21.9 21.719.0
16.1
0
5
10
15
20
25
30
35HE
RO DO NE RIG
ESV
ATW
Othe
r Avg
.
RDC
Aver
age
Rig
Age
(Yea
rs)
Established U.S. Drillers = 48% Total Global Fleet
3 4 4 41
41 3 1 3 4
1 16
25
34
6 5 6
26
36 4
5
103
36
11
10
1
3 32
1 1
1
1 14
11
4
9
41 1 2
11
8 6
2
118
1
3
37
61
5
8
9
2 2
2
1 2
13
8
14
0
5
10
15
20
25
30
35
1Q04
2Q04
3Q04
4Q04
1Q05
2Q05
3Q05
4Q05
1Q06
2Q06
3Q06
4Q06
1Q07
2Q07
3Q07
4Q07
1Q08
2Q08
3Q08
4Q08
1Q09
2Q09
3Q09
4Q09
1Q10
2Q10
3Q10
4Q10
1Q11
2Q11
# of
Rigs
Ord
ered
Established Drillers: Floating Rigs Other Drilling Co's: Floating RigsEstablished Drillers: Jackups Other Drilling Co's: Jackups
Fav orable global macro env ironment and drilling
fundamentals open the door for new entrants
Risk of obsolescence in light of commodity price stability +
fav orable y ard economics encourages established
drillers to order again; new er market entrants capitalize on
this too
THE DOWNSTREAM
Page 147
The Downstream
Refining is the processing of raw crude into usable fuels called refined products: gasoline, diesel and jet. These products are sold into wholesale and retail markets.In the wholesale market, products are traded between large customers in global markets or on exchanges. These products are then sold into the retail market.In the retail market, petroleum products are sold to the end-user. The primary example of this gasoline or diesel sold at service stations.
Source: Company data, Credit Suisse estimates.
The downstream segment refers to all activities after crude is produced to when it is sold to the end-user.
Refining and marketing are the two key downstream components.
Petrochemicals are also included in downstream activities but are usually considered a separate segment.
Refining
Page 149
Refining Basics
Refining is the process of turning crude oil into usable petroleum products. A refinery is the factory where this process takes place.When in operation, refineries run continuously. However, refineries do take downtime for planned reasons, such as upgrading a refining unit, or unplannedreasons, such as fires or other accidents.
Exxon Mobil’s Baytown, TX refinery
BP’s Texas City, TX refinery
Source: www.houstonist.com
Source: www.state.tx.us
Sunoco’s Philadelphia, PA refinery
Source: www.sunoco.com
Page 150
Breaking Down a Barrel of Crude
The refining process splits crude oil into a variety of refined products.An example of the mix that comes from one barrel of crude oil is shown to the right.
To create these different products, a furnace first heats and vaporizes the crude. The vaporized crude is then piped into a crude distillation unit or CDU (referred to on the left as the Distillation Tower). Here, the vaporized crude naturally separates into different fractionsor cuts. The heavier cuts fall to the bottom of the CDU. This process is repeated several times until the cuts fully separate.
Source: www.eia.doe.gov
Source: www.eia.doe.gov
Page 151
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 152
From Fractions to Final Products
Once separation is complete, the various fractions are recondensed into liquid form. A typical barrel of light crude before any further treatment would look similar to the barrel shown on the right.
The product slate can then be further altered. Advanced upgrading units such as crackers and cokers treat products from the refinery’s first cut, generally breaking heavier fractions into lighter, shorter hydrocarbon chains. Examples of upgrading units are shown to the left. Not every refinery has each of these units.The more conversion units a refinery has, the more flexible it generally is in terms of final product slate. Conversion units also comprise a refinery’s complexity, which we discuss later.
Source: Bloomberg, Credit Suisse estimates
Source: www.zeonglobalenergy.com
Page 153
Basic Upgrading Units: Reformer & Desulfurizer
A reformer has two functions. The first is to upgrade low octane naphtha into high octane reformate, a key component of high octane gasoline. The second function is to provide the hydrogen needed by a distillate desulfurizer. Octane measures how resistant a fuel is to self-igniting, which causes knocking. Knocking occurs when the engine backfires, wasting fuel and causing potential engine damage. Higher octane gasolines are more resistant to self-igniting.A desulfurizer or hydrotreater uses hydrogen to strip out naturally occurring sulfur from final refined products (gasoline, diesel, heating oil) in order to comply with modern environmental requirements.
Sou
rce:
Mar
atho
n O
il
Reformer Desulfurization unit
Page 154
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.
Sou
rce:
Mar
atho
n O
il
Page 155
Advanced Upgrading Unit: Alkylation Unit
Cat cracked elements not sent to the gas-processing facility, blended, or cracked again are sent to an alkylation unit (shown below).– Alkylation is the reverse of fractionation: the process makes larger refined product components
from smaller molecules.
– A reverse processing gain occurs, as alkylation decreases yields. This is known as shrinkage.
– Paraffins, such as isobutane, are created in the gas-processing facility. These are combined with other olefins to form iso-paraffins, or alkylates. Alkylates are used as fuel additives to both boost the octane rating and make fuels cleaner-burning.
Source: Valero
Page 156
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.
Sou
rce:
Mar
atho
n O
il
Page 157
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 158
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 159
Where Does the Product Go Once It Is Refined?Once refined, products are transported to end-use sites such as retail stations. They can be transported by pipelines (shown to the right), trucks and ship. Pipelines are the cheapest form of transportation. Crude is also initially transported by these three means. Pipelines must be dedicated to either crude or refined product, not both.
If crude or product is not being used immediately, then it is stored in fields similar to the one to the left.
Source: www.eia.doe.gov
Source: www.eia.doe.gov
Page 160
Examples of the Uses for the Products Created from Crude
Liquid petroleum gas (LPG) is the lightest product. These gases can include ethane, butane, and propane and are used both as chemical feedstocks and for outdoor cooking.
Light distillates are the next cut up from LPGs and include gasoline and naphthas. These are used as petrochemical feedstocks and automotive fuels.
Middle distillates can include diesel fuel, jet fuel, kerosene, and heating oil. These are used for jets, trucks and residential heating.
Cuts that are heavier than middle distillates are usually called “bottom of the barrel” products. These can be residual fuels such as fuel oil and are used to power ships and for power generation. Asphalt is also a “bottom of the barrel” product.
Source: G
oogle images
Refinery Operations
Page 162
Ownership of Refining AssetsRefineries can be owned by both integrated oil and gas companies (with upstream operations) as well as by independent refiners. The distribution of ownership is shown to the right.Chevron and Exxon Mobil are two examples of integrated oil companies, sometimes referred to as Big Oil. The primary advantage of Big Oil owning refineries is that these companies can supply refinery operations using their own crude supply, although this doesn’t happen that much. The disadvantage is less flexibility in procuring crude from different producers.Independent refiners can be publicly traded like Valero or Tesoro or be privately owned such as Sinclair or Wyoming Refining. These companies can more easily buy crude from different producers and shop for the best possible price. However, the lack of upstream operations exposes independent refiners to crude price spikes and potential supply problems.
Source: OGJ
US Refining Capacity, by Ownership
Public independent 4.7 MMBD
27%
Private independent 3.3 MMBD
19%Integrated 9.4 MMBD
54%
Page 163
Geographical DivisionIn the U.S., refinery locations are divided into five separate Petroleum Administration for Defense Districts (PADDs). Each region has different benchmark margins and legal specifications. The map below illustrates the PADDs. The next slide shows the percent of total U.S. refining capacity in each PADD and the distribution of ownership within each PADD. The slide after that shows additional yield, complexity and ownership details within each PADD.
Source: www.eia.doe.gov
Page 164
Topic (1) WTI – Brent, Too Much Crude in the Mid-Con
Source: MPC
Page 165
Intermediate Solutions Reliant on RailRail Loading Capacity Announcements
Significant rail loading capacity is being added in 2012 in the Bakken. Barging increasing from Patoka.
HES 130kbd
Rangeland 100kbd
EDOG 100kbd
Musket 70kbd
Infrastructure bottlenecks could include access to trains and offloading capacity
Total Tariff from Bakken to St James Louisiana of $10-12/bbl.
PADD 2 production growing at 200kbd pa annualized from recent up-tick. There should be sufficient rail capacity to transport this by 2Q12.
Significant drilled but not completed well inventory in the Bakken.
Source for all charts: Credit Suisse estimates, Bloomberg, DOE
PADD 2 Crude Growth Through Jun-2011
45 050 0
55 060 0
65 070 0
75 080 0
Jan-
09
Mar
-09
May
-09
Jul-0
9
Sep-
09
Nov-0
9
Jan-
10
Mar
-10
May
-10
Jul-1
0
Sep-
10
Nov-
10
Jan-
11
Mar
-11
May
-11
M id w es t (P AD D 2) F ield Pro du c t ion o f C rud e O il (T h ou san d
0
100
200
300
400
500
600
70020
10
2011
1Q12
2Q12
3Q12
4Q12
2012
2013
2014
2015
2016
2017
(KBD
)
Page 166
WTI-Brent to Peak This Winter, Structurally Wider For LongerWTI-Brent Spread Futures Curve
Widening WTI-Brent has been a key theme in 2011. We have a mid-cycle supply-demand file which suggests a need for 2-3 pipelines to the Gulf
The likely peak of WTI-Brent should be this
winter as mid-con refineries shut for winter
maintenance and demand falls
As we move into 2012, increased rail capacity becomes available - $10-12/bbl from Bakken to the Gulf providing an alternative for E&P producers.
In 2013, Keystone XL adds pipeline capacity subject to 2H11 permit approvals and a successful construction program.
We need another pipeline in addition to XL –Enbridge, Energy Partners, Seaway Reversal in the frame.
Margin for error on supply not huge given potential from new plays e.g. Utica
Longer term Canada Still Grows – Exports to the West ?
….equally important where does WTI-Brent settle after the pipelines are built ?...
Source: Credit Suisse estimates, Bloomberg, DOE
Mid-Con Supply Demand Chart
$ 0
$ 5
$ 1 0
$ 1 5
$ 2 0
$ 2 5
3Q 1 1 1Q 1 2 3 Q 12 1 Q1 3 3Q 1 3 1 Q 14 3 Q1 4 1Q 1 5 3 Q 15
0
50 0
1 ,00 0
1 ,50 0
2 ,00 0
2 ,50 0
3 ,00 0
3 ,50 0
4 ,00 0
4 ,50 0
20 10 20 11 2012 2 01 3 2 014 201 5 20 16 2017
(KBD
)
Re fin ing P ip eline Ra il
Ta nke r + Ba rge S upply Growth
Page 167
Most Projects Still Work at $60 Oil, Bakken Most SensitiveRates of Return at the Current Futures Strip and $60 per Bbl Oil
At $60 oil, Marcellus moves to the front of the pack, but Granite Wash and Eagle Ford still exceed the 15% rate-of-return hurdle rate. Bakken and Barnett (liquids-rich) projects are more at risk.
At the current futures strip the Granite Wash, Eagle Ford, Marcellus and Bakken remain the highest returning plays in domestic onshore E&P.
Sou
rce:
Com
pany
Dat
a an
d C
redi
t Sui
sse
Estim
ates
53%
50%
37%
35%
27%
27%
26%
24%
22%
21%
19%
18%
18%
15%
15%
14%
12%
10%
8% 8% 6% 4%
26%
24%
36%
37%
12%
27%
19%
26%
24%
22%
12% 14% 18
%
18%
13% 15
%
11%
9% 10%
8%
6% 4% 4%
54%
0%
10%
20%
30%
40%
50%
60%
Granite
Was
h - Liquids R
ich H
oriz.
Eagle
Ford Shale
- Liquids R
ich
Marcell
us Shale
- SW Liquids R
ich
Marcell
us Shale
- SW
Bakke
n Shale / T
hree Forks
Sanish
Barnett
Shale - C
ore
Cana W
oodford Shale
Marcell
us Shale
- NE
Horn R
iver B
asin
Pinedale
Barnett
Shale - S
outhern Liquids R
ichHuro
n Shale
Eagle
Ford Shale
- Dry
Gas
Haynes
ville
Shale - C
ore LA / T
XBarn
ett Shale
Fayett
eville
Shale
Woodford Shale
- Arko
ma
Picean
ce B
asin Vall
ey
Granite
Was
h - Horiz
.
Haynes
ville/
Bossier
Shale - N
E TX
Cotton Vall
ey Vert
ical
Cotton Vall
ey H
orizontal
Powder Rive
r CBM
Current Futures Strip $60/Oil and Nat Gas at Futures Strip
Page 168
Even After Pipelines are Built to Gulf, Challenges RemainStructural Oversupply Versus Refining Capacity
Even after all required pipelines are built to the Gulf Coast, refinery bottlenecks need to be considered
The line on the chart shows the available light processing refining capacity in the Mid-Con and the Gulf after heavy processing capacity is stripped out
By 2014, onshore crude supply could exceed this light processing capacity.
Were this to occur, there would need to be crude exports from the Gulf to the North East
In this scenario WTI would trade $3-4/bbl below LLS but LLS would trade $2-3/bbl below Brent…i.e. a $5-7/bbl WTI-Brent spread into the longer term
POSITIVE LONGER TERM MARGINS AND FREE CASH FLOW FOR MID CON REFINERS AND IN THE GULF
SKITTISH EQUITY MARKET LIKELY WELCOME HEDGES
Source: Credit Suisse estimates, MPC
Theoretical Cost to Move EagleFord to PADD I
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
10,000
2009 2010 2011 2012 2013 2014 2015 2016 2017
KBD
GoM Padd 3 (Core)Texas (ex-Eagleford) BakkenPadd 2 (Core) Padd 4 (Core)Eagleford NiobaraMississippian UintaLight Crude Capacity
Page 169
Division by Ownership Type and PADD
Source: OGJ.
US Refining Capacity, by PADD
PADD III 8.4 MMBD
48%
PADD IV0.6 MMBD
4%
PADD V, 3.1, 18%
PADD I1.6 MMBD
9%
PADD II3.6 MMBD
21%
PADD IPrivate independent 0.1 MMBD
6%
Public independent
1.1 MMBD67%
Integrated 0.4 MMBD
27%
PADD II
Private independent 0.7
MMBD20%
Public independent 0.8
MMBD21%
Integrated2.1 MMBD
59%
PADD III
Integrated4.9 MMBD
58%
Public independent
1.7 MMBD20%
Private independent
1.9 MMBD22%
PADD IV
Integrated0.3 MMBD
47%
Public independent0.1 MMBD
21%
Private independent
0.2 MMBD32%
PADD V
Integrated1.6 MMBD
52%Public
independent1.1 MMBD
34%
Private independent0.4 MMBD
14%
Page 170
Refinery Summary, by PADD and Company
Source: Credit Suisse estimates.
Oil Product Marketing
Page 172
Introduction to Marketing
Marketing is divided into wholesale and retail segments. Profits from the marketing division tend to be more stable than those from the refining division.The wholesale market component involves the trade between large customers in global markets or on exchanges. These products are then sold into the retail market.
The retail market encompasses the sale of petroleum products to end-use markets and serve end users on a spot, transactional basis. The most common form of retail distribution is through the service station Benchmark margins for the U.S. retail segment since 1995 are shown above.
Sou
rce:
DO
E, C
redi
t Sui
sse
estim
ates
Composite Retail Margins Historical 4-week moving average 1995-Present
-
10
20
30
40
50
60
70
Jan-
95Ma
r-95
Jun-
95Se
p-95
Dec-9
5Fe
b-96
May-
96Au
g-96
Nov-9
6Ja
n-97
Apr-9
7Ju
l-97
Oct-9
7De
c-97
Mar
-98
Jun-
98Se
p-98
Nov-
98Fe
b-99
May-9
9Au
g-99
Nov-
99Ja
n-00
Apr-0
0Ju
l-00
Oct-0
0De
c-00
Mar-0
1Ju
n-01
Sep-
01No
v-01
Feb-
02Ma
y-02
Aug-
02Oc
t-02
Jan-
03Ap
r-03
Jul-0
3Se
p-03
Dec-
03M
ar-0
4Ju
n-04
Aug-
04No
v-04
Feb-
05Ma
y-05
Aug-
05Oc
t-05
Jan-
06Ap
r-06
Jul-0
6Se
p-06
Dec-0
6Ma
r-07
Jun-
07Au
g-07
Nov-0
7Fe
b-08
May-
08Ju
l-08
Oct-0
8Ja
n-09
Apr-0
9Ju
n-09
Sep-
09De
c-09
Mar
-10
May-1
0Au
g-10
Nov-
10Fe
b-11
May-1
1Ju
l-11
Oct-1
1
(cent
s/gal)
Page 173
Retail Margins Key to Profitability of the Marketing Business
The retail division tends to have a much greater percentage of the profit than the wholesale division owing to higher margins, so we focus on this part.Below, there are two charts of historical retail benchmark margins (excluding taxes). The left chart is for U.S. retail margins while the right chart is for retail margins in NorthWest Europe. The retail business is highly competitive and operators compete on both price and product quality.
Source: www.eia.doe.gov, Credit Suisse estimates
U.S. Retail Margins NorthWest Europe Retail Margins
2 0
3 0
4 0
5 0
6 0
7 0
8 0
Jan-
11
Jan-
11
Feb-1
1
Mar-1
1
Apr-1
1
May-1
1
Jun-1
1
Jul-1
1
Aug-
11
Sep-
11
Oct-1
1
Nov-1
1
Dec-1
1
(cen
ts/g
al)
5Y R A v g 20 11 20 10
-
1 0
2 0
3 0
4 0
5 0
6 0
Jan-
11
Feb-
11
Mar-1
1
Apr-1
1
May-1
1
May
-11
Jun-
11
Jul-1
1
Aug-
11
Sep-
11
Oct-1
1
Nov-1
1
Dec-1
1
(cen
ts/ga
l)
5 YR A vg 20 1 1 20 10
Page 174
More on the Retail Segment
Previously a gas station used to be just that…a gas station. To attempt to generate additional profits many gas stations now have convenience storesselling merchandise and food.Retail operators purchase fuel under long-term or short-term supply agreements either with oil companies (called branded) or from independently owned distributors.Big Oil and Independent Refiners have marketing and distribution costs associated with gasoline normally making it more expensive. Using unbranded gasoline can allow a retail station a wider profit margin. However, the quality and public perception of branded gasoline versus unbranded gasoline is different.As of July 2011, the federal fuel tax in the U.S. was 18.40 cents per gallon for gasoline and 24.40 cents per gallon for diesel. The average state tax for fuel was around 30.50 cents per gallon for motor gasoline and 29.60 cents per gallon for diesel.
Page 175
Retail Prices Tend to be Sticky
One final note about retail gasoline and diesel prices is that they tend to lag changes in wholesale prices, which makes the business somewhat seasonal.During the summer driving season, the run up in gasoline and diesel prices tend to support retail margins. Sharp moves up or down in crude can also narrow or expand retail margins, respectively.Total marketing margin = wholesale margin + retail margin
Source: Google Images
INVESTING IN BIG OIL
Page 177
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 178
Background
Super Majors– These large global integrated oil companies (IOCs) were formed from a wave of mergers that
took place between 1998 and 2003. – Typically show little volume growth and questions remain over reinvestment strategy.– Generous dividends and share buybacks characterized the upcycle.
Other– Smaller than the Super Majors and usually with a higher concentration of assets in select
regions (i.e. U.S., North Sea).– Usually more leveraged to commodity prices.
National Oil Companies (NOCs)– Fully or majority owned by national governments.– Some have recently started to reach beyond home areas.
Emerging Majors– Partially state-owned oil companies with public equity.– Have also begun to expand their operations beyond domestic borders.
Page 179
Super Majors (XOM, ENI, CVX, COP, TOT, BP, RDS)
In spite of significant reserve bases, the Super Majors have found it hard to grow production recently versus their peers. They exhibit high return on capital, while Emerging Majors and NOCs dominate the production growth rankings.
The Super Majors are mainly focused on large projects that can substantially increase their reserve base and compensate for significant base production declines.
Total Oil & Gas reserves – Super Majors (mmboe)
Sour
ce: C
redi
t Sui
sse
estim
ates
78,214
82,873
85,527
90,10690,795
88,98589,892
91,643
87,82588,724
91,654 91,684
70,000
75,000
80,000
85,000
90,000
95,000
1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
Page 180
Integrateds: Sensitivities
XOM Correlation
y = 0.2253x + 1.4425R2 = 0.9457
0
5
10
15
20
25
30
0 20 40 60 80 100 120 140WTI, US$/bbl
Net I
ncom
e, U
S$/b
bl
Typical Integrated Sensitivity vs Oil Price Typical Integrated Sensitivity vs Oil Price
12mth rolling Avg Oil 12mth rolling Avg Gas
Source: Credit Suisse estimates
% Net Incom e change for +1$/bbl change in OIL
0.0%
0.2%
0.4%
0.6%
0.8%
1.0%
1.2%
HES STL CVX BP MRO OMV XOM COP TOT BG RDS
% Net Incom e change for +1$/boe change in GAS
0.0%
0.2%
0.4%
0.6%
0.8%
1.0%
1.2%
BG CVX MRO STL COP BP HES XOM RDS TOT OMV
y = 0.4674x-0.9256
R2 = 0.7824
0.0%0.5%1.0%1.5%2.0%2.5%3.0%3.5%4.0%4.5%5.0%
0 20 40 60 80 100 120 140
Sens
itivi
ty
XOM Correlation
WTI, US$/bbl
Page 181
Profitability – Upstream Driven
Total returns for the Integrated Oils are driven by the upstream segment, although chemicals has been on an upswing.
Even in their best years, the downstream and chemicals segment performances have generally not been comparable to the upstream.
ROGIC (%) – Segment*So
urce
: Cre
dit S
uiss
e es
timat
es
*US Integrated Oils only
0.0%
5.0%
10.0%
15.0%
20.0%
25.0%
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
ROGIC - upstream ROGIC - downstream ROGIC - chemicals
Page 182
Segment breakdown – Upstream Driven*
The upstream has been a consistent outperformer
The relative outperformance of the upstream has led integrated oil companies to increase reinvestment spending in the business
ROCE - Segments Segmental capex
Source: Company, Credit Suisse estimates.
*US Integrated Oils only
14.0%15.7%
20.2%
23.0% 23.3%
3.7%5.0%
7.4%
11.8%13.2%
4.9%
19.9%
10.1% 10.6%9.4%
0%
5%
10%
15%
20%
25%
2009 2010 3-yr avg 5-yr avg 10-yr avg
Upstream Downstream Chemicals
0
10
20
30
40
50
60
70
80
90
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010E 10-yravg
5-yr avg 3-yr avg
Cap
ex ($
bn)
Upstream Downstream Chemicals
Page 183
-9%
0%
-11%
-21%
-5%
18%
5%
9%
-4%
17%
12%
18%
24%
15%
3%
-27%-30.0%
-25.0%
-20.0%
-15.0%
-10.0%
-5.0%
0.0%
5.0%
10.0%
15.0%
20.0%
25.0%
30.0%
1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
RecessionRecession
Performance
The Integrated Oils are a classic defensive investment class. They generally outperform during broad market downturns as these periods often coincide with rising energy price environments.
Integrated Oils vs. S&P500
Source: Credit Suisse estimates.
*Estimated end of recession as per St. Louis Federal Reserve Bank
Page 184
Characteristics
The Integrated Oils are the most conservative oil and gas investment compared to the more volatile Independent E&Ps and hyper-volatile Oilfield Service shares. They tend to perform better than the other oil and gas industries as the cycle shifts from peak to trough, but will likely underperform the highly leveraged E&Ps and Service companies when oil and gas fundamentals improve.
CVX
XOM
RDS
HES
MRO
SU
TOT
PCA
STO
REP
BG
IMO
ENICOP
BP
0.6
0.7
0.8
0.9
1
1.1
1.2
1.3
1.4
1.5
Average Integrateds Relative P/E vs. S&P500 Low Beta
Source: Company, Credit Suisse estimates.
0%
20%
40%
60%
80%
100%
120%
140%
160%
1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010
OUTLOOK FOR BIG OIL
Page 186
Under-appreciated Cash Flow Growth
– XOM, RDS and COP should deliver best in class growth+dividend yield
Potential Longer Term Cash flow Growth and Divs
Source: IEA, JODI, Credit Suisse Estimates
CFPS Drives 2015 Multiples Lower
0.0%
2.0%
4.0%
6.0%
8.0%
10.0%
12.0%
14.0%
XOM CVX HES COP RDS MRO TOT ENI BP
10 - 17 CAGR - Adjusted Total CFPS 2011 Div Yield
0.0
1.0
2.0
3.0
4.0
5.0
6.0
7.0
XOM
COP
HES
TOT
EOG
RDS
ENI
BP OXY
MRO
CVX
Historical Multiple, 5 yr Average (IOCs)
Page 187
Big Oil’s – Portfolio Shift and Performance Prize
Sou
rce
for a
ll ch
arts
: XO
M, C
redi
t Sui
sse
estim
ates
Portfolio Shifting to Long Duration Projects
Higher share of longer lived projects helps Big Oil manage the reinvestment treadmill. Longer lives should be correlated with higher multiples
On $120bn of upstream capex, a 10% performance improvement translates into 1% additional FCF yield
10% improvement in cost equals 1% FCF yield
0%
5%
10%
15%
20%
25%
30%
35%
40%
45%
50%
COP CVX XOM BP RDS TOT ENI
Shar
e of L
ong
Dura
tion
Long Duration, 2009 Long Duration, 2017
Page 188
Higher Cash Margins on New Upstream ProjectsOperating Cash Flow per Barrel on Selected New Projects (2011-15 Start-ups)
Source: Credit Suisse Estimates
– Cash margins on projects starting up in 2011-15 are up to 30-40% higher than existing production
– Margins are highest on Canadian oil sands (mined), GTL, US GoM deepwater and offshore West African projects (partly due to the timing of cost recovery)
$-
$1 0
$2 0
$3 0
$4 0
$5 0
$6 0
$7 0OM
L 13
8/139
(Usa
n/UKO
T)
Jack
/St M
alo
Whe
atsto
ne
Kash
agan
Pear
l GTL
Akpo
/Egin
a
CLOV
Gorg
on
Bloc
k 31 P
SVM
Quee
nslan
d Gas
Mars
B
Pazfl
or B
lock 1
7
APLN
G
AOSP
- Ba
se +
Ph 1
Golia
t
Qatar
gas 4
Skar
v
Tupi
(BM
-S-11
)
Junin
5
Guar
a (B
M-S-
9)
Rum
aila
Yem
en LN
G
ACG
Grou
ndbir
ch
MLE
& C
AFC
(405
b)
Page 189
Stocks are discounting a double dip
Sou
rce
for a
ll ch
arts
: Com
pany
dat
a, C
redi
t Sui
sse
estim
ates
Pessimism in future returns by company
Big Oil should generate CFROI of 6-8% at $80/bbl
Stocks are discounting only 2-5%CFROI
Big Oil would generate this CFROI on less than $60/bbl
Embedded returns lower than 2010
0
2
4
6
8
10
OXY
CVX
XOM
TOTF
HES
BP COP
RDSb
OMVV
STL
ENI
REP
MRO
CFROI, FY1 CFROI, Embedded
0.0
2.0
4.0
6.0
8.0
10.0
12.0
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011E
Embedded CR
FOI
(%)
0
20
40
60
80
100
120
140
($/bbl)
Average CFROI (LHS)Consensus Brent (RHS)
INVESTING IN E&P
Page 191
Evaluating E&Ps: Key MetricsProducers seek to create value by adding, producing and selling oil and natural gas reserves at a return greater than their cost of capital. There are several key metrics that help quantify producer performance:
– Reserve per Share Growth: Basic measure of a producer’s ability to add reserves. Industry average growth over the past five years has been about 8-10% annually.
– Reserve Replacement Ratio: A measure of reserve adds compared to production. Reserve replacement of >100% indicates incremental reserves were added net of production.
– Reserve Life: Indication of inventory depth by comparing how many years of reserves a producer has at current production. Median industry reserve lives are currently ~12.0 years.
– Recycle Ratio: Compares cash flow ($ per Boe) with finding and development costs ($ per Boe). A recycle ratio of 1 is a “breakeven point,” indicating that a producer is replacing what was produced. Industry three-year median is 1.9x.
– Reinvestment Rate: Reinvestment rates of > 100% indicate a producer will be free cash flow negative.
– PUD Percentage: Measures proved undeveloped (PUD) against total reserves. Higher relative PUD percentage will likely mean higher future capital needs to develop existing reserves.
Page 192
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 $5.63 per Mcfe as of 4Q10.
Page 193
Evaluating E&Ps: Hedging
Producers use derivative instruments to protect against volatility in commodity prices.
Common instruments: (1) swaps, (2) collars, (3) floors, and (4) natural gas basis swaps
Basis swaps protect regional gas prices by locking in differentials to NYMEX.
Hedging only protects near term cash flows. As hedges roll off, producers are forced to re-hedge at prevailing commodity prices.
Timing of when to put on hedges is an important management consideration.
Sample Natural Gas Collar ($ per MMBtu)
$0.00
$2.00
$4.00
$6.00
$8.00
$10.00
$12.00
$14.00
Jun-08
Jul-0
8
Aug-08
Sep-08
Oct-08
Nov-08
Dec-08
Jan-09
Feb-09
Collar Floor protects against downside volatility
Source: Bloomberg, Credit Suisse.
Page 194
Evaluating E&Ps: Valuation
The primary tools we use for valuing producers are Net Asset Value and Multiples.– Net Asset Value (NAV): An NAV is a discounted cash flow analysis of a producer’s
reserves.
In deriving an NAV, assumptions are made on future commodities prices, production rates, operating costs, finding & development costs, and life of reserves.
NAVs can be run on a producers 3P reserves (All-in NAV), proved reserves only, or proved-developed reserves. The choice of which NAV to use depends on the outlook for the producer to find, develop and produce out the reserves that will be discounted.
NAVs per share is compared to a producer’s stock price. Price to NAV > 100% suggests that a stock is over-valued (based on valuation assumptions).
– Multiples: The most commonly followed valuation multiple within the E&P sector is EV to EBITDA.
Recently, lack of visibility on future commodity prices have shifted valuation focus away from NAVs and placed EV to EBITDA multiples more in favor
Historically the group has traded at 6.0x EBITDA.
INVESTING IN OILFIELD SERVICES & DRILLING
Page 196
OFS: The Traditional Upstream Spending Cycle
North America leads the upturn, international markets lag
Int'l markets, deepwater markets accelerate and cycle approaches peak earnings
Change in macro environment precipitates decline in commodity prices
North American independents curtail upstream spendingCycle begins with
upturn in commodity prices
North America generally leads in a resumption in upstream spending because more of the activity is conducted by smaller (and therefore more nimble) operators (E&P companies). With shorter time horizons, generally, the North American operators are also the first to curtail spending in a downturn
Page 197
OFS: Oil Services Activities Through the Cycle
Production related services are the most resilient and the earliest to “revive”, but traditionally have the lowest Beta. Secular challenges related to hydrocarbon production have sustained higher-than-expected growth in the latest upcycle.
With more confidence in sustained higher commodity prices, drilling and completion related activity responds. Exploration is generally the last to strengthen and the first to fall in a downturn in oil prices.
As Drilling and Completions activity picks up, beneficiaries include rig count driven companies selling drilling materials (e.g. bits, fluids) - margins improve quickly as manufacturing absorption issues dissipate.
Companies with solid positions in International markets as well as deepwater/remote areas benefit from pick up in international activity. Key beneficiaries: Large caps, deepwater drillers
Oil companies increasingly focus on new Prospect Identification as existing prospects have been developed. Seismic companies are key beneficiary.
Companies that (1) Install Infrastructure for new developments (Production) and (2) provide new drilling rig equipment tend to see fastest earnings growth later in the cycle. Stocks respond to backlog growth in middle stages of the cycle.
Initial activity includes Well Servicing and Production Enhancement, i.e. the fastest way to take advantage of higher commodity prices is not through the drill bit. Beneficiaries: pressure pumpers, workover drilling contractors
Drilling Services companies experience price leverage as rig count rises and service utilization increases.
Page 198
OFS: Stocks Directionally Correlated with Upstream Spending
Note the strong directional correlation between spending patterns and the stocks as expectations for future upstream spending have historically been a significant driver of relative OFS stock performance.
OFS stocks tend to be highly anticipatory and move ahead of changes in spending patterns.
02468
101214161820
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
Qua
lRig
($bi
l)(M
onth
ly D
rill.
& C
ompl
. Spe
ndin
g)
0.00.51.01.52.02.53.03.54.04.55.05.5
OFS
Rel
ativ
e St
ock
Inde
x
Worldwide QualRig OFS Relative Stock Performance
Page 199
OFS: Gross Revenues Drive Upstream Spending
Spending trends tend to follow producer gross revenues (production times commodity prices)
Historically, spending trends tend to follow 18-month average of gross revenue at a reinvestment rate of approximately 11-12%.
20
40
60
80
100
120
140
160
180
200
220
240
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
E
2012
E
Mon
thly
WW
Pro
duce
r Gro
ss R
even
ue (1
8-M
o. A
vg)
2
4
6
8
10
12
14
16
18
20
22
24
Qua
lRig
($bi
l)M
onth
ly D
rillin
g &
Com
plet
ion
Spen
ding
($bi
l)
Worldw ide QualRig Average Yearly QualRig
Page 200
OFS – Contract Drilling: Offshore Drillers
Dayrates and utilization are key drivers of driller earnings power
Worldwide Semi Dayrate/Utilization
Source: ODS-Petrodata
Worldwide Jackup Dayrate/Utilization
$0
$40,000
$80,000
$120,000
$160,000
$200,000
$240,000
$280,000
$320,000
$360,000
$400,000
$440,000
Jan-
90
Jan-
91
Jan-
92
Jan-
93
Jan-
94
Jan-
95
Jan-
96
Jan-
97
Jan-
98
Jan-
99
Jan-
00
Jan-
01
Jan-
02
Jan-
03
Jan-
04
Jan-
05
Jan-
06
Jan-
07
Jan-
08
Jan-
09
Jan-
10
Jan-
11
WW
Sem
i Day
rate
s
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
WW
Sem
i Util
izat
ion
WW Semisubmersible Dayrates WW Semisubmersible Utilization WW Avg. Semisubmersible Utilization
Average = 83.9%
$0
$20,000
$40,000
$60,000
$80,000
$100,000
$120,000
Jan-
90
Jan-
91
Jan-
92
Jan-
93
Jan-
94
Jan-
95
Jan-
96
Jan-
97
Jan-
98
Jan-
99
Jan-
00
Jan-
01
Jan-
02
Jan-
03
Jan-
04
Jan-
05
Jan-
06
Jan-
07
Jan-
08
Jan-
09
Jan-
10
Jan-
11
WW
Jac
kup
Day
rate
s
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
WW
Jac
kup
Util
izat
ion
WW Jackup Dayrates WW Jackup Utilization WW Avg. Jackup Utilization
Average Utilization = 83.3%
Page 201
OFS – Contract Drilling: Offshore DrillersStocks are generally correlated with dayrate trends
Source: ODS-Petrodata
$0
$50,000
$100,000
$150,000
$200,000
$250,000
Dec-9
1
Dec-9
2
Dec-9
3
Dec-9
4
Dec-9
5
Dec-9
6
Dec-9
7
Dec-9
8
Dec-9
9
Dec-0
0
Dec-0
1
Dec-0
2
Dec-0
3
Dec-0
4
Dec-0
5
Dec-0
6
Dec-0
7
Dec-0
8
Dec-0
9
Dec-1
0
Offs
hore
Day
rate
s
0.00
2.00
4.00
6.00
8.00
10.00
12.00
14.00
16.00
CSFB OFS Index: Absolute Performance CSFB OFS Index: Relative Performance WW Offshore Dayrates (unweighted)
0.81
Relative R-squared = 0.79
Absolute R-squared =
Page 202
OFS: Traditional Valuation Methodologies
Services – as an earnings momentum group, we believe shares have generally been valued on forward year P/E and to a lesser extent forward EV/EBITDA. During trough periods, P/E or EV/EBITDA is applied to normalized or “mid-cycle” earnings estimates
Equipment – the backlog visibility, which can extend out as far as three years, lends itself to DCF. However, forward earnings metrics are also used
Drillers – with high asset intensity associated with owning the rigs, and different depreciation methods used by the companies, the industry tends to use forward year P/CF (EV/EBITDA). In the recent upcycle, backlog visibility lends itself to DCF. In troughs, replacement value metrics are also used
Offshore Asset Replacement Cost Trend
Diversified Service Forward P/E Trend
0.0%
20.0%
40.0%
60.0%
80.0%
100.0%
120.0%
140.0%
160.0%
180.0%
Q19
7
Q39
7
Q19
8
Q39
8
Q19
9
Q39
9
Q10
0
Q30
0
Q10
1
Q30
1
Q10
2
Q30
2
Q10
3
Q30
3
Q10
4
Q30
4
Q10
5
Q30
5
Q10
6
Q30
6
Q10
7
Q30
7
Q10
8
Q30
8
Q10
9
Q30
9
Q11
0
Q31
0
Q11
1
Cur
rent
Current = 81%
Maximum = 166%
Minimum = 41%
0
5
10
15
20
25
30
Dec-
04Fe
b-05
Apr-0
5Ju
n-05
Aug-
05Oc
t-05
Dec-
05Fe
b-06
Apr-0
6Ju
n-06
Aug-
06Oc
t-06
Dec-
06Fe
b-07
Apr-0
7Ju
n-07
Aug-
07Oc
t-07
Dec-
07Fe
b-08
Apr-0
8Ju
n-08
Aug-
08Oc
t-08
Dec-
08Fe
b-09
Apr-0
9Ju
n-09
Aug-
09Oc
t-09
Dec-
09Fe
b-10
Apr-1
0Ju
n-10
Aug-
10Oc
t-10
Dec-
10Fe
b-11
Apr-1
1Ju
n-11
Aug-
11
P/E
Prior Cy cle('96-mid '98)High = 25.8xAv e. =
Nov '04 - Aug '08:High = 24.3xAv e. = 17.0x
Current = 11.6x
Page 203
OFS: IndicatorsLeading Indicators– Seismic – Licensing rounds, Oil company exploration budgets, Sustained higher commodity
prices
– Drilling and Completion – Oil company spending budgets (generally set early in the calendar year, although they are revised intra-year), Permitting activity
Coincident Indicators– Oil and natural gas prices
– Earnings. As a traditionally earnings momentum-driven group, quarterly earnings matter.
– Pricing (day rates for drillers). Contract drilling shares are generally highly correlated with the trajectory of day rates.
– Rig count. North American rig counts are updated weekly (sources include Baker Hughes, M-I) or bi-weekly (The Land Rig Newsletter). Non-North American rig counts are updated monthly
Page 204
OFS: Secular Trends
Resource Nationalism. The recent upcycle/strength in commodity prices facilitated/was coincident with several countries becoming less accommodating to outside oil companies; this manifested itself in both contractual changes to lower oil company ownership stakes and higher taxes.
New Frontiers. Related to the above, international oil companies are being pushed to explore/exploit more challenging and higher cost environments to access hydrocarbons in their quest to grow reserves/production, including more offshore (and deeper waters).
Gas Monetization. The upcycle has seen more natural gas development (20% of the non-North America (non-NAM) rig count versus 15-18% in the 1998 cycle). Although the OFS activities are essentially the same, natural gas tends to be more lucrative than oil as it is often deeper (=higher pressure and temperature) and presents corrosion challenges.
NAM unconventional gas. The recent upcycle has seen the “unlocking” of NAM gas shales, including the use of horizontal drilling and aggressive multi-zonal completion techniques (including very large fracturing jobs). The shales plays are thought to be 2-5x more service intensive than traditional wells.
Bundling. The combination of human resource constraints at oil companies, more challenging reservoirs and demonstrated efficiencies are leading to more tendering for products and services on a bundled basis. This is driving organizational changes to meet this demand within service companies.
INVESTING IN REFINING
Page 206
Refining Margins Drive Refinery ValueRefining earnings are driven by refining margins (also called cracks or crack spreads). Cracks are normally quoted gross, for example, as the difference between the prices of refined products and the price of the crude feedstock, before operating costs.
Barrel of crude Finished productRefinery – processing center
There are four major determinants of margins. The first is crude cost, which is effectively the cost of goods sold. The second is finished or end product price. The higher this is, the wider the crack spreads. The third is refinery complexity or yield. More complex refiners run less attractive (cheaper) crudes and produce a higher yield of light products. The fourth determinant is regional supply/demand, mainly concerned with local market conditions and regulations.
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How to Calculate Benchmark Refining Margins
Benchmark refining margins attempt to give a rough overview of the current profitability of the refining industry. To calculate a benchmark margin, we assume that one barrel of crude from a region is then transformed into a standard suite of refined products. For instance, the Gulf Coast benchmark 3:2:1 margin (for PADD III) assumes that three barrels of WTI crude oil are turned into two barrels of gasoline and one barrel of middle distillates. Above we show an example of this calculation.Benchmark margins vary for each region. For instance, the New York Harbor (PADD I) uses a 6:3:2:1 margin, which assumes that six barrels of Brent crude oil are turned into three barrels of gasoline, two barrels of distillate, and one barrel of “bottom of the barrel” products or residual fuels.
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US$/gal US$/bbl (x 42)Gasoline 1.95 81.90 x 2/3 54.60Distillate 1.74 72.93 x 1/3 24.31Product price 78.91WTI crude 68.59 x 1 68.59Gulf Coast 3:2:1 refining margin 10.32
Page 208
Why We Use Theoretical Benchmark Margins
We can also look at individual crack spreads, such as what would one barrel of gasoline trade for above one barrel of WTI crude oil.One barrel of crude cannot actually transform into one barrel of gasoline (or any other product), however this is the convention in discussing gasoline cracks or distillate (heat) cracks. A NYMEX gasoline crack of $3.64/bbl means that one barrel of gasoline is currently trading at a $3.64 premium to one barrel of WTI crude. We illustrate recent gasoline and distillate crack spreads in the chart above.
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$(5)
$-
$5
$10
$15
$20
$25
$30
$35
1Q1999
4Q1999
3Q2000
2Q2001
1Q2002
4Q2002
3Q2003
2Q2004
1Q2005
4Q2005
3Q2006
2Q2007
1Q2008
4Q2008
3Q2009
2Q2010
1Q2011
$/bbl
Gasoline Distillate
Page 209
Additional Variables: Utilization Rates
The actual throughput for a refinery is known as its crude run. Crude runs can be less than nameplate capacity due to planned or unplanned downtime or due to an economic decision to reduce operating rates in the face of weak margins. The crude run divided by the crude capacity is known as the utilization rate. If a refinery can process 100 KBD of crude but crude runs are only 90 KBD, then the utilization rate is 90%. Utilization rates are seasonal and usually increase in the summer when US demand for gasoline is greater.
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70
75
80
85
90
95
100
Sep-
89
Sep-
91
Sep-
93
Sep-
95
Sep-
97
Sep-
99
Sep-
01
Sep-
03
Sep-
05
Sep-
07
Sep-
09
US
refin
ing
capa
city
dis
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utili
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n %
Page 210
Additional Variables: Complexity
Refineries are often divided into two categories: simple and complex. In reality complexity is measured on a continuum. One commonly used measure of complexity is the Nelson Complexity Index. The Nelson index dates from 1960 and assigns a separate complexity factor to each piece of equipment in a refinery (see LH picture below). The factor assigned is normally based on the piece’s cost relative to the crude distillation unit (CDU), which is assigned a complexity factor of 1.0.Below the complexity of Kuwait’s Mina Abdulla refinery is calculated. The index for vacuum distillation, for example, is 1.11, calculated as [134,000 / 242,000] x 2).
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-$0.10
$0.00$0.10
$0.20$0.30
$0.40
$0.50$0.60
$0.70$0.80
$0.90
1Q98
3Q98
1Q99
3Q99
1Q00
3Q00
1Q01
3Q01
1Q02
3Q02
1Q03
3Q03
1Q04
3Q04
1Q05
3Q05
1Q06
3Q06
1Q07
3Q07
1Q08
3Q08
1Q09
3Q09
1Q10
Gas
olin
e-R
esid
Spr
ead
(US$
/gal
)
$0
$5
$10
$15
$20
$25
WTI
-May
a S
prea
d (U
S$/
bbl)
Gasoline-Resid WTI-Maya
Why Not Make Every Refinery Complex?
Complex refineries can run different types of crude, quickly change product slates and produce more higher value products, so why not make every refinery complex? The upfront capital costs to add complexity are high and maintenance can be expansive. For some locations, more simple refineries may make sense.Above, we show historic crude and product differentials. A greater differential in the light-heavy spread favors complex refineries who run heavier crude but produce a similar light product yield to a simpler refinery processing light crude. Higher differentials between gasoline and residual fuel oil favor complex refiners, many of whom do not produce any fuel oil as a final product.
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Example of the Economics for a Simple vs. Complex Refinery
As illustrated above using two hypothetical Singapore refineries, 2008 year-end product pricing, and Dubai crude, a complex refinery generates a substantially higher cash margin than a simple refinery. Note that the percentages do not add up to 100%, as some refinery fuel and energy is lost in the process.While the difference in margins is appreciable, so is the cost of building a complex plant. In practice, complex refiners adapt their yield patterns to suit the market conditions prevailing at the time.
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Singapore complexUS$/bbl Dubai Product Output Crude Gross Operating CashRefined products yield % prices value cost margin cost marginGasoline 26.6% x 36.75 = 9.78Naphtha 7.4% x 29.25 = 2.16Jet/Kerosene 4.0% x 54.15 = 2.17Gas oil 38.6% x 57.85 = 22.33Fuel oil 22.3% x 32.61 = 7.27
98.9% 43.71 - 37.02 = 6.69 - 3.50 = 3.19
Singapore simpleUS$/bbl Dubai Product Output Crude Gross Operating CashRefined products yield % prices value cost margin cost marginGasoline 11.9% x 36.75 = 4.37Naphtha 5.1% x 29.25 = 1.49Jet/Kerosene 9.9% x 54.15 = 5.36Gas oil 24.4% x 57.85 = 14.12Fuel oil 46.2% x 32.61 = 15.07
97.5% 40.41 - 37.02 = 3.39 - 2.00 = 1.39
Page 213
A Few Final Notes about Refiner Profitability
Just because a refiner is complex does not mean that it can process heavier crudes. One must look into what is driving the higher complexity level. For instance, a plant may have extensive facilities to upgrade fuel oil or a lubricants plant but may not be able to process heavy or sour crudes.Competition is key for refiners. If a plant is in a relatively isolated market it will enjoy much higher margins than a plant in a merchant refining center.Operating costs are key to cash margins. These are driven by several factors including natural gas.
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US refiners are earnings momentum stocks
TesoroSunocoValero
When it comes to independent refining stocks, momentum often drives stock price movement. The charts above show how share price movements occurs after adjustments to EPS forecasts.
0.00.51.01.52.02.53.03.54.04.55.05.56.0
9/22
/200
612
/15/
2006
3/09
/200
76/
01/2
007
8/24
/200
711
/16/
2007
2/08
/200
85/
02/2
008
7/25
/200
810
/17/
2008
1/09
/200
94/
03/2
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6/26
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18/2
009
12/1
1/20
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05/2
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5/28
/201
08/
20/2
010
11/1
2/20
102/
04/2
011
4/29
/201
17/
22/2
011
TSO
NTM
EPS
0
10
20
30
40
50
60
70
TSO
sha
re p
rice
TSO EPS forecastTSO share price
0.00.51.01.52.02.53.03.54.04.55.05.56.06.57.07.58.08.59.0
9/22
/200
612
/15/
2006
3/09
/200
76/
01/2
007
8/24
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711
/16/
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2/08
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/17/
2008
1/09
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11/1
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102/
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4/29
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17/
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011
SU
N N
TM E
PS
15
25
35
45
55
65
75
85
95
SUN
sha
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SUN EPS forecastSUN share price
0.00.51.01.52.02.53.03.54.04.55.05.56.06.57.07.58.08.59.0
9/22
/200
612
/15/
2006
3/09
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76/
01/2
007
8/24
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711
/16/
2007
2/08
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/17/
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6/26
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08/
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/201
17/
22/2
011
VLO
NTM
EPS
051015202530354045505560657075
VLO
sha
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rice
VLO EPS forecastVLO share price
OUTLOOK FOR REFINING
Page 216
US gasoline demand has likely peaked…..FOREVER
US future oil demand growth is now seen at negative 0.1%, from a positive rate of over 1% between 1998 and 2007
We expect a 0.6% annual decline in gasoline consumption between 2010 –2020 from new CAFE standards. Adopting the full RFS would give a 1.4% annual decline.
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US Gasoline demand Long Term
5,000
6,000
7,000
8,000
9,000
10,000
2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
US
gaso
line
cons
umpt
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KB
D
Gasoline demand after CAFE Refiner Gasoline demand after CAFE and RFS
Economic bounce back slows decline in 2010
Page 217
Over Capacity in the Industry
Significant new capacity and a collapse in demand have ushered in The Dark Ages
Some proposed new capacity has started to slip
Expect more movement in that direction, including fewer Middle East refineries
Source: C
redit Suisse
-1000
-500
0
500
1000
1500
2000
2500
3000
2006 2007 2008 2009 2010 2011E 2012E 2013E 2014E 2015E
KB
D
North America OECD Europe South America FSU/Other Europe Africa Middle East OECD Pacific Other Asia Biofuels Demand growth
Page 218
US Crude Over Supply Throws a Lifeline to Mid-Con RefinersStructural Oversupply Versus Refining Capacity
Even after all required pipelines are built to the Gulf Coast, refinery bottlenecks need to be considered
The line on the chart shows the available light processing refining capacity in the Mid-Con and the Gulf after heavy processing capacity is stripped out
By 2014, onshore crude supply could exceed this light processing capacity.
Were this to occur, there would need to be crude exports from the Gulf to the North East
In this scenario WTI would trade $3-4/bbl below LLS but LLS would trade $2-3/bbl below Brent…i.e. a $5-7/bbl WTI-Brent spread into the longer term
Each $1/bbl margin adds 8% to EBITDA for a refinery
Refining stocks are deeply undervalued
Source: Credit Suisse estimates, HOLT
Embedded Returns in US Refiners (HOLT)
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
10,000
2009 2010 2011 2012 2013 2014 2015 2016 2017
KBD
GoM Padd 3 (Core)Texas (ex-Eagleford) BakkenPadd 2 (Core) Padd 4 (Core)Eagleford NiobaraMississippian UintaLight Crude Capacity
INVESTING IN MLPS
Page 220
What is an MLP?
Real Assets
Real Cash Flow
Real Company
Housed in a master limited partnership structure
Source: Credit Suisse analysis
MLP
Typical MLP Structure
Page 221
MLP Assets
Source: Spectra Energy website, American Petroleum Institute
An MLP must generate at least 90% of its income from qualifying sources (primarily natural resources activities) as defined in section 7704 of the internal revenue code
– Energy related assets include: Exploration and production, gathering and processing, transportation (e.g., pipelines), storage and terminals, refining, marine transportation, propane, and coal
– MLPs predominantly own midstream energy assets
Page 222
*Credit Suisse definition
Master limited partnerships (MLPs) are limited partnerships that are publicly traded on US stock exchanges. They trade just like common stock. However, unlike corporations, these are pass-through entities that pay no corporate taxes. A high proportion of distributions are tax-deferred.
Limited Partner (LP): provides capital, receives distributions, has no role in managing the partnershipGeneral Partner (GP): manages partnership, 2% equity ownership, owns incentive distribution rights (IDRs)Distribution: Similar to dividends, distributions are paid quarterly and a large portion (typically 70% to 100%) is tax deferredIncentive Distribution Rights (IDRs): Entitle the GP to an increasing portion of distributions (up to50%) as target distribution levels are attainedDistributable Cash Flow (DCF)*: maximum amount of cash flow available to pay limited partners after taking into account maintenance capital requirements and the general partner entitlementSchedule K-1: Investors receive Schedule K-1s instead of Form 1099sUBTI: MLPs generate unrelated business taxable income (UBTI)
MLP Key Terms Defined
Page 223
Cash Flow Characteristics– Gas pipelines and storage most stable and
secure cash flow given reservation fees – E&P/Refining least stable given commodity
price risk and depleting asset baseMaintenance Capex
– Too little can mean lower cash flow over timeCash Flow Coverage of Distribution
– More predictable cash flow streams = less need for excess distribution coverage
– Less predictable cash flow streams = greater need for excess distribution coverage
Source: Factset, Credit Suisse analysis
MLPs pay out majority of available cash flow
Access debt/equity markets needed to finance growthBenefit of business model:
Mandates financial discipline, transparency and focus on cash flowRisk to business model:
Reliance on capital markets for growth
MLP Business Model: Distribution Sustainability is Key
MLP Debt / Equity Issuance
5.7 5.37.0
8.311.1 11.5
20.2
16.2
4.9
8.3 9.2
19.1
5.6 6.8
15.1
7.8
0.0
5.0
10.0
15.0
20.0
25.0
2004 2005 2006 2007 2008 2009 2010 YTD
($bn
)
Debt Equity
Page 224
Source: Factset, Bureau of Labor Statistics; Prices as of 09/02/11
High tax-advantaged yield Current yield of 6.6%
+ Distribution growth 2011E growth of 4.9%
= Attractive total returnExpect 10 to 13% total returns
MLP Value Proposition
Total Return CAGRs: MLPs: 15.7%, S&P 500: 6.1%, R2000: 6.4%
Energy MLPs Annual Distribution Growth vs CPI
4.9% 4.5% 4.3%
7.0%
3.6% 3.8%4.8%
9.1%8.2%
9.4% 8.8%
2.6% 3.0%
4.9% 5.4% 5.0%
6.8%
-2.0%
0.0%
2.0%
4.0%
6.0%
8.0%
10.0%
12.0%
14.0%
1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011E 2012E 2013E 2014E
Annu
al D
ist G
rowt
h
MLP Distribution Growth (Median) Y/Y Change in CPI
AMZ ML P Ind ex Y ie ld
4%
6%
8%
10%
12%
14%
16%
1/5/96
8/2/96
2/28/97
9/26/97
4/24/98
11/20/9
86/1
8/99
1/14/0
08/1
1/00
3/9/01
10/5/0
15/3/0
211
/29/02
6/27/03
1/23/04
8/20/04
3/18/05
10/14/0
55/1
2/06
12/8/0
67/6/
072/1/0
88/29/0
83/27
/0910
/23/09
05/21/
1012/
17/10
07/15/1
1
Total Return (Since 1996)
-200%0%
200%400%600%800%
1000%1200%
12/29/
959/1
3/96
5/30/9
72/1
3/98
10/30/
987/1
6/99
3/31/0
012/
15/00
8/31/0
15/1
7/02
1/31/0
310/
17/03
7/2/04
3/18/0
512/
2/05
8/18/0
65/4
/071/1
8/08
10/3/0
86/1
9/09
3/5/10
11/19/
108/5
/11
AMZ MLP Index TR S&P500 TR Russell 2000 TR
164%
886%
153%
Page 225
Follow the Cash, No One Really Cares About EarningsMLPs are primarily valued on their distributions, expectations for distribution growth
and perceived risk profile
Valuation MethodologiesDistribution Discount Model (DDM) Methodology
– Credit Suisse preferred methodology – Price target is based on a three-stage DDM model, which discounts five years of distribution forecast,
assumes a second stage of moderating distribution growth and a terminal value – To arrive at a discount rate we use a blended approach combining the discount rate implied by the
capital asset pricing model with the discount rate implied by investor’s required rate of return (yield plus expected distribution growth)
– Subjective factors are considered: asset mix, stability of cash flows and management track recordTarget Yield Methodology
– Price target derived by projecting a targeted yield on an expected distribution rate 12 months out – Yield spread comparisons are usually analyzed. Since 1999, MLPs have traded at 322 basis points
spread to the ten-year US treasury and 595 basis point spread to a high yield bond indexRelative Valuation Metrics
– Price / Distributable cash flow (DCF) multiple– Adjusted Enterprise Value / EBITDA multiple
Valuation Framework: DDM is Preferred Methodology
Page 226
Source: Factset, Alerian website, Credit Suisse analysis; Prices as of 09/08/11
MLPs yield 6.6%, 459 bps more than treasuries, which is close to one standard deviation above the historical average. MLP yields remain compelling relative to investment grade bonds.On a price-to-distributable cash flow basis, MLPs remain within their historical +/- one standard deviation range of 10x to 14x.
Yield Spread AnalysisA M Z P r ic e/D C F (1 9 9 6-2 0 11 )
4x
6x
8x
1 0x
1 2x
1 4x
1 6x
1 8x
1/5/9
66/
28/96
12/2
0/96
6/13
/9712
/5/97
5/29/9
811
/20/9
85/
14/99
11/5
/99
4/28
/00
10/2
0/00
4/12/0
110
/5/01
3/28
/029/2
0/02
3/14
/03
9/5/0
32/2
7/04
8/20
/04
2/11
/058/5
/051/2
7/06
7/21
/061/1
2/07
7/6/07
12/2
8/07
6/20/0
812
/12/08
6/5/0
911
/27/
0905
/21/10
11/1
2/10
05/0
6/11
C u r re n t = 13 .2x
A v er ag e = 12 .0x
C S L U C I B B B 7-1 0 Y r Sp re a d to 1 0 -Y r T re a su ry (1 9 9 9 -2 0 1 1)
0
10 0
20 0
30 0
40 0
50 0
60 0
70 0
80 0
1/15
/99
7/9/9
912
/31/99
6/23
/00
12/1
5/00
6/8/01
11/30
/01
5/24
/02
11/15
/025/
9/03
10/3
1/03
4/23/0
410
/15/0
44/
8/05
9/30/0
53/
24/06
9/15
/06
3/9/0
78/
31/07
2/22
/08
8/15
/08
2/6/
097/
31/0
901
/22/1
007
/16/1
001
/07/11
07/01
/11
C u r ren t Sp r ea d = 21 5
Av era g e Sp r ea d = 20 6
A M Z Y ie ld v s . 1 0 y r T r e as u ry (1 9 9 9 -2 0 1 1)
0
2 0 0
4 0 0
6 0 0
8 0 0
1 , 0 0 0
1 , 2 0 0
1 , 4 0 0
1/15/9
97/
9/99
12/31
/99
6/23
/00
12/1
5/00
6/8/01
11/3
0/01
5/24/
0211
/15/
025/
9/03
10/3
1/03
4/23
/0410
/15/04
4/8/
059/
30/0
53/
24/0
69/
15/0
63/9
/078/
31/07
2/22/0
88/
15/0
82/
6/09
7/31/0
901
/22/1
007
/16/
1001
/07/1
107
/01/11
C u rr e n t S p re a d = 4 5 9A v e ra g e S p re a d = 3 2 2
AMZ Y ield vs. CS LUCI BBB 7-10 Yr (1999-2011)
-200-100
0100200300400500600700
1/15/9
97/
9/99
12/31
/99
6/23
/00
12/1
5/00
6/8/01
11/3
0/01
5/24/
0211
/15/
025/
9/03
10/3
1/03
4/23
/0410
/15/04
4/8/
059/
30/0
53/
24/0
69/
15/0
63/9
/078/
31/07
2/22/0
88/
15/0
82/
6/09
7/31
/09
01/2
2/10
07/1
6/10
01/0
7/11
07/01
/11
A verag e = 118b psC urrent = 244ps
IG cred tis are att ractive vs. MLPs
M LPs are at tractive vs. IG credits
Disclosures
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Companies Mentioned (Price as of 21 Sep 11) Alon USA Energy Inc. (ALJ, $7.61) Anadarko Petroleum Corp. (APC, $72.72) Atwood Oceanics, Inc. (ATW, $37.47, NEUTRAL [V], TP $45.00) Baker Hughes Inc. (BHI, $54.33, OUTPERFORM, TP $93.00) Berry Petroleum Co. (BRY, $43.71, OUTPERFORM, TP $70.00) BHP Billiton (BLT.L, 1888.50 p, NEUTRAL, TP 3160.00 p) Bill Barrett Corp (BBG, $41.21) Boardwalk Pipeline Partners, LP (BWP, $26.07, OUTPERFORM, TP $35.00) BP (BP.L, 404.05 p, OUTPERFORM, TP 610.00 p) Bristow Group Inc. (BRS, $42.65, OUTPERFORM, TP $53.00) Cabot Oil & Gas Corp (COG, $70.03) Cameron International Corp. (CAM, $47.58, OUTPERFORM, TP $74.00) Chesapeake Energy Corp. (CHK, $29.42) Chevron Corp. (CVX, $94.27, OUTPERFORM, TP $130.00) Cobalt International Energy (CIE, $8.78, OUTPERFORM [V], TP $17.00) Complete Production Services (CPX, $22.74, NEUTRAL [V], TP $52.00) ConocoPhillips (COP, $64.95, RESTRICTED) CONSOL Energy Inc. (CNX, $37.92, OUTPERFORM, TP $65.00) Delek US Holdings, Inc. (DK, $12.52, NEUTRAL, TP $17.00) Denbury Resources (DNR, $12.99, NEUTRAL, TP $30.00) Devon Energy Corp (DVN, $61.61) Diamond Offshore (DO, $60.22, UNDERPERFORM, TP $67.00) Dresser Rand Group Inc (DRC) Dril-Quip, Inc. (DRQ, $63.72) Duncan Energy Partners, LP (DEP, $41.22) EnCana Corp. (ECA, $21.64, OUTPERFORM, TP $36.00) Energy Transfer Equity, LP (ETE, $37.43, RESTRICTED) Energy Transfer Partners, L.P. (ETP, $43.89, RESTRICTED) ENI (ENI.MI, Eu12.88, NEUTRAL, TP Eu19.00) Ensco Plc. (ESV, $46.19, OUTPERFORM, TP $71.00) Enterprise GP Holdings, LP (EPE, $43.48) Enterprise Products Partners, LP (EPD, $42.26, OUTPERFORM, TP $46.00) EOG Resources (EOG, $83.43) EV Energy Partners LP (EVEP, $72.31) Exterran Holdings (EXH, $9.71, NEUTRAL, TP $17.00) ExxonMobil Corporation (XOM, $71.97, NEUTRAL, TP $95.00) FMC Technologies, Inc. (FTI, $41.13, NEUTRAL, TP $49.00) Forest Oil (FST, $17.62, OUTPERFORM [V], TP $29.00) Frontier Oil Corporation (FTO, $32.31) Gardner Denver, Inc. (GDI, $71.63, NEUTRAL, TP $91.00) Global Geophysical Services, Inc. (GGS, $8.20, OUTPERFORM [V], TP $21.00) Goodrich Petroleum Corp. (GDP, $14.91) Gulfport Energy Corporation (GPOR, $26.35) Halliburton (HAL, $35.09, OUTPERFORM, TP $66.00) Helmerich & Payne, Inc. (HP, $48.27, NEUTRAL, TP $69.00) Hercules Offshore (HERO, $3.63, OUTPERFORM [V], TP $6.50) Hess Corporation (HES, $56.49, OUTPERFORM, TP $115.00) Holly Corp. (HOC, $71.76) HollyFrontier Corp (HFC, $29.64, OUTPERFORM [V], TP $50.00) Husky Energy Inc. (HSE.TO, C$22.93, NEUTRAL, TP C$32.00) Kinder Morgan Energy Partners, L.P. (KMP, $70.70, NEUTRAL, TP $77.00) Kinder Morgan Management, LLC (KMR, $60.04, OUTPERFORM, TP $73.41) Kosmos Energy Ltd (KOS, $12.79, OUTPERFORM [V], TP $25.00) LUKOIL (LKOH.RTS, $56.90, OUTPERFORM, TP $105.20) Magellan Midstream Partners, LP (MMP, $61.29, NEUTRAL, TP $62.00) Marathon Oil Corp (MRO, $23.73, NEUTRAL, TP $36.00) Murphy Oil Corp. (MUR, $48.03) Nabors Industries, Ltd. (NBR, $15.63, OUTPERFORM, TP $35.00) National Oilwell Varco (NOV, $58.04, OUTPERFORM, TP $95.00) Neste (NES1V.HE, Eu7.16, NEUTRAL, TP Eu11.50) Newfield Exploration Co. (NFX, $44.30) Nexen Inc. (NXY.TO, C$17.28, NEUTRAL, TP C$27.00) Noble Corporation (NE, $33.41, OUTPERFORM, TP $51.00) Noble Energy (NBL, $77.09)
NuStar Energy LP (NS, $56.00, NEUTRAL, TP $68.00) NuStar GP Holdings LLC (NSH, $33.25, NEUTRAL, TP $36.00) Occidental Petroleum (OXY, $76.32, NEUTRAL, TP $128.00) Oceaneering Intl, Inc. (OII, $39.15, NEUTRAL, TP $48.00) Oil States International (OIS, $58.32, OUTPERFORM [V], TP $110.00) OMV (OMVV.VI, Eu25.04, UNDERPERFORM, TP Eu28.00) Patterson-UTI Energy, Inc. (PTEN, $19.54, OUTPERFORM, TP $42.00) Petrobras (PBR, $24.64, NEUTRAL, TP $38.00) Pioneer Natural Resources (PXD, $74.34) Plains All American Pipeline, L.P. (PAA, $60.04, OUTPERFORM, TP $67.00) Plains Exploration & Production Co. (PXP, $25.75) Quicksilver Resources, Inc. (KWK, $8.63, NEUTRAL, TP $12.00) Range Resources (RRC, $67.96, OUTPERFORM, TP $77.00) Repsol YPF SA (REP.MC, Eu19.52, OUTPERFORM, TP Eu29.50) Rex Energy Corp. (REXX, $14.28, NEUTRAL [V], TP $13.00) Rosetta Resources Inc. (ROSE, $43.01, OUTPERFORM [V], TP $71.00) Rowan Companies (RDC, $35.23, NEUTRAL, TP $46.00) Royal Dutch Shell PLC (ADR) (RDSa.N, $63.15, OUTPERFORM, TP $90.00) Schlumberger (SLB, $65.15, OUTPERFORM, TP $117.00) Seadrill (SDRL, NKr184.10, NEUTRAL, TP NKr178.00) Smith International, Inc. (SII, $38.84) Southwestern Energy Co. (SWN, $38.70) Spectra Energy Partners, LP (SEP, $28.77, NEUTRAL, TP $34.00) St. Mary Land (SM, $76.99) Statoil (STL.OL, NKr127.60, NEUTRAL, TP NKr159.00) Suncor Energy (SU.TO, C$28.13, OUTPERFORM, TP C$50.00) Sunoco Logistics Partners, L.P. (SXL, $88.22, OUTPERFORM, TP $93.00) Swift Energy Co. (SFY, $29.26, OUTPERFORM, TP $52.00) Tesoro Corp. (TSO, $21.47, OUTPERFORM [V], TP $36.00) Tidewater (TDW, $53.71, OUTPERFORM, TP $63.00) Total (TOTF.PA, Eu32.20, NEUTRAL, TP Eu46.00) Transocean Inc. (RIG, $56.30, NEUTRAL, TP $71.00) Tullow Oil (TLW.L, 1333.00 p, OUTPERFORM, TP 1804.00 p) Ultra Petroleum Corp. (UPL, $32.54) Valero Energy Corporation (VLO, $19.89, OUTPERFORM, TP $41.00) Weir Group (WEIR.L, 1768.00 p, OUTPERFORM, TP 2000.00 p) Western Refining Inc. (WNR, $14.35, NEUTRAL [V], TP $24.00) Whiting Petroleum Corp. (WLL, $41.04, OUTPERFORM, TP $73.00)
Disclosure Appendix Important Global Disclosures Arun Jayaram, CFA, Brad Handler & Edward Westlake each certify, with respect to the companies or securities that he or she analyzes, that (1) theviews expressed in this report accurately reflect his or her personal views about all of the subject companies and securities and (2) no part of his orher compensation was, is or wil l be directly or indirectly related to the speci fic recommendations or views expressed in this report. See the Companies Mentioned section for ful l company names. The analyst(s) responsible for preparing this research report received compensation that is based upon various factors including Credit Suisse's totalrevenues, a portion of which are generated by Credit Suisse's investment banking activities. Analysts’ stock ratings are defined as follows: Outperform (O): The stock’s total return is expected to outperform the relevant benchmark* by at least 10-15% (or more, depending on perceivedrisk) over the next 12 months. Neutral (N): The stock’s total return is expected to be in line with the relevant benchmark* (range of ±10-15%) over the next 12 months. Underperform (U): The stock’s total return is expected to underperform the relevant benchmark* by 10-15% or more over the next 12 months. *Relevant benchmark by region: As of 29th May 2009, Australia, New Zealand, U.S. and Canadian ratings are based on (1) a stock’s absolute totalreturn potential to its current share pr ice and (2) the relative attractiveness of a stock’s total return potential within an analyst’s coverage universe**,with Outperforms representing the most attractive, Neutrals the less attractive, and Underperforms the least attractive investment opportunities.Some U.S. and Canadian ratings may fall outside the absolute total return ranges defined above, depending on market conditions and industryfactors. For Latin American, Japanese, and non-Japan Asia stocks, ratings are based on a stock’s total return relative to the average total return ofthe relevant country or regional benchmark; for European stocks, ratings are based on a stock’s total return relative to the analyst's coverageuniverse**. For Austral ian and New Zealand stocks, 12-month rolling yield is incorporated in the absolute total return calculation and a 15% and a7.5% threshold replace the 10-15% level in the Outperform and Underperform stock rating definitions, respectively. The 15% and 7.5% thresholdsreplace the +10-15% and -10-15% levels in the Neutral stock rating definition, respectively. **An analyst's coverage universe consists of all companies covered by the analyst within the relevant sector.
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Restricted (R): In certain circumstances, Credit Suisse policy and/or applicable law and regulations preclude certain types of communications,including an investment recommendation, during the course of Credit Suisse's engagement in an investment banking transaction and in certain othercircumstances. Volatility Indicator [V]: A stock is defined as volatile if the stock price has moved up or down by 20% or more in a month in at least 8 of the past 24months or the analyst expects significant volatility going forward.
Analysts’ coverage universe weightings are distinct from analysts’ stock ratings and are based on the expectedperformance of an analyst’s coverage universe* versus the relevant broad market benchmark**: Overweight: Industry expected to outperform the relevant broad market benchmark over the next 12 months. Market Weight: Industry expected to perform in- line with the relevant broad market benchmark over the next 12 months. Underweight: Industry expected to underper form the relevant broad market benchmark over the next 12 months. *An analyst’s coverage universe consists of all companies covered by the analyst within the relevant sector. **The broad market benchmark is based on the expected return of the local market index (e.g., the S&P 500 in the U.S.) over the next 12 months. Credit Suisse’s distribution of stock ratings (and banking clients) is:
Global Ratings Distribution Outperform/Buy* 49% (61% banking clients) Neutral/Hold* 40% (56% banking clients) Underperform/Sell* 9% (52% banking clients) Restricted 2% *For purposes of the NYSE and NASD ratings distribution disclosure requirements, our stock ratings of Outperform, Neutral, and Underperform most closely correspond to Buy,Hold, and Sell, respectively; however, the meanings are not the same, as our stock ratings are determined on a relative basis. (Please refer to definitions above.) An investor'sdecision to buy or sell a security should be based on investment objectives, current holdings, and other individual factors. Credit Suisse’s policy is to update research reports as it deems appropriate, based on developments with the subject company, the sector or themarket that may have a material impact on the research views or opinions stated herein. Credit Suisse's policy is only to publish investment research that is impartial, independent, clear, fair and not misleading. For more detail please refer to CreditSuisse's Policies for Managing Conflicts of Interest in connection with Investment Research:http://www.csfb.com/research-and-analytics/disclaimer/managing_conflicts_disclaimer.html Credit Suisse does not provide any tax advice. Any statement herein regarding any US federal tax is not intended or written to be used, and cannotbe used, by any taxpayer for the purposes of avoiding any penalties. Important Regional Disclosures Singapore recipients should contact a Singapore financial adviser for any matters arising from this research report. Restrictions on certain Canadian securities are indicated by the following abbreviations: NVS--Non-Voting shares; RVS--Restricted Voting Shares;SVS--Subordinate Voting Shares. Individuals receiving this report from a Canadian investment dealer that is not affil iated with Credit Suisse should be advised that this report may notcontain regulatory disclosures the non-affiliated Canadian investment dealer would be required to make if this were its own report. For Credit Suisse Securities (Canada), Inc.'s policies and procedures regarding the dissemination of equity research, please visithttp://www.csfb.com/legal_terms/canada_research_policy.shtml. Credit Suisse Securities (Europe) Limited acts as broker to DK. The following disclosed European company/ies have estimates that comply with IFRS: BP.L, DK, ENI.MI, XOM, LKOH.RTS, NES1V.HE, OMVV.VI,REP.MC, SDRL, STL.OL, TOTF.PA, TLW.L, WEIR.L, BLT.L. As of the date of this report, Credit Suisse acts as a market maker or liquidity provider in the equities securities that are the subject of this report. Principal is not guaranteed in the case of equities because equity prices are variable. Commission is the commission rate or the amount agreed with a customer when setting up an account or at anytime after that. CS may have issued a Trade Alert regarding this security. Trade Aler ts are short term trading opportunities identi fied by an analyst on the basis ofmarket events and catalysts, while stock ratings reflect an analyst's investment recommendations based on expected total return over a 12-monthperiod relative to the relevant coverage universe. Because Trade Alerts and stock ratings reflect different assumptions and analytical methods, TradeAlerts may differ directionally from the analyst's stock rating. The author(s) of this report maintains a CS Model Portfolio that he/she regularly adjusts. The security or securities discussed in this report may be acomponent of the CS Model Portfolio and subject to such adjustments (which, given the composition of the CS Model Portfolio as a whole, may differfrom the recommendation in this report, as well as opportunities or strategies identified in Trading Alerts concerning the same security). The CSModel Portfolio and important disclosures about it are available at www.credit-suisse.com/ti. Taiwanese Disclosures: Reports written by Taiwan-based analysts on non-Taiwan listed companies are not considered recommendations to buy orsell securities under Taiwan Stock Exchange Operational Regulations Governing Securities Firms Recommending Trades in Securi ties toCustomers. To the extent this is a report authored in whole or in part by a non-U.S. analyst and is made available in the U.S., the following are importantdisclosures regarding any non-U.S. analyst contr ibutors: The non-U.S. research analysts listed below (if any) are not registered/qualified as research analysts with FINRA. The non-U.S. research analystslisted below may not be associated persons of CSSU and therefore may not be subject to the NASD Rule 2711 and NYSE Rule 472 restr ictions oncommunications with a subject company, public appearances and trading securities held by a research analyst account.
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