Global LNG

Transcription

Global LNG

Deutsche Bank
Markets Research
North America
United States
Industrials
Industry
Global LNG
Integrated Oil
Date
17 September 2012
Industry Update
Paul Sankey
Research Analyst
(+1) 212 250-6137
[email protected]
Lucas Herrmann, ACA
Research Analyst
(+44) 20 754-73636
[email protected]
David T. Clark, CFA
Research Analyst
(+1) 212 250-8163
[email protected]
Silvio Micheloto, CFA
Research Analyst
(+1) 212 250-1653
[email protected]
Winnie Nip
Research Associate
(+1) 212 250-8529
[email protected]
Gorgon & the Global LNG Monster
Slow and steady wins the race
Since oil peaked in July 2008, the S&P500 is up 16%, the NASDAQ up 42%, E&P stocks & the
OSX are down ~30%. The four best-performing major oils since then: Chevron, ExxonMobil, Shell
and BG. If you were asked in a pub quiz for oil analysts what the common link between the four
stocks was, you might just say "LNG". Always considered a tough theme to get direct exposure
to, in this note we preview Chevron's Gorgon field trip and re-present the global LNG note
recently published by Lucas Herrmann on our European Oil Team. We have written a global LNG
note every two years since 1998. The song remains the same: 7% growth in supply & demand to
the forecast end.
________________________________________________________________________________________________________________
Deutsche Bank Securities Inc.
All prices are those current at the end of the previous trading session unless otherwise indicated. Prices are sourced
from local exchanges via Reuters, Bloomberg and other vendors. Data is sourced from Deutsche Bank and subject
companies. Deutsche Bank does and seeks to do business with companies covered in its research reports. Thus,
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. DISCLOSURES AND
ANALYST CERTIFICATIONS ARE LOCATED IN APPENDIX 1. MICA(P) 072/04/2012.
Deutsche Bank
Markets Research
North America
United States
Industrials
Industry
Global LNG
Integrated Oil
Date
17 September 2012
Industry Update
Paul Sankey
Gorgon & the Global LNG Monster
Research Analyst
(+1) 212 250-6137
[email protected]
Slow and steady wins the race
Since oil peaked in July 2008, the S&P500 is up 16%, the NASDAQ up 42%,
E&P stocks & the OSX are down ~30%. The four best-performing major oils
since then: Chevron, ExxonMobil, Shell and BG. If you were asked in a pub quiz
for oil analysts what the common link between the four stocks was, you might
just say "LNG". Always considered a tough theme to get direct exposure to, in
this note we preview Chevron's Gorgon field trip and re-present the global LNG
note recently published by Lucas Herrmann on our European Oil Team. We
have written a global LNG note every two years since 1998. The song remains
the same: 7% growth in supply & demand to the forecast end.
Lucas Herrmann, ACA
The world LNG market simply goes from strength to strength
We are now in our 14th year of analysing this market, and the forecast remains
the same: 7% annual growth, even off the higher base that has been
established after these years of sustained expansion. Gas into LNG now
accounts for broadly 10% of major oil production and will rise to nearer 15%
by 2020 based on current approved projects. With demand clearly exceeding
supply through 2017, we expect continued oil index pricing, despite all the
questions and pressures that global energy shifts elsewhere, notably the US
shale gas revolution, have exerted. At Gorgon, for example, Chevron continues
to sign long term, closely oil indexed take or pay natgas contracts for start up
in 2014 and beyond: the market is structurally locking in long term oil
indexation as the generations of projects roll on, and the location shifts with
perceived potential – realised (Papua New Guinea), lost (Venezuela, Nigeria)
and emerging (East Africa, US). Market growth will shift significantly towards
emerging China and India, and combined with faltering supply from founder
projects we see the need for at least 190mtpa of incremental supply over and
above that in construction. Best positioned for near and long term trends are
BG and Shell, with the greatest rate of positive change: Chevron.
Silvio Micheloto, CFA
Research Analyst
(+44) 20 754-73636
[email protected]
David T. Clark, CFA
Research Analyst
(+1) 212 250-8163
[email protected]
Research Analyst
(+1) 212 250-1653
[email protected]
Winnie Nip
Research Associate
(+1) 212 250-8529
[email protected]
Companies Featured
Chevron (CVX.N),USD117.14
ExxonMobil (XOM.N),USD91.91
ConocoPhillips (COP.N),USD58.30
BG Group (BG.L),GBP1,291.00
Royal Dutch Shell Plc
(RDSb.L),GBP2,319.50
Buy
Hold
Hold
Buy
Buy
Chevron’s Gorgon project remains a monster far from being tamed
The company will host a field trip to the North West Shelf for major investors
and analysts in the last week of September, yet will still be unable to confirm a
final cost estimate on what, at around $50bn, possibly $60bn of capex, is one
of the largest private projects ever undertaken in global history. In fact, we
cannot think of a larger project; the Three Gorges Dam cost around $23bn
(officially), and was not privately financed; nor was Boston’s Big Dig, including
all interest costs, costing around $22bn. In this note we re-iterate our view that
despite the costs, Chevron (Buy $130 target price) stock discounts the risk and
under-values the long term cashflows that will be generated by their literally
enormous Australian gas position, of around 22.2 tcf of gross 2P reserves.
Other key ideas: BG (Buy 1700p) which in our view has stolen a march on its
peers at Sabine Pass and whose forward options look well placed on the cost
curve. With 40% of its value and near 30% of its production LNG related, it is
the outstanding LNG play, in our view. Shell’s (Buy 2475p) unparalleled supply
options combined with its relationships (not least with CNPC) look good. Most
positive rate of change, Chevron. Risks above all are Asian demand, notably
from pandemic or war.
________________________________________________________________________________________________________________
All prices are those current at the end of the previous trading session unless otherwise indicated. Prices are sourced
from local exchanges via Reuters, Bloomberg and other vendors. Data is sourced from Deutsche Bank and subject
companies. Deutsche Bank does and seeks to do business with companies covered in its research reports. Thus,
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. DISCLOSURES AND
ANALYST CERTIFICATIONS ARE LOCATED IN APPENDIX 1. MICA(P) 072/04/2012.
17 September 2012
Integrated Oil
Global LNG
Table Of Contents
Global LNG and Gorgon .................................................................. 3
The $60bn behemoth project of the $225bn company? ......................................................... 3
Chevron and Gorgon ........................................................................ 4
What is Gorgon – specifics ..................................................................................................... 5
History of Australian LNG and Gorgon .................................................................................... 6
North West Shelf LNG ............................................................................................................ 7
Gorgon exploration, reserves, and participation ..................................................................... 9
Gorgon development, contracts, pricing and production ...................................................... 10
Gorgon capex and costs; value and IRR ............................................................................... 12
Wheatstone LNG .................................................................................................................. 16
Impact on Chevron’s Volumes and Cashflow ....................................................................... 17
Gorgon and Global LNG ................................................................ 23
LNG - Key to the rebuild at Big Oil ........................................................................................ 23
Underlying growth augmented by new demand centres ..................................................... 25
LNG supply to 2025 – many horses but several will fall ....................................................... 30
US exports – what should we expect? ................................................................................. 35
US LNG exports – the chance for the arbitrageur to rejuvenate ........................................... 38
Where to price - Oil linkage to remain but with a slice of Hub? ............................................ 40
An attractive end market offering strong growth potential ................................................... 41
The Companies: Overview ............................................................ 44
Comparing and contrasting the LNG majors – 2017 vs. 2012 .............................................. 44
Comparing and contrasting the LNG majors – Side by Side ................................................. 45
Chevron: From nowhere to industry major ........................................................................... 46
ExxonMobil: The ultimate Qatari base load .......................................................................... 48
ConocoPhillips ...................................................................................................................... 50
BG: Building out upstream; rejuvenating downstream ......................................................... 52
BP: Fallen behind .................................................................................................................. 54
Shell: Cash flow to near double by 2017 .............................................................................. 56
Total SA: Strong and steady growth but options look challenged ........................................ 58
Appendix A: US exports and European gas ................................. 60
Appendix B: US supplier economics ............................................ 63
Sabine Pass - what does it tell us about capacity charge flex? ............................................. 63
Appendix C: Shipping in brief ....................................................... 65
Those relying on short term charters risk losing upside ....................................................... 65
Appendix D: Portfolios & options ................................................. 66
Chevron – Staggering growth to come but very narrow focus ............................................. 66
Exxon – Building out from its Qatar dominated base ............................................................ 67
ConocoPhillips ...................................................................................................................... 68
BG Group – Expanding position, east facing options ............................................................ 69
Shell – Footprint dwarfs peers, as do options ...................................................................... 70
BP – Broad legacy position but limited growth potential ...................................................... 71
Total – A decade of reinforcement now slows. Difficult options .......................................... 72
Sector Investment Thesis .............................................................. 73
Outlook ................................................................................................................................. 73
Valuation ............................................................................................................................... 73
Risks ..................................................................................................................................... 73
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17 September 2012
Integrated Oil
Global LNG
Global LNG and Gorgon
The $60bn behemoth project of the $225bn company?
Since oil peaked in June 2008, the S&P500 is up 16%, the NASDAQ up 42%, E&P
stocks & the OSX are down ~30%. Only four major oils show positive performance
since then: Chevron, ExxonMobil, Shell and BG. If you were asked in a pub quiz for oil
analysts what the common link between the four stocks was, you might just say "LNG".
Always considered a tough theme to get direct exposure to, in this note we preview
Chevron's Gorgon field trip and re-present the global LNG note recently published by
Lucas Herrmann on our European Oil Team. We have written a global LNG note every
two years since 1998. The song remains the same: 7% growth in supply & demand to
the forecast end.
Figure 1: Price Performance YTD vs Since oil peaked in 2008
40%
Refiners Total
(75%,62%)
VLO( 6%,60%)
30%
PXD
ECA
SU
20%
OSX
10%
YTD
PBR
NatGas
S&P 500
NASDAQ
RRC
CVX
XOM
MRO
NBL
APC
RDS
OXY
COP
TOT
STL
BP
NFX
CHK
-10%
DVN
MUR APA
HES
WTI
EOG
SWN
E&P Total
0%
BG
CNQ
UPL
-20%
-30%
-40%
-100%
SLB
ENI
REP
-80%
-60%
-40%
-20%
0%
20%
40%
60%
Since Oil Peaked (2008)
Source: Deutsche Bank, FactSet
We assert that demand strength will pressure prices to remain oil-indexed; we see a
good market for US LNG exports but by no means an unlimited one, and we see key
winners much in the way that we see the market: the song remains the same. BG,
Shell, Chevron with a better rate of change than ExxonMobil. We do not cover
Cheniere, but all credit to a company that was first mover in the US LNG import boom –
that never happened – to be the first mover in the US LNG export boom. Revolutions do
happen. Logical planning can prove to be totally wrong-headed when they do occur.
Speed of action and ability to embrace change are the keys. Why do we think refining
stocks can still work? Because investors continue to look to the pre-revolution past, not
the new future, of cheap US energy in such abundance, that exports are the theme.
Page 3
17 September 2012
Integrated Oil
Global LNG
Chevron and Gorgon
We believe that no company has a relatively larger long term Brent oil-levered resource
potential than Chevron. Within that portfolio, the largest undeveloped potential has
been in North West Australia, where exploration success that dates back to the 1960s
has, over time, become a massive undeveloped gas base, relatively proximate to the
energy-short markets of Asia.
Figure 2: 2P Reserves: total gas & Australia gas vs. total oil+gas
250,000
60%
CVX gas makes up 43% of total oil & gas reserves
50%
200,000
40%
150,000
Australia gas alone is 18% of total oil & gas reserves
30%
100,000
20%
50,000
10%
0
0%
Total O&G 2P, bcfe (LHS)
Total Gas % of Total O&G 2P (RHS)
Australia* Gas % of Total O&G 2P (RHS)
Source: Wood Mackenzie, Deutsche Bank
However, the timeline between discovery and development has been immense. Gas
was first discovered in the Gorgon area of North West Australia – a huge gas resource
base - in 1982. The development effort has essentially been underway since then, but
intensely since the mid-1990s.
Now, finally, Gorgon is reaching full development. There remain major challenges, but
the first and foremost has been met, that of gas contracts. Up-front capital expenditure
is so enormous for these developments that gas must be sold first, in huge quantities.
That has been the biggest challenge. The project is well contracted based on long-term
oil-indexed basis, to high quality North Asian offtakers.
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17 September 2012
Integrated Oil
Global LNG
The next challenge is currently underway, that of development. Because of its remote
location offshore, its high CO2 content, and the development undertaking on
environmentally sensitive Barrow Island, the project needs immense scale to generate a
return. Adding to major issues, high degrees of unionization, competition for labour,
typhoons, and technical challenges all present a high degree of risk to development on
what has become, at upwards of $50bn of capital expenditure just in this development
phase alone, one of the largest private projects ever developed globally.
In this note we highlight the outstanding attractiveness of the long term LNG market in
terms of growth, supply shortage, and cashflow generation quality. We believe that for
the long-term investor, Gorgon will be an outstanding project, particularly the investor
that can time entry into the stock as the risked price of Gorgon in CVX most underestimates the turn to cashflow delivery.
But the reality for active investors is that the current position of the project, at its point
of maximum spend and zero revenue, is immensely risky. With this scale of capex,
delays - which even in the construction phase - have already cost an estimated six
months because of cyclones. The problem with the Chevron Gorgon trip is that
company won’t, because it can’t, provide a final cost estimate. Until the market can
believe that the sum of all risk is more than discounted in the stock, this project will be
an overhang, not an under-pinning. The switch between the two will almost certainly
occur over the next three years; we rate Chevron a BUY based on the view that its
multiple and NAV discount reflect the risk. But like the market, we hope for conviction,
possibly increased on this trip. In reality, true conviction will only come when it is too
late to buy at the low, when first gas delivery begins.
What is Gorgon – specifics
Gorgon, offshore northwest Australia, is a vast gas field being developed to feed a
15.6mtpa LNG project. The project is in fact developing two fields in water depths of
between 138-1,350 meters: the Gorgon and Io/Jansz gas/condensate fields in the
Carnarvon Basin. Each contains around 20 TCF of proven and probable reserves.
With vast quantities of gas established, initial upstream development will involve the
drilling and completion of 18 subsea wells, which will be tied back to three 5.2mtpa
LNG processing trains, with associated storage and offloading facilities, on the eastern
coast of Barrow Island, a Class A nature reserve.
A fourth train is expected to enter Front End Engineering and Design (FEED) by yearend 2012. To comply with the stringent environmental controls, Chevron will sequester
some 80% of the carbon dioxide produced (13.6% of the gas content from Gorgon field)
into the Dupuy saline reservoir.
Besides exporting LNG, the project will also supply gas to customers in West Australia
through a 95km pipeline. The first 150 TJ/d (142mmcf/d) train of the domestic gas plant
is expected to start production in 2015, with the second 150 TJ/d train starting up in
2020.
The Gorgon Project achieved Final Investment Decision (FID) in September 2009 and so
far, a severe cyclone season in 2010-11 has delayed progress on Barrow Island by
about six months. We are now two years away from first LNG delivery, expected in late
2014.
Page 5
17 September 2012
Integrated Oil
Global LNG
Figure 3: CVX Australia overview
Source: Chevron
History of Australian LNG and Gorgon
Chevron (and Texaco) trace their Australian roots to the very start of the Australian oil
and gas industry. West Australian Petroleum (WAPET) was the pioneer oil and gas
company in Australia, formed in March 1952 as a joint venture between Caltex, itself a
JV between Chevron and Texaco formed to market their Saudi oil in Asia, and Aussie
pioneer Ampol. The company made Australia's first flowing oil discovery in 1953 at
Rough Range on the North West Cape; an area first considered because of its
topographical similarity to Saudi Arabia. In 1964 WAPET discovered the first
commercial natural gas field at Dongara in the Perth Basin Gas that has been flowing
since. The company was joined by Shell in 1964 and shortly after, and made their major
find, on Barrow Island.
Despite an expectation of likely oil deposits, Barrow Island had had Government bans
on drilling and exploration due to the 1952 atomic bomb testing on the nearby
Montebello Islands. The bans were lifted in 1953 and WAPET discovery "Barrow-1"
flowed with significant heavy crude and commercial production in 1967. As a result of
the success at Barrow Island, extensive off-shore exploration took place in the
Carnarvon Basin during the late 1960s and 1970s. WAPET discovered a significant gas
deposit at West Tryal Rocks, northwest of Barrow Island in 1973, and in 1980 the
Gorgon gas deposit.
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17 September 2012
Integrated Oil
Global LNG
North West Shelf LNG
The original North West Shelf permit, WA-1-P, was awarded to Woodside and MidEastern Oil in 1963. Lacking financial firepower, they in turn farmed out to a group
comprised of Shell, BP, Burmah, and Chevron. After major discoveries at North Rankin
and Goodwyn ownership was rationalised, with BHP replacing Burmah. Eventually,
when gas contracts were eventually signed in 1980, some 17 years after first discovery,
ownership settled as a 16.67% share each for operator Woodside, part Woodside
owner Shell, BP, Chevron, BHP and Japanese industrial giants Mitsubishi/Mitsui.
Having started production in 1984, the mega project gradually increased to its fifth train
sanctioned in 2002, when Chinese major and gas offtaker CNOOC was brought in to the
JV. It has now reached plateau production of around 120kb/d of liquids and some
3bcf/d of natgas (500kboe/d).
Figure 4: Map of North West Shelf Gas Project in the Carnarvon Basin
CARNARVON BASIN
NWS Gas Project
Goodwyn-North Rankin pipeline
IO/JANSZ
GOODWYN
NORTH
RANKIN
NWS Gas Project
GORGON
Wheatstone-Ashburton
North pipeline
Pluto LNG Plant
Gorgon LNG plant
(under construction)
BARROW
ISLAND
Devil Creek Gas Plant
MACEDON
Wheatstone LNG Plant
(under construction)
Western Australia
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17 September 2012
Integrated Oil
Global LNG
As such, the project would form a classic “old school” LNG project, as well as a
Western Australia domestic gas supply project. Capital costs were high, not least
because the Japanese utility buyers were primarily interested in security of supply in the
wake of the oil crises of the 1970s/1980, contracts were very long term and oil indexed,
with limited flexibility, essentially representing the sale of multiple tcfs of gas over 20year terms. Some 16 tcf has been produced and sold, and we are still only somewhere
near halfway through ultimate sales, estimated around 35 tcf in total. Oil industry
history says that with time, decline rates will be mitigated by in-fill drilling and
technology advances for many years to come – original 20 year contracts were for life
of project and have been renewed. That “squeezing of the sponge” is very high return
activity.
Those are the positives. However with Japanese utilities selling gas domestically at over
$20 per mmbtu, primarily interested in security of supply, cost control was weak
especially given that multiple equal partners gave an unwieldy management structure.
That clearly added delays and costs. The project is widely seen, certainly in retrospect,
as “gold-plated”, and full life returns were very poor, certainly compared to original
estimates and subsequent performance. For example, cumulative cashflows suggest
that from first production in 1984, the project only went cashflow positive around 2004,
some 20 years later. In that 20-year period, the stock price performance of the major
oils, many directly involved in the project, was basically horrible. That should be the
nightmare that haunts Chevron investors.
Figure 5: North West Shelf cumulative cash flow vs. production profile (gross)
700
100
80
560
Cashflow turned positive in 2004 20 yrs after production began
60
420
40
280
20
140
0
-20
1980
1982
1984
1986
1988
1990
1992
1994
1996
1998
2000
2002
2004
2006
2008
2010
2012
2014
2016
2018
2020
2022
2024
2026
2028
2030
2032
2034
0
-280
-40
-60
-140
Cumulative Cash Flow $B (LHS)
Total Production kboe/d (RHS)
-420
Source: Wood Mackenzie
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17 September 2012
Integrated Oil
Global LNG
Gorgon exploration, reserves, and participation
After some success in drilling around the Tryal Rocks area of the Rankin Platform in the
1970s, Gorgon 1 was spudded in 1980. It discovered “massive, fluvio-deltaic sandstone
sequences within a gas column of 409 metres (1,342 ft)”. The Gorgon structure is now
viewed as a “north-south orientated elongate horst”, around 35km x 5km, the reservoir
a sequence of north-dipping truncated feeder, the Mungaroo sands. In 2000 the Jansz-1
well and subsequent drilling was combined with the discovery in 2001 of Io-1 into the
Io-Jansz gas condensate field that forms the additional major reservoir for Gorgon
project supply. Drilling continues, and continues to find vast quantities of gas.
Figure 6: CVX Australia Exploration
Source: Chevron
*Recoverable resources as defined in the Supplement to the Annual Report and available at Chevron.com
Gas composition is an issue. Notably, gas from the Gorgon field is high in carbon
dioxide (14%), offset by the much lower CO2 content of Io-Jansz (<2%).
The reservoir was originally explored by the WAPET consortium of Chevron, Texaco,
Shell, and Ampolex, subsequently bought by Mobil and in turn ExxonMobil. Over time,
given the scale of the reservoir and number of blocks, BP, Woodside and Santos have
all been involved in what became a complex participation and unitization process in
which Chevron became dominant, not least by merging with Texaco in 2001.
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17 September 2012
Integrated Oil
Global LNG
In 2003 Chevron announced a proposed development on long term oil-producing Class
A nature reserve Barrow Island. The complication of the nature reserve, which is a
micro-environment that is required to have everything taken on to it scrubbed and
shrink wrapped, is offset by the island’s depleted reservoirs that allow for CO2 reinjection to meet Australia’s CO2 limitations. This will be the largest sequestration
project in the world, pumping some 80% of produced CO2 into the Dupuy saline
reservoir. Net peak production from the Gorgon project is expected to reach ~1.23bcf/d
of natural gas and ~9.5kb/d of condensate, implying some 100mmcf/d of CO2
produced.
In 2004, Gorgon became part of the worldwide Royal Dutch/Shell reserves scandal,
when it was revealed that Shell had booked reserves from Gorgon in its proven SEC
reserves category as early as 1997. It was widely seen as the most egregious element
of the 20% over-statement of reserves that was admitted in early 2004, and contrasted
with the fact that neither Chevron nor ExxonMobil had booked any Gorgon reserves
even by 2004; standard interpretation of SEC rules would limit bookings to the year of
final investment decision.
In 2005, Chevron, Shell and ExxonMobil set a framework agreement to unitise and
prioritise gas field developments for the major LNG development, with front end
engineering and design (FEED) by Kellogg Brown and Root, aiming for final investment
decision (FID) by 2007. Cost escalation was rampant in the industry as oil prices
boomed into 2008, and the decision was made to expand the project from 10Mt to
15Mt of LNG per year to improve economics. FID was achieved in September 2009 with
estimated cost for the first phase of development of A$43bn (US$37bn). Capacity has
since been expanded to 15.6Mt per year. The key cost number, however, remains
uncertain, other than it will be higher than at FID.
Gorgon development, contracts, pricing and production
Originally LNG was marketed by the Gorgon JV as a group in 2003, with a letter of
intent signed with CNOOC for 4mtpa and MoUs with Chevron Overseas Petroleum for
2mtpa and Shell Eastern for 2.5mtpa to supply to North America. However, after
CNOOC pulled out of contract negotiations in 2005, the Gorgon partners began
marketing their volumes separately. In the next two years, preliminary non-definitive
agreements in the form of heads of agreement (HOAs) were being made, but following
the postponement of the project in 2007, all renegotiated and subsequent contracts
made were definitive sale and purchase agreements (SPAs).
Below, we lay out the long-term SPAs signed by Chevron and the other participants as
of September 2012, which represent renegotiated agreements following the
postponement of the project in 2007. Many of these SPAs come with an optional
extension, although the company has not publicly commented on that option.
With total capacity now at 15.6mtpa, Chevron’s 47.3% share amounts to 7.384mtpa in
offtake, meaning the company currently has 2.369mtpa (32%) of uncontracted LNG.
Page 10
17 September 2012
Integrated Oil
Global LNG
Figure 7: Gorgon LNG Purchase Agreements
Buyer
Agreement Type
Duration
Annual Delivery
(mtpa)
Sales Point
CVX’s long-term LNG sales
Chubu Electric
Sales & Purchase Agreement
2014-2039 (25 yr)
1.44
FOB
Osaka Gas
2014-2039 (25 yr)
1.375
FOB
Tokyo Gas
2014-2039 (25 yr)
1.1
FOB
GS Caltex*
2014-2034 (up to 20 yr)
0.5
DES
Kyushu Electric
2014-2034 (up to 20 yr)
0.3
FOB
Nippon Oil
2014-2029 (15 yr)
0.3
DES
Other participants’ LNG sales
BP
2014-2031
0.50
FOB
PetroChina
2014-2034
2.25
DES
PetroChina
2014-2034
2.00
FOB
Petronet LNG
2014-2034
1.50
FOB
Shell
2014-2039
1.25
DES
Source: Chevron, Wood Mackenzie
* A portion of the GS Caltex volumes would come from Chevron’s portfolio outside of Gorgon
In addition to the SPAs with Chevron, Osaka Gas, Tokyo Gas and Chubu Electric will
also have the right to offtake their own volumes of equity gas (combined total of
0.421mtpa) as equity participants.
Figure 8: Gorgon LNG equity participants
Tokyo Gas, 1.0%
Chubu Electric, 0.4%
Osaka Gas, 1.3%
RDS, 25.0%
CVX, operator,
47.3%
XOM, 25.0%
Source: Wood Mackenzie, Company data
Chevron believes that Asian gas prices will retain their oil price linkage for at least a
decade if not longer. There is good reason for this, namely they are signing 20-year long
term LNG contracts based on that structure, even currently. The security of supply
agenda is the driving force of the Asian LNG market, as it has always been. The buyers
are conservative and hydrocarbon short, there is no Asian spot market for natgas and is
unlikely to be. Henry Hub prices may be low but have been at $14/mmbtu within the
last five years. Risk aversion, perversely, drives oil price linkage. We do believe that
Chinese unconventional gas has the potential to revolutionise Asian gas price
structuring, but this is probably at least a decade away, and in the meantime, Chinese
natgas imports are substituting oil, again speaking to a powerful oil-gas linkage.
Page 11
17 September 2012
Integrated Oil
Global LNG
Gorgon capex and costs; value and IRR
The cost of Gorgon is enormous, but not outside LNG industry norms during this period
of intense Australian (ie high cost) developments. The issue has been a slowdown in
Middle Eastern developments, led by Qatar, and struggles in former low cost provinces
such as Indonesia and Malaysia with progressing new projects. Other potentially low
cost opportunities have become no cost because of lack of final investment decision,
such as in Nigeria. As we argue later in this note, the likelihood is that Australia finds
itself priced out of the greenfield market for LNG as a plethora of new supply options,
notably in North America and East Africa, enter the market.
For now Gorgon is in line with a high cost development phase for LNG, which makes it
all the more imperative for the project to be completed on time and within reasonable
distance of original budget ($37bn).
Figure 9: Cost Inflation in the Industry - $ per tonne of liquefaction capacity
high - Pluto,
$2,081
2,200
2,000
$/tonne (real 2012 terms)
1,800
1,600
Gorgon
1,400
1,200
1,000
NLNG Seven Plus,
$936
800
600
Cheniere Sabine
Pass, $556
400
200
1965
low - Atlantic LNG
2 & 3: $208
1970
1975
1980
1985
1990
1995
2000
2005
2010
2015
2020
First Year Capex Incurred
Although the project is broadly on schedule, even after major typhoon interruption in
2011, we have highlighted that all projects are generally on time and on budget until
they are 50% complete. That is essentially where Gorgon is now. As highlighted in the
slides below, progress continues, with a further more specific update surely to be given
on the trip.
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17 September 2012
Integrated Oil
Global LNG
Figure 10: Gorgon Project Update (2Q12 call)
Figure 11: Gorgon Project Cost Review (2Q12 call)
Source: Chevron
Source: Chevron
The company says that reports of delays and schedule slippage are the normal course
of business for a project of this size, and that the “critical path” elements have been
totally met, with the offshore loading facility and site preparation now complete. Thus
begins the process of shipping modules to the site and “knitting together” the various
pieces. This is the critical phase for cost.
There are two elements to the cost over-run potential.

First, the known issue of Australian dollar (A$) cost related to foreign exchange.
Essentially the project is 50% A$ sensitive, and was given final investment
decision (FID) in 2009 when the A$ was at 0.7 to the US$. Project revenues are
in US$. A$ costs are therefore crucial, and the A$ has appreciated 30% since
FID assumptions were made. That would imply that the $20bn of project costs
that are A$ sensitive have increased 30%, implying a US$6bn increase in
project costs. That much is more or less known.

Important note: the inflation in costs here related to A$ will tend to positively
correlate to an appreciation in the price of oil. Given the project is oil price
indexed, the A$ appreciation is largely offset by the 46% increase in crude
prices that have also occurred. On balance, it seems that the admittedly
modest 12% IRR of the project is so far intact. Equally it implies that future
strength in the A$ will be basically hedged by the likely equivalent move in oil
prices. In fact, DB forecasts a weakening A$ and a higher oil price
environment, implying an uplift for project economics.
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17 September 2012
Integrated Oil
Global LNG
Figure 12: AUD/USD with DB forecast vs. Brent historical and strip
Brent
Oct-13
Jul-13
Apr-13
Jan-13
Oct-12
Jul-12
Apr-12
0.60
Jan-12
$20
Oct-11
0.70
Jul-11
$40
Apr-11
0.80
Jan-11
$60
Jul-10
0.90
Oct-10
$80
Apr-10
1.00
Jan-10
$100
Oct-09
1.10
Jul-09
$120
Jan-09
1.20
Apr-09
$140
AUD/USD (rhs)
Source: Bloomberg Finance LP, Deutsche Bank
What Chevron say they don’t know, and can’t say, is what will happen to the second
major uncertainty over cost, which is the labour productivity of the construction process
on Barrow Island. Labour tightness and high degrees of unionisation in Australia cause
concern. Three major projects are underway on the East side of Australia for coal bed
methane to LNG, pressuring the skilled workforce availability. Chevron point out that
there are differences between their project and those on cost, particularly up to 6,000
wells for coal bed methane vs just 18 for Gorgon. Equally the simultaneous progression
of those projects creates local pressure that may be less intense on the North West
Shelf, as Gorgon is the first in a series of projects; however the remoteness of the North
West shelf makes this assertion questionable. The company does have the ability to
ship in migrant labour if that labour is not available in Australia, albeit using migrants
while paying Australian wages. Chevron highlights that reports of delays or rescheduling of elements of the Gorgon project so far have been normal project
management process, and that critical path has been met. So far, the wildest number
we have heard is a 50% ($20bn) inflation in costs, to US$60bn. That would be a large
enough inflation to explain Chevron’s enormous $20bn cash pile, which they state is
being held for… cost inflation. The company highlights that the mid-year $20/bbl down
move in Brent prices cost $6bn in annual cashflow.
Overall, Gorgon was never a spectacular return project, given it has spectacular costs;
even on initial estimates of around $40bn of costs, using a $70/bbl Brent assumption, it
was just shy of an 11% IRR. Our view is that a final project cost of $50bn would be in
line with negative expectations, $60bn would be an outright negative for the cost and
would imply well below 10% IRR.
A concern with Chevron’s trip is that a final cost estimate will still not be ready. That
has been promised for year end. The net result is that we are left to run scenarios. On
balance, we would say that in the current oil price environment, even a $60bn project
does not have an awful return, nor even with a two year delay. That would take returns
down to around 7%, or the cost capital for Chevron if it didn’t carry such an enormous
cash pile. We believe the project was sanctioned on an assumption of around $70/bbl
oil. Although the oil price environment looks much more supportive than that, we
highlight that Australian $ inflation has eaten into the oil market support. Overall,
project economics look stable at around low double digit returns.
Page 14
17 September 2012
Integrated Oil
Global LNG
Figure 13: IRR at different oil prices with $40B initial cost
17%
Figure 14: IRR at different project costs with $70/bbl oil
12%
$40B initial development costs
$70 long term oil price
10%
15%
8%
13%
6%
11%
4%
9%
2%
7%
0%
$70
No delay
$100
1 year delay
$120
$40bn
2 year delay
$50bn
No delay
$60bn
1 year delay
2 year delay
Source: Deutsche Bank
15%
15%
13%
10%
11%
5%
9%
7%
0%
$70
No delay
$100
1 year delay
$120
$40bn
$50bn
No delay
2 year delay
1 year delay
$60bn
2 year delay
14%
13%
12%
11%
10%
9%
8%
7%
20%
15%
10%
5%
0%
$70
No delay
$100
1 year delay
$40bn
$120
2 year delay
No delay
$50bn
1 year delay
$60bn
2 year delay
A much higher return fourth train is likely to enter FEED at Gorgon this year, with FID
expected in 2014, and Wheatstone is designed to go to six trains and beyond in due
course, beyond its initial two train start up. The facility is designed to take gas from
other companies with major discoveries in this prolific and politically stable wilderness.
Page 15
17 September 2012
Integrated Oil
Global LNG
Wheatstone LNG
The Chevron Australia LNG story does not end with Gorgon. Wheatstone, located at
Ashburton North on the Pilbara coastline of Western Australia, is a two-train, 8.9mmtpa
LNG project which will source gas from the Wheatstone, Iago, Julimar and Brunello gas
fields, also in the Carnarvon Basin. The upstream development will involve 35 subsea
wells tied back to a central processing platform, from which the gas will be transported
to the LNG plant via a 225km export pipeline. There will also be a 200TJ/d (184mmcf/d)
domestic gas plant that allows the Wheatstone project to supply gas to Australia via a
spurline to the Dampier to Bunbury Gas Pipeline.
The project was FID’d in September 2011 and first LNG is expected in mid-2016. As
highlighted, the project is being optimized for a tripling of capacity in due course, and to
run trailing to Gorgon so that labour and logistics can be fed from Gorgon into
Wheatstone’s two year lag.
Figure 19: Wheatstone LNG location & equity participants
Kyushu
Electric,
Shell, 6.40%
1.46%
KUFPEC,
7.00%
Apache,
13.00%
CVX,
operator,
72.14%
Source: Chevron, Wood Mackenzie
Page 16
17 September 2012
Integrated Oil
Global LNG
Impact on Chevron’s Volumes and Cashflow
As illustrated below, the impact of Gorgon and Wheatstone LNG, alongside two major
Gulf of Mexico start-ups, is dramatic for 2015 volumes. And the growth from 2015
onwards is strong.
Figure 20: Incremental Volumes from CVX’s Four Major Startups
YoY Increment (kboe/d)
150
120
Big Foot
90
Jack/St. Malo
Wheatstone
60
Gorgon
30
0
2012
2013
2014
2015
2016
Source: Deutsche Bank, Chevron, Wood Mackenzie
In theory the incremental volumes provide a remarkable boost to Chevron’s volumes,
essentially providing the break-out, finally, to the oft-promised 3mboe/d+ range.
Figure 21: CVX Volumes vs Guidance
3,400
3,200
000 boe/d
3,000
2,800
2,600
2,400
2,200
CVX History + DB forecast
Growth Target 2003
Growth Target 2007
Growth Target 2010
Growth Target 2001
Growth Target 2004
Growth Target 2008
Growth Target 2011
2017e
2016e
2015e
2014e
2013e
2012e
2011
2010
2009
2008
2007
2006
2005
2004
2003
2002
2001
2000
1999
2,000
Growth Target 2002
Growth Target 2006
Growth Target 2009
Growth Target 2012
Source: Deutsche Bank, Chevron
Page 17
17 September 2012
Integrated Oil
Global LNG
Figure 22: Volume growth 2013e
16.0%
14.0%
12.0%
10.0%
8.0%
6.0%
4.0%
CVX.N
XOM.N
HES.N
MUR.N
RDSa.L
TOTF.PA
MRO.N
COP.N
OXY.N
-4.0%
CNQ.TO
-2.0%
SU.TO
0.0%
BP.L
2.0%
-6.0%
2013/2012
2012/2011
2013/2012 Average
Source: Deutsche Bank, Company data
Until 2015, volume growth is weak, and for the next year, worst in class. Even allowing
for 2014 volume growth into 2015, in fact 2016 is the pivot point for annual free
cashflow contribution from the Australian LNG projects. The frustration for all who
follow Chevron is the knowledge that at some time over the period since we have
recommended the stock, there will be an optimal time to buy the future growth and free
cash flow expansion. Now, as we comment in 2012, it seems early to buy a 2015 story.
In fact history says that 2015 is the time to buy a 2015 story in big oil, as their track
record of delivery has been so challenged, as evidenced by Chevron’s volume
performance vs volume targets illustrated above.
Figure 23: Free Cashflow Contribution from CVX’s Projects
50
40
$B
30
20
10
0
(10)
2012
Australia Conc LNG
2013
2014
Kazakhstan Conc
2015
US Conc West Coast
2016
2017
Nigeria PSC
2018
Thailand Conc
2019
2020
US Conc Gulf of MexicoDee
Other
*Free Cash Flow = Revenues - Operating Costs - Capital Costs - Royalties - Govt. Take
Source: Deutsche Bank, Wood Mackenzie
Page 18
17 September 2012
Integrated Oil
Global LNG
Cumulative cashflow from the Australian LNG projects is not expected to turn positive
until at least a dozen years after production startup. This is reminiscent of the 20 year
lag experienced by North West Shelf LNG. The positive news for investors on Gorgon
and Wheatstone is that Chevron is the operator and by far the largest equity participant
in both Gorgon and Wheatstone, giving it better control over the projects’ development.
Figure 24: Gorgon cumulative cashflow vs. production
profile (gross)
20
FID - Sep 2009
10
Figure 25: Wheatstone cumulative cashflow vs.
production profile (gross)
500
10
300
250
5
150
0
0
0
2039
2037
2035
2033
2031
2029
2027
2025
2023
2021
2019
2017
2015
2013
2011
2009
2007
0
-10
-250
-20
-500
-30
-750
-5
-150
-10
-300
-15
Cashflow expected to turn positive
in 2027 - 13 yrs after first LNG
-40
-50
-20
-1000
-450
Cashflow expected to turn positive
in 2029 - 13 yrs after first LNG
-600
-25
-750
-30
-1250
-900
As we have highlighted, the projects dramatically alter Chevron’s global LNG
positioning, catapulting it from a bit actor to a global leader over the next five years.
Figure 26: Production from LNG projects, 2012 vs 2017e
2012
kboe/d
700.0
2017
600.0
500.0
400.0
300.0
200.0
100.0
0.0
BG
BP
Shell
Total
Exxon
Chevron
ENI
Statoil
Source: Deutsche Bank estimates
Page 19
17 September 2012
Integrated Oil
Global LNG
When forward margins are considered, the company believes that the same 30% Brent
leverage that Chevron currently enjoys, now best in class, will hold post 2017. That is,
cash margins for Chevron currently represent around 30% of the Brent price. When
they look forward to 2017, they believe the same 30% flow through will be in place.
Again, over that period the company moves from 70-30 oil gas to 60-40 oil-gas, yet the
portfolio will remain at around 80% oil linked in terms of pricing, owing to the direct oil
linkage of the two massive LNG projects.
Figure 27: CVX Net Income per bbl produced
High Low Range
Chevron
WTI (RHS)
Q2 12
Q4 11
Q2 11
Q4 10
Q2 10
Q4 09
Q2 09
-$10
Q4 08
$20
Q2 08
$0
Q4 07
$40
Q2 07
$10
Q4 06
$60
Q2 06
$20
Q4 05
$80
Q2 05
$30
Q4 04
$100
Q2 04
$40
Q4 03
$120
Q2 03
$50
Q4 02
$140
Q2 02
$60
$0
Source: Deutsche Bank, Company data
Alongside Chevron’s best in class profitability is a level of return that stands out, when
combined with its cashflow multiple. There are overhangs on Chevron, but it seems too
cheap relative to its return, to us. That is the essence of our current BUY.
Figure 28: EV/DACF vs. ROCE, 2012e
10.0
PXD.N
RRC
BG.L
9.0
SWN.N
EV/DACF
8.0
7.0
XOM.N
ECA.TO
EOG.N
CHK.N
REP.MC DVN.N
NFX.N
APC.N
6.0
5.0
BP.L
UPL.N
OXY.N
COP.N
TOTF.PA
RDSb.L
HES.N
SU.TO
MRO.N
APA.N
ENI.MI
STL.OL
CNQ.TO
4.0
3.0
0.0%
NBL.N
CVX.N
MUR.N
2.5%
5.0%
7.5%
10.0%
12.5%
15.0%
17.5%
20.0%
22.5%
ROCE
Page 20
17 September 2012
Integrated Oil
Global LNG
For now, investors can comfort themselves in being “paid to wait” with Chevron’s
relatively attractive dividend. ConocoPhillips offers more headline yield, but a far less
attractive long term asset base and growth potential, as we see it.
Figure 29: Cash returns 2013e
7.0%
6.0%
5.0%
4.0%
3.0%
2.0%
Dividend Yield
HES.N
CNQ.TO
SU.TO
MRO.N
XOM.N
OXY.N
MUR.N
COP.N
RDSa.L
BP.L
-1.0%
TOTF.PA
0.0%
CVX.N
1.0%
Buyback Yield
For long term investors, we believe our NAV is conservative. Notably, we heavily risk
Australia owing to the potential for cost inflation. As Australia is de-risked, some
$10/share of implied upside to our NAV is released. Again, we do not see a better long
term asset base in global oil.
Figure 30: Share Price Discount to NAV
30%
20%
10%
CVX's discount to NAV too steep
0%
-10%
-20%
-30%
-40%
RDSa.L
BP.L
COP.N
TOTF.PA
MUR.N
MRO.N
OXY.N
CNQ.TO
CVX.N
HES.N
SU.TO
XOM.N
-50%
Source: Deutsche Bank, Wood Mackenzie, FactSet
Page 21
17 September 2012
Integrated Oil
Global LNG
Figure 31: CVX NAV
Upstream
Angola
Argentina
Australia
Azerbaijan
Bangladesh
Brazil
Canada Newfoundland Labra
Canada Oil Sands
Chad
China
Colombia
Congo Braz
Denmark
Indonesia
Kazakhstan
Myanmar
Netherlands
Nigeria
Norway
Philippines
Saudi Arabia Partitioned
Thailand
Trinidad
United Kingdom
United States Alaska
United States Gulf Coast
United States DW Gulf of Mexico
United States MidContinent
United States Northeast
United States West Coast
United States Permian
United States Rocky Mount
Venezuela Strategic Assoc
Vietnam
Sub-Total
Implied per barrel of booked reserves
Implied PER on 2008-11 avg earnings $ M.
Risked Value
($ Million)
Comment
9,475
2,074
45,814
4,301
1,632
7,403
4,822
7,974
866
3,267
559
2,335
2,360
6,890
20,760
2,138
326
9,964
129
2,127
4,041
12,160
804
5,280
667
1,878
22,674
337
3,692
28,067
3,867
1,410
2,967
686
223,747
$19.8
11,315
$18,336
12.2x
Absolute
Value/
Value
Risked 2 P Absolute 2P Risked 2P
($ Million)
Reserves
Reserves Reserves
18,221
596
1,147
15.9
2,357
95
108
21.9
59,499
3,448
4,478
13.3
5,444
288
364
14.9
2,206
514
695
3.2
8,920
266
321
27.8
5,953
280
345
17.3
8,910
637
712
12.5
1,139
69
91
12.5
3,630
292
324
11.2
643
45
51
12.6
3,033
184
239
12.7
2,458
115
120
20.5
9,440
1,068
1,464
6.4
59,314
1,338
3,823
15.5
2,545
170
202
12.6
340
20
21
16.1
28,467
771
2,203
12.9
158
8
10
16.6
2,390
144
162
14.8
4,449
1,092
1,203
3.7
14,741
927
1,124
13.1
847
214
225
3.8
6,947
325
428
16.2
833
69
86
9.7
2,184
216
251
8.7
34,883
1,209
1,860
18.8
392
46
53
7.4
4,243
675
776
5.5
32,261
1,200
1,379
23.4
4,496
324
376
11.9
1,640
187
217
7.5
8,477
475
1,357
6.2
836
240
293
2.9
342,296
17,546
26,506
12.8
$30.3 /bbl
18.7x
% of
Total EV
3.6%
0.8%
17.5%
1.6%
0.6%
2.8%
1.8%
3.0%
0.3%
1.2%
0.2%
0.9%
0.9%
2.6%
7.9%
0.8%
0.1%
3.8%
0.0%
0.8%
1.5%
4.6%
0.3%
2.0%
0.3%
0.7%
8.7%
0.1%
1.4%
10.7%
1.5%
0.5%
1.1%
0.3%
85.4%
Value
per Share Massive Australian
4.8 position + resource
1.1
23.3
2.2 UCL deal bolstered
0.8 leading Asian position
3.8 ~12% of value
2.5
4.1
0.4
1.7
0.3
1.2 Tengiz is ~11% of total
1.2 upstream value
3.5
10.5
1.1
0.2
5.1
0.1 Tremendous Nigerian
1.1
position
2.1
6.2
0.4
2.7
0.3
1.0
11.5
0.2
1.9
14.3 Lots of resource, but
2.0 surprisingly little
0.7 development value yet
1.5
0.3
113.7
10,603
4.0%
5.4
234,349
89.4%
119.1
1,730
1,695
11,605
1,275
2,460
2,641
21,406
9.8x
0.7%
0.6%
4.4%
0.5%
0.9%
1.0%
8.2%
0.88
0.86
5.90
0.65
1.25
1.34
10.88
1,500
1,500
0.6%
0.6%
0.76
0.76
4,846
32.8x
1.8%
2.46
Total Enterprise Value
Adjusted 2Q12 Net Debt
Value before adjustments
Corporate Expenses
NPV of eventual Ecuador litigation/arbitration liability
Pension Underfunding
Net Asset Value
262,102
-10978
273,080
16,107
2,000
9,152
245,821
100.0%
-4.2%
104.2%
6.1%
0.8%
3.5%
93.8%
133.18
-5.58
138.76
8.18
1.02
4.65
124.91
Market Capitalisation
Premium to NAV
230,747
-6%
12.6x
3P "Possible" Reserves
Upstream Sub-Total
Refining and Marketing
Europe Refining
Europe Marketing
North America Refining
North America Marketing
Asia / Africa Refining
Asia Pacific / Latin America Marketing
Sub-Total
$2,193
Gas, Power, Etc
GS Caltex, Ships etc
Sub-Total
Chemicals
Memo:
Number of Shares in Issue
$148
$19,452
Large resource value
relative to 2P
reserves
117.25
-6%
12.64
1,968
Source: Deutsche Bank, Wood Mackenzie
Page 22
17 September 2012
Integrated Oil
Global LNG
Gorgon and Global LNG
LNG - Key to the rebuild at Big Oil
As with Chevron, so goes big oil. We estimate that non-conventional sources of
production for these companies will grow at an estimated 8% CAGR vs overall
production growth of just 1% across the same period, rising to c40% of portfolio
volumes from nearer 20% in 2005. Beyond altering the sources of production growth,
the industry was focused on changing the structure of its cash flow model, with
substantial investment in duration-type upstream assets offsetting the deleterious effect
of the rapid declines in conventional and deepwater projects. LNG is a massive part of
this shift, alongside heavy oil sands developments. We are far more positive on pricing
in the former; the latter has exposure to what we believe will be a chronically oversupplied US oil market. We also expect oil-indexed pricing to continue to be the norm
for long term contracts, based on Asian demand strength and tightness of supply.
The industry benefits from strong demand growth. Massive upfront exploration,
marketing and development spend provide a barrier for entry, given these are beyond
the capacity of the majority of non-super major oils. The LNG payback is a 20-year +
source of maintenance-capex light, plateau-type production generating strong future
cash flows from predictable volumes.
Figure 32: LNG demand – two decades of growth at some 6-8% - with new drivers
mtpa
Demand start - end
1990-2000
2000-2010
2010-2020E
2020-2025E
55.9 – 102.7
102.7 – 219.3
219.3 – 368.7
368.7 – 457.2
6.3%
7.9%
5.3%
4.4%
48
31
27
6.3%
5.2%
4.4%
3.1%
Growth rate %
New sources
Growth rate underlying %
Source: Deutsche Bank; Wood Mackenzie estimates
The risk is a demand collapse in Asia, possibly from a pandemic, war, or revolution, for
example in market driver China. Barring a major external event of that kind, the global
market for LNG will exhibit increasing tightness through at least 2015 as growth of 34% in supply struggles to keep pace with anticipated 5-6% p.a. demand growth.
Already some 20mtpa short, we expect Asian markets to continue to tighten, sucking in
supply from other parts of the world, especially Europe. Moreover, with the projects
expected to fulfill mid-decade demand at risk of slippage, the likelihood must be that
this period of tightness is extended. Based on FID’d projects we expect gas into LNG to
compound at c.8% over the 2005-20 period, rising to 15% of production by 2020 from
6% in 2005. We expect net cash flows to turn increasingly positive, with the majors
seeing a doubling in pre-investment cash flow to c$40bn p.a. at $100/bbl oil by 2020
(Figure 38).
We have written on LNG since 1998; the demand forecasts have been solid, in
retrospect. The dynamism has come from the shifting sources of supply, the ebbs and
flows of projects from Venezuela, to Nigeria, the Arctic, and back to the classic
Australian offshore North West Shelf. The discovery of up to 100TCF of new gas
resource off the coast of East Africa together with a flood of export applications in
North America argue that the balance in the market is set to change. The emergence of
the US as a potential supply source questions the sustainability of the historical linkage
between LNG and oil prices, and perhaps equally massively, whether a repeat of the US
shale experience in China could materially undermine projected future LNG demand.
Page 23
17 September 2012
Integrated Oil
Global LNG
Figure 33: Estimated capacity growth in LNG supply
2009-20E – limited new supply to 2015 with slippage
likely
Figure 34: The short in Asian supply argues that the
region will continue to suck in Atlantic Basin LNG through
2018
160
25.0%
Capacity additions between 2012-2016
below historic demand growth with past
experience suggesting slippage likely
20.5%
20.0%
As of May '12, Fukushima and project push backs
suggest short anticipated in Asian LNG market of
c33mtpa by 2014 with market short holding
through 2018
140
120
100
80
15.0%
11.9%
10.9%
60
11.1%
9.9%
10.0%
40
8.7%
7.6%
20
5.1%
0
5.0%
3.5%
3.7%
3.7%
-20
2008
0.4%
0.0%
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
Operational
Under Construction
Probable
Possible
Speculative
Demand
2020
Figure 35: LNG spot pricing – As markets have tightened
Figure 36: Tight through 2017 – but E. Africa, US exports
so the differential between East & West has grown
and others argue there is supply options exceed demand
mtpa
$/mmbtu
Delta between UK landed and Japan landed LNG price ($/mmbtu)
12.00
45%
Supply probable/possible (PP)
600
Shipping delta (Nigeria - UK/Japan)
10.00
Demand
700
40%
Supply PP & Speculative
35%
Spare capacity PP&Spec (RHS)
500
30%
8.00
400
25%
300
20%
6.00
4.00
15%
200
10%
2.00
100
5%
0.00
2025
2024
2023
2022
2021
2020
2019
2018
2017
2016
2015
2014
2013
2012
2011
2010
Q3 12E
Q2 12
Q1 12
Q4 11
Q3 11
Q2 11
Q1 11
Q4 10
Q3 10
Q2 10
Q1 10
Q4 09
Q3 09
Q2 09
Q1 09
Q4 08
0%
0
Source: Deutsche Bank; Energy Intelligence
Figure 37: Gas into LNG – We estimate an increase from
6% to 15% of production between 2005-2020E
Figure 38: Cash into LNG – We see c$40bn of IOC cash
flow at $100/bbl by 2020
$bn
% group volumes
16.0%
Atlantic expansions (Sakhalin,
Tannguh, Qatar, Rasgas,
NLNG, Yemen) drive growth
14.0%
50
Net cash flow (a+b)
40
Onstream cash flow (a)
12.0%
30
10.0%
20
8.0%
10
6.0%
Post FID in 2012 cash flow (b)
0
From 2014 Pacific expansion (Gorgon,
Ichthys, PNG, Prelude, Wheatstone
QGC, GLNG) drives the next wave
4.0%
2.0%
0.0%
-20
-30
2020
2019
2018
2017
2016
2015
2014
2013
2012
2011
2010
2009
2008
2007
2006
2005
2004
2003
2002
2001
2000
2020
Page 24
2019
2018
2017
2016
2015
2014
2013
2012
2011
2010
2009
2008
2007
2006
Source: Deutsche Bank; Wood Mackenzie Inc RDS, XOM, CVX, BP, ENI, BG, TOTF, STL
-10
Source: Deutsche Bank; Wood Mackenzie
17 September 2012
Integrated Oil
Global LNG
Underlying growth augmented by new demand centres
Over the past two decades our sustained forecasts for LNG market growth have been
met, with a compound rate of c7% p.a driven as expected by Asia, and to an extent
environmental concerns particularly regarding nuclear power/carbon dioxide. Looking
ahead, this healthy growth trend is expected to continue. Furthermore, new sources of
demand continue to emerge. At the present time over 20 countries, as diverse as
Thailand through Poland through Jordan, are estimated to have firm plans to import
LNG with some 75mtpa of new import facilities in train. Looking back to our first
forecasts on LNG, it is the emergence of the Middle East as a demand centre that has
been remarkable.
Most importantly, China and India contribute increasingly to existing market expansion,
accounting for c65-70mtpa for 2010-20 demand growth or broadly half of the projected
growth in demand (c35mtpa of which has already been contracted).
Figure 39: Major economies’ energy mix
Figure 40: China, India and other Asia are
shows scope for EM growth in gas
account for over 50% LNG demand
35%
100%
90%
13%
80%
20%
28%
70%
4%
10%
32%
30%
16%
26%
25%
25%
60%
20%
20%
50%
40%
14%
15%
30%
10%
20%
10%
5%
13%
10%
US
Coal
European 5
Oil
Gas
Japan
Nuclear
Taiwan
Korea
Hydroelectricity
India
China
Other renewables
Source: Deutsche Bank; BP Statistical Review of world energy
n.a.
0%
Europe
11%
3%
2%
0% 0%
0%
10%
9%
Americas
JKT
China
% total volume growth
India
Other Asia
Other
CAGR 2020/10 (%)
Figure 41: Regas – countries with defined plans for re-gas
Plans for regas
mtpa
mtpa
mtpa
Bangladesh
5.4
Jordan
1.5
Poland
3.7
Canary Islands
1.0
Lithuania
3.0
Singapore
6.0
Germany
7.2
Malaysia
8.9
South Africa
1.4
Indonesia (Java)
4.8
Morocco
3.7
Thailand
10.1
Ireland
1.9
New Zealand
0.5
Uruguay
2.7
Israel
1.7
Pakistan
6.7
Vietnam
3.0
Jamaica
1.1
Philippines
1.5
TOTAL
73.5
Growth across the major end markets of Japan, South Korea and Taiwan is expected to
continue at a healthy 3% p.a. augmented in part by Japan’s likely enforced shift away
from nuclear (or nearer 2.5% if the c6mtpa Fukushima-derived uplift that remains by
end decade is excluded). Indeed, given their existing scale these three economies are
expected to account for over a quarter of market growth (or c40mtpa). Europe is also
expected to see modest growth; but more importantly and interestingly we believe that
Europe looks set to take the role of swing consumer, with LNG shifting from West to
East through periods of supply tightness and back again as the demand cycle eases.
Page 25
17 September 2012
Integrated Oil
Global LNG
Figure 42: The past ten years – the Americas, Europe and
JKT dominate the market and drive growth
mtpa
Figure 43: The next ten years – China and India are
absolutely key, with Europe (UK) providing a sink
mtpa
Europe
250.0
Americas
China
200.0
India
JKT
400.0
Other Asia
350.0
Europe
Americas
JKT
China
India
Other Asia
Other
Other
300.0
250.0
150.0
200.0
100.0
150.0
100.0
50.0
50.0
0.0
2000
0.0
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
Figure 44: LNG market shares by geography at decade
ends – China and India are growing in importance
Figure 45: LNG: Geographic growth rates and share of the
absolute growth. Asia dominates on all fronts
35%
100%
China
&
India
8%
90%
80%
China
&
India
24%
70%
60%
32%
30%
26%
25%
20%
20%
50%
14%
15%
40%
30%
10%
20%
5%
10%
13%
10%
n.a.
0%
2000
Europe
2010
Americas
JKT
China
Europe
2020E
India
Other Asia
Other
11%
3%
2%
0% 0%
0%
10%
9%
Americas
JKT
China
% total volume growth
India
Other Asia
Other
CAGR 2020/10 (%)
Figure 46: Major economies energy mix 1990 shows the
bias towards oil
Figure 47: Major economies energy mix 2010 shows
strong gasification
100%
100%
2%
90%
80%
25%
17%
10%
3%
4%
6%
90%
70%
70%
60%
60%
50%
50%
40%
40%
30%
30%
20%
20%
10%
10%
0%
US
Coal
European 5
Oil
Gas
Japan
Nuclear
Taiwan
Hydroelectricity
Page 26
Korea
13%
80%
India
China
Other renewables
20%
28%
10%
4%
16%
25%
0%
US
Coal
European 5
Oil
Gas
Japan
Nuclear
Taiwan
Korea
Hydroelectricity
India
China
Other renewables
17 September 2012
Integrated Oil
Global LNG
Considering China’s demand potential – a country whose coal market is equivalent to
the global LNG market seven times over – natgas growth is an agenda item. The
Government’s stated aim is to gasify the economy and carry gas’ share of the energy
mix from c4% in 2010 to 10% by 2020. Assuming an economy that grows at c.7% p.a.
over the decade our analysis of the different sources of gas supply (piped imports,
indigenous conventional and shale) suggests that by 2020 China could easily require
c60mtpa of LNG. This is despite our aggressive assumption that China will meet its
official shale objective by 2020 of producing c2,120 - 3,530bcf of gas from shale from
just about nothing today.
Using the NDRC’s objectives as a base, below is a simple model for natgas in China
through 2020. Assuming an economy that grows at 7% p.a. and energy intensity
averages 0.7x over the period (well down on the 0.9x seen over the past decade but in
line with the country’s objective of lowering the energy intensity of the economy c18%
by 2015), this suggests to us a broad doubling of natural gas demand by 2015 to
c22bcf/d with demand again near doubling by 2020 to c45bcf/d. Against this we lay
down Wood Mackenzie’s assumptions for indigenous supply ex-shale gas together with
our understanding of the pipeline supply which China has contracted from Myanmar
and Turkmenistan. The balance represents the excess demand that we estimate will
need to be met from alternative sources, most significantly shale gas and LNG. With
little data at all on the true potential for shale gas, we perhaps generously assume that
by 2015 China achieves its stated objective of some 230bcf p.a. of production rising to
over c6bcf/d by 2020. The balance represents the potential for LNG which by 2015
stands at 21mtpa, but by 2020 nearer 60mtpa.
Figure 48: China gas: Basic natural gas supply/demand model
2010
2011
2012
2013
2014
2015
2016
Demand (bcf/d)
3885
4748
5750
6440
7213
8079
9048 10134 11350 12712 14238
China - Gas supply
3308
3649
4319
4560
5096
5580
5988
6532
7090
7820
8834
3265
3541
4130
4205
4562
4876
5072
5187
5328
5465
5611
0
0
18
88
159
229
344
706
1059
1589
2383
43
108
171
267
376
474
572
639
703
766
841
127
505
724
900
1059
1059
1059
1059
1059
1059
1059
99
282
424
424
424
424
424
424
212
530
1059
1059
1059
Conventional
Shale
CBM/CTG
2017
2018
2019
2020
Imports
Turkmen 1 Pipe
Myanmar Pipe
Turkmen 2 Pipe
Balance - LNG (bcf)
450
594
708
882
776
1016
1365
1590
1719
2351
2862
Balance - LNG (mtpa)
9.4
12.2
14.3
17.8
15.7
20.5
25.3
32.1
34.7
47.5
57.8
LNG contracted mtpa
9.8
12.4
14.9
18.1
21.9
25.8
32.3
36.7
37.4
37.4
37.4
Regas capacity mtpa*
11.6
15.6
21.4
28.0
40.7
44.7
54.2
60.7
65.3
66.8
70.3
LNG - % coal demand
0.6%
0.8%
0.9%
1.1%
0.9%
1.1%
1.3%
1.6%
1.7%
2.2%
2.6%
LNG - % oil demand
2.4%
3.0%
3.5%
4.2%
3.5%
4.4%
5.2%
6.4%
6.7%
8.8% 10.3%
Source: Deutsche Bank; BP Statistical Review of world energy, Wood Mackenzie * Approved and proposed
Based on our simple forecasts it is clear that the estimated demand is not only broadly
in line with that contracted through the middle of the decade (c37mtpa by 2017) but
also with the country’s proposed plans for re-gas capacity through the end of the
decade. To the extent that China’s official targets for shale gas are not achieved (a view
espoused by many IOCs) there is also significant forecast upside (every 10bcm, or
353bcf, of shale shortfall equating to the potential for an incremental 7mtpa of LNG
demand).
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17 September 2012
Integrated Oil
Global LNG
With LNG imported into coastal regions, displacing more expensive fuel oil, we also
believe that over the current decade pricing will not prove a substantial issue. That said,
at a likely price of c$14-15/mmbtu assuming $100/bbl oil, against an estimated $810/mmbtu for pipeline and shale gas (including transmission charges), LNG does not
appear especially competitive vis a vis other sources of gas let alone coal. Indeed, it
would seem reasonable to assume that dependent upon the success or otherwise of
shale gas in China, it is almost certainly LNG’s relatively high cost that will limit the
pace at which it continues to grow as a source of fuel beyond 2020. A 40-50mtpa
increase in demand through the current decade (25mtpa of which has already been
contracted) does not, however, seem unreasonable.
Similarly, our analysis of India’s gas markets suggests significant potential for growth.
Over the past two decades gas demand has expanded by 8% p.a. With few new
indigenous sources of gas and the giant Reliance/BP KG6 field suffering significant
delivery issues, there are robust short term arguments for a surge in LNG demand.
Overall, our modeling suggests that assuming 5% p.a. gas demand growth, India will
require around 40mtpa of LNG by 2020, a c32mtpa increase on 2010. We recognise
that, because of India’s faltering energy policies and price structures, LNG’s full
potential is unlikely to be realized.
Figure 49: China – energy demand growth
Figure 50: China energy demand in 2010
1990-2010 looks unsustainable
expressed in LNG equivalence
mtoe
3000
2500
Hydro 124 mtpa
Oil
Gas
Coal
Nuclear
Hydro
Renewables
Nuclear 68 mtpa
Renewables
14 mtpa
Oil
366 mtpa
2000
Gas
93 mtpa
1500
1000
500
Coal
1458 mtpa
0
2011
2010
2009
2008
2007
2006
2005
2004
2003
2002
2001
2000
1999
1998
1997
1996
1995
1994
1993
1992
1991
1990
With limited visible new sources of conventional gas, a CBM industry that remains no
more than nascent and a domestic pricing policy that in our opinion is, if anything,
more likely to discourage than encourage investment in new sources of domestic
supply at this time, India’s demand for imported gas seems likely to boom. Near-term
the collapse in projected production from the key Reliance Dhirubi field (KG6) from
c2.8bcf/d to just 0.7bcf/d (or the equivalent of c14mtpa of LNG) also argues that India
will need to significantly increase its imports of LNG. Indeed, with the country’s
environmental restrictions on coal mine expansions of the past three years also severely
restricting growth in domestic coal, India appears in many ways to be on the verge of
an energy crisis. Again, this can only add in our opinion to its short term need for
alternative sources of energy supply.
Bearing these observations in mind Figure 51 illustrates the potential for LNG demand
growth in India. In building our estimates we have assumed that gas demand growth
moves to 5% p.a. from the 8% p.a. achieved over the past two decades, largely to
reflect the lower pace of growth anticipated for the Indian economy (c6-7% p.a.) as well
as the more limited availability of cheap domestic supplies. Equally, we have adjusted
our estimates for growth in those years where insufficient re-gas capacity is in place to
import the estimated volume of gas that the market appears likely to require.
Page 28
17 September 2012
Integrated Oil
Global LNG
Figure 51: India: Basic natural gas supply demand model
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
Domestic demand
61.9
61.1
61.0
64.7
69.2
72.6
76.3
81.6
85.7
90.0
94.5
Domestic supply
50.8
46.1
39.5
40.1
40.9
40.9
40.4
41.0
42.4
42.4
39.1
LNG imports
11.1
15.0
21.5
24.6
28.3
31.7
35.9
40.7
43.3
47.6
55.4
7.9
10.7
15.3
17.5
20.2
22.6
25.6
29.0
30.9
33.9
39.5
9.0
6.3
10.0
11.6
13.1
14.2
17.3
16.9
18.9
24.5
LNG demand mtpa (a)
Demand pre-KG6 d/grade
LNG contracted mtpa (b)
7.5
9.0
9.1
7.6
8.6
9.6
11.4
11.7
14.0
15.0
15.0
Re-gas capacity mtpa
13.6
13.6
15.1
20.0
22.9
24.1
28.7
36.3
36.3
36.3
41.3
Excess required (a-b)
n.a.
n.a.
6.3
10.0
11.6
13.1
14.2
17.3
16.9
18.9
24.5
Source: Deutsche Bank; BP Statistical Review of world energy; Wood Mackenzie
Looking at Figure 51 immediately apparent is that with little by way of new domestic
supply growth anticipated over the coming decade, if gas is to maintain its share of
India’s existing energy mix, let alone increase that share, the country will need to
significantly increase its imports of LNG. We see an increase in LNG imports by 2020 of
around 30mtpa relative to 2010 levels.
Yet, set against this seemingly positive backdrop is whether the economics of many of
India’s power projects and developments will still work under their current producer
price agreements (PPA’s) when faced with a gas import price that will likely be
significantly higher than the c$5-6/mmbtu stipulated by Government for gas supplied
domestically, not least from KG6. Thus, whilst the potential for significant LNG demand
upside would most definitely appear to exist, policy uncertainty is high. Indeed, because
of past Government interference, price feels a much more important constraint upon
demand for India than it does for China. This together with the country’s more
comfortable relationship with the US also suggests to us that India will likely be a far
more important home for potential US exports than China (as perhaps illustrated by
GAIL’s recent Cheniere deal).
So where are we left on the industry’s demand outlook in aggregate? It seems clear to
us that whilst there are significant uncertainties, the market opportunity in each
economy is very real, with c.70-80mtpa of new demand (almost half of which has
already been contracted) readily forecastable. Add to this the potential for the
emergence of demand from new territories of 30mtpa (of which 9mtpa is already
contracted) and the market’s requirements by 2020 look set to be comfortably above
320mtpa – and this before considering potential growth from the 200mtpa that
currently arises in the existing markets of JKT, Europe, Latin America and the Middle
East. Allow for growth here of broadly 2% in aggregate and, at 370mtpa in total Wood
Mackenzie’s 2020 expectation for some 368mtpa of global demand strikes us as very
sensibly placed.
Page 29
17 September 2012
Integrated Oil
Global LNG
Figure 52: Global LNG: Demand by region 1990-2020E
1990
2000
2010
2020E
10 yr CAGR %
Region
mtpa
%
mtpa
%
mtpa
%
mtpa
%
China
0
0%
0.0
0%
9.4
4%
57.8
16%
To ‘00
To ‘10
To ‘20
n.a.
n.a.
19.9%
India
0
0%
0.0
0%
8.8
4%
29.4
8%
n.a.
n.a.
12.8%
JKT
37.8
68%
72.8
71%
114.7
52%
153.5
42%
6.8%
4.7%
3.0%
Americas
0.5
1%
4.5
4%
19.3
9%
15.2
4%
24.7%
15.6%
-2.4%
Europe
17.6
31%
25.1
24%
63.5
29%
77.6
21%
3.6%
9.7%
2.0%
Other Asia
0
0%
0.0
0%
0.0
0%
12.8
3%
n.a.
n.a.
n.a
RoW inc M East
0
0%
0.3
1%
3.4
2%
22.5
6%
n.a.
9.6%
9.9%
55.9
100%
102.7
100%
219.3
100%
368.7
100%
6.3%
7.9%
5.3%
Total
Source: Deutsche Bank; Wood Mackenzie
Figure 53: Gas as % overall energy mix –
Non-OECD still well below OECD
Figure 54: Founder projects start to enter
decline post 2018 adding to supply needs
mtpa
30.0%
25.0%
22.6%
20.6%
20.4%
ADGAS
Bontang
Brunei
Malaysia
c.30mtpa decline foreseen
2018-25 from formative
schemes
60
19.6%
20.0%
15.9%
17.2%
13.8%
15.0%
ALNG
70
24.9%
50
40
11.3%
9.4%
10.0%
30
20
5.0%
10
0.0%
1970
1980
2000
2025
2024
2023
2022
2021
2020
2019
2018
2017
Source: Deutsche Bank; BP Statistical Review
0
2016
Non OECD gas ex Russia
2010
2015
OECD gas
1990
Source: Wood Mackenzie GLO; Deutsche Bank
Beyond 2020, we believe it is reasonable, assuming accuracy of our previous long term
market size estimates, to assume LNG markets continue to expand at around 4-5% p.a.
as new markets emerge. By 2025 it would not seem unreasonable to anticipate global
market demand of between 450-470mtpa. At broadly twice the current 220mtpa
market, this certainly suggests that the appetite for supply is going to be considerable.
Moreover, as we move towards the next decade resource depletion will see a number
of founder supply projects (Brunei, Abu Dhabi, Malaysia and Indonesia) enter decline.
Include an estimated c.30mtpa of supply loss here and by 2025 the market looks likely
to require around 270mtpa of supply relative to its effective 2010 capacity.
LNG supply to 2025 – many horses but several will fall
Gas is abundant globally. But mooted supply schemes in Iran, Venezuela (first pursued
1971 by Lee Raymond) and Nigeria will struggle to rise from the drawing board given
geopolitical/financing issues. Expansions in markets which are now short of domestic
gas such as Trinidad and Egypt also strike us as unlikely to see new export schemes
approved. Thus, the list of supply options falls relatively sharply. Whilst this revised
estimate of potential supply is far closer to the demand envisaged, it remains materially
above the 190mtpa demand increment. Moreover, with the scale of the discoveries in
East Africa building, the Eastern Mediterranean emerging as an important new gas
province, and applications for US export being filed on an almost monthly basis, it also
likely excludes a number of further potential sources of 2025 supply.
Page 30
17 September 2012
Integrated Oil
Global LNG
Figure 55: Potential LNG supply out thru 2025 – split by
geography as a % 360mtpa potential supply
AB other
3%
PB expansions
3%
FLNG
ME expansions
3%
2%
60
Fantasy LNG
4%
50
US LNG
15%
T&T/Egypt/Yemen
2%
40
Canada/Alaska
LNG
11%
Venezuela LNG
4%
Iranian LNG
6%
30
20
10
ME expansions
Trin/Egypt/Yemen
AB expansions
AB other greenfield
PB expansions
FLNG
Venezuela LNG
Fantasy LNG
Iranian LNG
Russian LNG
Australian greenfield
East African LNG
Australia expansion
Source: Deutsche Bank; Wood Mackenzie GLO
Australia
expansion
9%
Canada/Alaska LNG
East African
LNG 8%
Nigeria LNG
Australian LNG
8%
0
US brownfield LNG
AB expansions
3%
Russian LNG
6%
Nigeria LNG
12%
Figure 56: Composition by geography all the speculative
supply schemes out to 2025 in mtpa per region
Is there over-supply in the long term and will prices normalise globally? After all if a unit
of gas sells for $2-3/mmbtu in the US it seems beyond the realms of credibility that in
Asian markets it can continue to trade for nearer $15/mmbtu. Seen from this
perspective oil-linked pricing looks doomed. Not so. The price experience of the past
decade shows contract price terms appreciating in recent years as the number of
schemes competing for demand faltered. Depicted in Figure 57 we show how pricing
across several LNG contracts has shifted over the years. Initially much of the growth in
price reflected the marked increase in industry costs experienced through the middle of
the past decade. Over the past five years, however, fluctuations in the contract price
secured for the long-term supply of LNG have, as much as anything, reflected
competition for off-take at particular points in the cycle. With substantial new supply
options now emerging from the US, East Africa and the Mediterranean in addition to
already mooted Australian developments the supply side again looks set for
intensification in price competition; but we believe that this in turn will be self-defeating
for supply growth.
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Figure 57: LNG contract prices over the past decade. Price clearly fluctuates as the cycle
shifts from short supply to short demand
25
LNG price ($mmbtu)
20
Where costs drove the initial
changes in pricing, more recently
the supply/demand cycle has played
an important role with prices
peaking in '08 and troughing in '10
C
y
c
l
e
15
10
C
o
s
t
5
0
50
60
70
80
90
100
110
120
Oil price $/bbl
Oil Parity
NWS - Guangdong (2002)
Tangguh -Fujian (2003)
Sakhalin - Tokyo Gas (2004)
NWS recontracts 1 (2006)
NWS recontracts 2 (2006)
Gorgon-Petrochina (2007)
Rasgas - Kogas (2006)
Qatargas 2 - Chubu (2007)
BG Curtis (2010)
Qatar-Tepco (2012)
Source: Deutsche Bank; Wood Mackenzie data
We have analysed, alongside Wood Mac’s work, the different prices required to deliver
a 12% internal rate of return based on the net back LNG price across a host of different
geographies, such as Australia, Mozambique and North America in order to establish a
marginal cost curve for the supply industry. To this we have added the estimated midcycle cost of shipping via charter to Tokyo Bay, Japan. Applying this to our estimate of
the total volume of LNG supply should afford a sensible view of those projects which
are likely to make it past the FID post and achieve a sensible return on capital invested.
The resulting cost curve is depicted in Figure 58. Evident from this is the relatively high
cost of both Australian and Russian LNG (c$13/mmbtu), the far better positioning of
East Africa (c$9/mmbtu) and the strong cost advantages of US brown-field, Canadian
and Nigerian supply schemes (c$8/mmbtu and below). For the US, however, equally
apparent is the much higher cost of shipping, a feature which of itself eats significantly
into the notable cost advantage inherent in the US schemes. Indeed, it is of note that
despite the far higher liquefaction costs associated with Canada, because of the
proximity of Canada’s Pacific coastline to Japan much of this cost difference unwinds.
As to the cheapest projects, Nigeria still proves the most favourable location albeit that
in building the Brass model, the tax and gas input costs (marginal at c$1/mmbtu) are
assumed to be in line with those which apply to Nigeria LNG. Neither of these
assumptions should be taken for granted.
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Figure 58: New Build LNG: Constructing the marginal cost curve illustrates the high cost
of Russian and Australian schemes vis a vis US, Canada and East Africa.
16.00
FOB Cost (Breakeven)
Shipping cost
$/mmbtu for 12% IRR
14.00
12.00
10.00
8.00
6.00
4.00
Shtokman
Browse (Aus)
Shtokman
(Russia)
QCLNG (Aus)
Wheatstone
(Aus)
Prelude FLNG
Ichthys (Aus)
Gorgon (Aus)
Cheniere US
@ $6/mmbtu
Pluto (Aus)
Tanzania
LNG
Mozambique
Cheniere US
@ $4/mmbtu
Shell CNPC
Canada
Kitimat
(Canada)
Brass LNG
(Nigeria)
Reverting to Wood Mackenzie’s list of probable, possible and speculative supply
schemes we present the total volume potential of c360mtpa out to 2025, but on the
basis of the estimated average break-even costs for the various supply schemes in the
different geographic regions. Assuming a market requirement of c190mtpa over the
same period as illustrated in Figure 59 suggests to us a marginal breakeven price of just
over $10/mmbtu delivered into Tokyo Bay, with the US export schemes (assuming a
$4/mmbtu long term price of gas) serving as the marginal projects.
Figure 59: Grading LNG supply – Listing all the potential supply schemes in Wood Mac’s
database, we see the cut-off for supply at c$10/mmbtu assuming c190mtpa of demand
$/mmbtu
16.0
14.0
12.0
10.0
8.0
6.0
4.0
0
31
60
91
121
152
182
213
244
274
305
ME expansions
Nigeria LNG
AB expansion
Iranian LNG
Trin/Egypt/Yemen
PB expansions
AB other greenfield
Australia expansion
Canada LNG
US BF LNG
FLNG
East African LNG
Australian GF LNG
Venezuela LNG
Russian LNG
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Global LNG
At face value it seems that of potential schemes to compete purely on breakeven price
for the available demand, none of the schemes in East Africa, Australia or Russia would
ever see the light of day. Rather tomorrow’s LNG supply would largely comprise
expansions at existing facilities (always likely to be the most economically viable)
together with the build out of opportunities in Nigeria, Canada and Iran. That looks
good for Chevron, given its gas resource and 2017 project base.
Applying qualitative analysis, in Figure 60 we show the resource cost curve but this
time without those schemes which we believe are unlikely to pass the FID post not
least Iran, Nigeria, Venezuela and those schemes located in geographies with
potentially constrained domestic gas markets. Evident from this is that it is the
Australian green-field that now represents the marginal project with the breakeven price
rising by around $3/mmbtu to c$13/mmbtu for the industry as a whole. Yet where this
analysis would tend to suggest that only 5-10mtpa of green-field Australian LNG
capacity would appear price competitive, supply from East Africa sits relatively
comfortably on the cost curve with scope for at least 40mtpa of supply before the cutoff point is reached.
Figure 60: Grading LNG supply – Strip out the candidates that comprise significant
uncertainty and we see the demand cut off falling in East Africa
$/mmbtu
16
14
12
10
8
6
4
2
0
0
31
60
91
121
152
182
Middle East expansions
AB expansion
PB expansion
AB other greenfield
Australia expansion
Canada LNG
US Brownfield LNG
FLNG
Mozambique
Tanzania
Australian Greenfield LNG
213
mtpa
Equally apparent from the above, however, and with particular relevance for Australia is
the existential threat that is implied for all of the high cost projects from the emergence
of the US as a major source of supply. And whilst the estimates for breakeven cost that
are presented above assume a sustainable US gas price of $4/mmbtu it is of note that it
is only if the US price of gas were to rise beyond $6.50/mmbtu that the projects
towards the high end of the cost curve would appear cost competitive with the US
(shipping rates allowing). Key to the outlook for further green-field expansion in
Australia, Russia (if one wishes to be so bold) and, to a lesser degree, East Africa is
therefore quite what the industry should expect from the development of US LNG for
export.
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US exports – what should we expect?
Starting with Cheniere’s June 2010 announcement that it was to seek a license for the
export of LNG from US shores, the past two years have seen a dramatic increase in
applications for the export of US gas as LNG to both FTA (free trade agreement) and
non-FTA markets. To date fifteen applications have been received requesting the export
of up to 156mtpa or 20.5bcf/d of gas, broadly 30% of current US gas supply (c68bcf/d).
Where most of those applications filed have been approved for the export of gas, to
countries with which the US has an existing free trade agreement (of which only Chile,
Mexico and South Korea offer material export potential) only first to apply Cheniere has
so far received Department of Energy (DoE) and Federal Energy Regulatory Commission
(FERC) approval, for the export and construction of up to 18mtpa of LNG to both FTA
and non-FTA countries. Dependent upon the final outcome and recommendations of an
already delayed DoE study on the potential impact of LNG exports on the domestic
economy the consensus remains, however, that further approvals will be forthcoming,
most likely subsequent to November’s US Presidential election.
Looking through the details of the filings to date (Figure 61) roughly 40mtpa (5bcf/d) are
represented by green-field sites and, as such, are likely to have similar construction
costs to new developments elsewhere across the globe (we would estimate a delivered
cost of at least $11/mmbtu assuming a $4/mmbtu Hub price). Without wishing to
ignore these projects, from our perspective they consequently contain all of the
negatives associated with US supply (politics, dry gas, Hub price escalation, etc) but
few of the benefits. Buyers consequently look far better placed to source from Canada.
Applications for brown-field developments on existing sites should, however, benefit
materially from lower construction costs given existing infrastructure, not least storage
and port facilities. At about half the normal cost to develop an LNG site it is the
potential build out of the c116mtpa of proposed facilities of this nature that, in our
opinion, represent the greatest effective threat to the LNG industry’s current status quo.
Figure 61: Main LNG export schemes for which an export application has been made both FTA and non-FTA
Location
Sponsor
Capacity
mtpa*
Capacity
bcf/d
For FTA
countries
Approval
status
Non-FTA
countries
Approval
status
Sabine Pass
Gulf Coast
Cheniere
18.0
2.20
Yes
Yes
Yes
Yes
Freeport
Gulf Coast
Freeport LNG
10.4
1.40
Yes
Yes
Yes
No
Lake Charles
Gulf Coast
BG/Southern
15.0
2.00
Yes
Yes
Yes
No
Cove Point
Maryland
Dominion
7.4
1.00
Yes
Yes
Yes
No
Cameron
Gulf Coast
Sempra
13.0
1.70
Yes
Yes
Yes
No
Freeport Expansion
Gulf Coast
Freeport LNG
11.0
1.40
Yes
Yes
Yes
No
Elba
South Georgia
Southern
4.0
0.50
Yes
Pending
n/a
No
Excelerate Liquefaction
Gulf Coast
Excelerate
10.0
1.38
Yes
Pending
n/a
No
Gulf LNG Liquefaction
Gulf Coast
Gulf LNG LLC
11.5
1.50
Yes
Pending
n/a
No
Golden Pass
Gulf Coast
Exxon/QG
18.0
2.2
Yes
Pending
n/a
No
116.6
15.28
Project (filing date)
Brownfield
Total brownfield
Greenfield
Jordan Cove
Oregon
Fort Chicago
9.0
1.2
Yes
Yes
Yes
No
Gulf Coast LNG export
Gulf Coast
Sempra
21.0
2.80
Yes
Pending
Yes
No
Oregon LNG
Oregon
Oregon LNG
9.0
1.25
Yes
Pending
NO
No
Total greenfield
39.0
5.25
Total (main ex 0.4bcf/d)
155.5
20.5
Source: EIA; Deutsche Bank *mmtpa based on 135mscf/d providing 1mtpa of capacity
Page 35
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Yet whilst US appetite for the build out of export facilities appears very substantial, far
less clear is quite how great the permitted volumes of gas for export will be. The fear
will be, irrationally as ever, that exports will raise domestic prices and so hinder US
interests. Like any protectionist argument, this is short-term attractive, long-term
nonsense. That makes it dangerously attractive to the average US politician. Clarity on
the matter will emerge until the DoE study on pricing and the US economy is published
later this year. However, with US Energy Secretary Stephen Chu stating that
“The best way to do this is you don’t want to be granting six or ten permits and then say
‘Ooops.. what a terrible mistake you made’.”
Common sense would suggest that the US DoE is most likely to tread cautiously
allowing a significant, but limited, volume of gas to flow to export in a relatively
controlled manner. Such an approach would, in our opinion, reduce the risks of
significantly disturbing the domestic gas price as well as allowing the supply industry to
broadly keep pace with demand particularly given the pull from other industries (not
least chemicals and power) over the same period. Bearing these points in mind we
would be surprised if the DoE permitted more than a 6bcf/d (40mtpa) base load with
approvals staggered over the next five or so years (in effect the low and slow case
presented in the EIA’s January 2012 study).
Even if all were approved, however, there are also clear questions on the absolute level
of buyer interest in the supply that is available. By the time shipping and liquefaction
costs have been included the price differential of US gas is substantially reduced.
Equally, where the broadening of supply sources and use of a non-oil proxy for price are
both attractive features, committing to supply off-take does not come without
significant risks and complications. Not least amongst these from our perspective are
the following: t

Price: At a conceptual c$9/mmbtu delivered cost (split $3.45/mmbtu gas, $3/mmbtu
liquefaction and $2.5/mmbtu shipping as per Figure 62), US-sourced LNG may look an
attractive supply option based on today’s gas price. But as the recent history of US gas
prices have shown the commodity can be notoriously volatile. Consequently, how
confident are buyers that over the next twenty years US gas prices will not appreciate
to levels that afford little if any advantage relative to alternative sources?
Figure 62: US CIF pricing based on most recent Cheniere’s contracts
Hhub price
2.00
3.00
4.00
5.00
6.00
7.00
Energy cost (15%)
0.30
0.45
0.60
0.75
0.90
1.05
Capacity charge
3.00
3.00
3.00
3.00
3.00
3.00
FOB cost
5.30
6.45
7.60
8.75
9.90
11.05
Shipping via Cape inc fuel*
2.51
2.51
2.51
2.51
2.51
2.51
CIF cost
7.81
8.96
10.11
11.26
12.41
13.56
Source: Deutsche Bank *Were product to travel via the Panama Canal once opened in 2014 the charter saving would be c$1.00. We assume however that much
of this will be offset by the toll charged to use the Canal. Separately, we note that current spot shipping rates would equate to a $2.00 increment on the costs
indicated above ie at today’s spot rates the effective cost of delivered LNG would be $11/mmbtu.

Political risk: Energy and energy independence are emotive subjects in US politics.
Consequently, there must be buyer concern that US politicians might change their view
on exports and act to rescind the export licenses that have been granted. Importantly,
the terms of Cheniere’s license specifically grant the US authorities this option
(although in fairness the comments of the current US Energy Secretary suggest he
would not wish to revoke).
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Dry gas: Natural gas can always be spiked. But as we have seen with Australia’s coal
seam gas projects, Asian buyers are highly conservative. That US gas is dry and
therefore of a lower calorific value than that used in many importing countries is
detrimental to economics.

Capacity cost. In contrast to taking re-gas capacity, committing to take liquefaction
capacity is far more expensive (c$3/mmbtu for liquefaction vs. c$0.35/mmbtu for regas). For the portfolio players and arbitrageurs this makes taking an ‘option’ on US LNG
a far riskier call. Thus where we believe that for the major IOCs the ability to source US
gas, not least to underpin the initial off-take from their own development projects, is a
valuable option, at c$150m p.a. for each mtpa of liquefaction capacity it is not cheap.
Moreover, those contracting will also have to have access to shipping, adding further to
their committed cost. Of itself this will, we suspect, limit the absolute level of demand.
Ultimately, none of these risks strike us as insurmountable. Yet they do appear
sufficiently large to suggest that, where US sourced gas may come to represent an
important portfolio option for many, buyers will be reluctant to leave themselves overly
dependent upon this one market. For some of the more important sources of
tomorrow’s LNG demand growth, most significantly China, we would also argue that
the US as a source of supply will be limited. The politics will, we suspect, just prove too
uncomfortable. To the extent that the Chinese want low priced gas, Canada looks to us
to be a far more attractive option.
Perhaps the right approach to determining the potential out turn by 2025 for US LNG is,
therefore, to better consider what the demand for US sourced product might be. For
without firm off-take contracts little will ultimately be built.
Approach things from this angle and, after allowing for capacity already in build
(80mtpa) and incremental Chinese demand over and above that contracted (2030mtpa), the US will be competing for part of the 170mtpa of remaining demand
growth we see by 2025. Assuming that most utilities will be reluctant to source more
than 10-20% of their future LNG needs from the US and this would suggest to us that
direct utility demand for US sourced LNG is unlikely to be much more than 25-30mtpa.
Less easy to predict in our opinion, however, is the extent to which US supply becomes
a source of demand for the key portfolio players such as BG Group, Shell, Total and GdF
Suez. For where the demise of North America as the LNG industry’s sink, when
combined with the escalation in build costs, sounded the death knell for the arbitrage
model over the longer term, so too has the emergence of the US as a cheap source of
supply offered the portfolio players a new, albeit higher risk, life line. Yet even here the
much greater financial commitment required and price risk taken suggests to us that
demand is likely to be contained over the next 5-10 years. Assuming some 15-20mtpa
ends up in the trading portfolios of the majors we are again left of the impression that,
irrespective of supply, aggregate demand for US sourced LNG by 2025 is unlikely to be
much beyond 40-45mtpa.
So how would a figure of this order position the higher cost projects in Australia and
East Africa, amongst others? Referring back to the earlier marginal cost curve but
altering US brown-field supply to 45mtpa from the previous c56mtpa the answer is
relatively little changed, with only half of the c30mtpa of mooted Greenfield Australian
supply likely to make it to market. For Mozambique and Tanzania however the shift in
the curve is far more encouraging, not least given our expectation that to the extent
that further trains were to be built they would benefit significantly from the typical
economies expected of an expansion project.
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Maybe the conclusion should therefore be that one way or another, resource rich or
not, Australia is slowly pricing itself out of the market with East Africa the more
material threat. As such, it strikes us that it is those with potential green-field supply
schemes in Australia for whom market timing is far more important. Miss the emerging
window for unmet future demand and, absent a sharp decline in Australian
construction costs, the risk must be that between the US and East Africa, finding
sufficient buyers at an economic price will prove increasingly challenging. For projects
such as Browse and Arrow, amongst others, this is not encouraging.
Figure 63: At 45mtpa of US LNG Australian green-field is better placed albeit that East
African supply growth then appears the greater threat.
$/mmbtu
16
14
12
10
8
6
4
2
0
0
7
14 21 28 35 42 49 56 63 70 77 84 91 98 105 112 119 126 133 140 147 154 161 168 175 182 189 196 203
mtpa
AB expansion
PB expansion
AB other greenfield
Middle East expansions
Australia expansion
Canada LNG
US Brownfield LNG
Mozambique
Tanzania
Australian Greenfield LNG
FLNG
US LNG exports – the chance for the arbitrageur to rejuvenate
Quite aside from its significance as a source of global LNG supply to utility buyers the
emergence of the US as a potential source of LNG represents something of a life-line in
our opinion for the LNG arbitrage players, namely BG Group, GdF Suez and, to a lesser
extent, Total and Shell.
Our reasoning is simple. The emergence of shale gas in North America effectively saw
the end of the US market’s need to import gas, so too has the associated collapse in the
US gas price and escalation in LNG supply costs ended the use of the ‘discount to
Henry Hub’ price formula that formed the basis of most Atlantic Basin supply contracts.
For the arbitrageur this has presented a significant challenge, namely how to gain
access to a significant supply of LNG for trading, that was competitively priced but
which, at times of market excess, could also be off loaded without the risk of significant
financial loss. To some good extent, the emergence of the US as a potential source of
cost advantaged supply changes all of this.
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Figure 64: Annual trading of gas: The US
has depth and liquidity. Euro hubs don’t
Figure 65: European storage similarly
offers limited capacity vis a vis the US
bn therm
bn therm
5000
4000
4500
3500
4000
3000
3500
2500
3000
2000
2500
2000
1500
1500
1000
1000
500
500
0
NBP
ZEE
NCG
GP
TTF
0
Henry Hub
NBP
Source: GSA; Deutsche Bank
ZEE
Baumgarten
PEG
TTF
HHub
Source: GSA; Deutsche Bank
This is not to say that alternative hubs have not been used as the basis of price formula.
For European utility buyers the UK’s National Balancing Point (NBP) is and remains an
important price basis against which to contract gas for long term delivery. However, as
illustrated in Figure 64 & Figure 65, gas markets and trading hubs outside North
America just do not have the depth, fungibility or potential for storage necessary to
form a price base against which an arbitrageur would confidently contract ‘portfolio’
supply let alone a project developer commit to sell its supply.
This makes the speculative commitment to purchase gas on a long term basis with a
view to trading it across markets on the basis of the NBP price risky in the extreme. For
absent a deep fungible market that through demand and storage can absorb a
significant increase in supply, the likelihood is that the delivery of a material volume of
gas that is surplus to demand will significantly disrupt spot pricing (if indeed sufficient
capacity exists to absorb the gas at all). US exports excluded, point to point contracts
have thus grown in relevance and with them the importance of firm end market
demand. Indeed, it is of note that BG’s contract with Cheniere at Sabine Pass to acquire
portfolio gas represented the first firm commitment to acquire portfolio gas by any
portfolio player since the middle of the last decade. As shown in Figure 67 portfolio
LNG has, and looks set to continue to fall, as a percentage of the overall LNG market.
Figure 66: BG Group: LNG portfolios effectively ‘waste’
Figure 67: Portfolio LNG as a % of that in circulation is in
over life of contract. US LNG offers scope for renewal
decline as the market shifts back to point to point
20
Sabine Pass offers BG the
chance to extend the life
of a wasting LNG portfolio
18
16
40.00%
35.00%
30.00%
14
12
25.00%
10
20.00%
8
15.00%
6
4
10.00%
2
5.00%
0
2030
2029
Source: Deutsche Bank; BG Group
2028
Sabine Pass 3/4
2027
ELNG 2
Sabine Pass 1/2
2026
ALNG 2/3
ALNG 4
2025
2024
2023
2022
2021
2020
2019
2018
2017
2016
2015
2014
2013
2012
Equatorial Guinea
2007 Portfolio as % market
2012 portfolio as % market
0.00%
Nigeria 4/5
Page 39
17 September 2012
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Global LNG
For the arbitrageurs, the emergence of the US as a potential source of price competitive
supply changes all of this. Not only does it offer them the option to rejuvenate their
trading portfolios. At the same time it also affords them the ability to frontload
deliveries for a potential new project or indeed to backfill a delayed project. And while
at times of excess supply the risk remains that the gas cannot be placed, at least the
downside is limited to no more than the committed capacity charge.
All told, the model may not be fixed and the downside risks around US supply are
undoubtedly greater. But at least portfolios can now be sensibly extended something
that is well illustrated in our opinion by the above consideration of what Sabine Pass
means for the longevity of BG’s current trading portfolio (Figure 66).
Where to price - Oil linkage to remain but with a slice of Hub?
All of this also suggests that if the supply side is to commit capital it needs to be
comfortable that it will be able to achieve a net back price (i.e. that received after
shipping costs) of at least $10-11/mmbtu or nearer $12-13/mmbtu delivered.
In our opinion this argues that we are very unlikely to see a material change in the
current structure for long term contract pricing. For if c$12/mmbtu delivered is the price
required to achieve a sensible return on capital invested, so too must the supplier feel
confident that the price achieved will cover considerable risks associated. Illustrated
below, on the assumption that the industry consensus on the through-cycle oil price
resides at somewhere between $80-$90/bbl this argues for linkage of c13.5-16.0%.
Caps and collars at higher and lower prices aside, it is this band around which we
would expect the price cycle to now revolve. Unsurprisingly, this is very much in line
with the contract terms secured over the past four or so years. For many emerging
customers who are effectively seeking to displace oil with gas (not least China, India
and the Middle East) it is also a formula that makes good sense.
Figure 68: Choose your oil price – but for an industry that needs north of $11/mmbtu
delivered if it is to invest linkage will run at 13%-16%
$70.00
$80.00
$90.00
$100.00
$110.00
$9.00
12.9%
11.3%
10.0%
9.0%
8.2%
$10.00
14.3%
12.5%
11.1%
10.0%
9.1%
$11.00
15.7%
13.8%
12.2%
11.0%
10.0%
$12.00
17.1%
15.0%
13.3%
12.0%
10.9%
$13.00
18.6%
16.3%
14.4%
13.0%
11.8%
$14.00
20.0%
17.5%
15.6%
14.0%
12.7%
Or is there an alternative structure? Perhaps, where US LNG is undoubtedly important
as an alternative source of supply and a potential source of tension in price
negotiations, what it really offers utility buyers is an alternative form of pricing – and
one that need not move in sync with the oil price. Given the price required to attract
non-US supply, however, more challenging in our opinion is quite what the form would
be. Hub-plus is obvious, but Hub plus what? Assuming somewhere between $45/mmbtu remains a sensible perception of the long run US gas price if the increment
isn’t at least a fixed $6/mmbtu we struggle to see supplier acceptance. The economics
simply don’t work.
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An attractive end market offering strong growth potential
In summary, given our analysis of the likely development of the LNG industry over the
next 10-15 years we would make the following general observations.

In the near term, the market short supply through at least 2015 and potentially
2018 – strong positive for arbitrageurs and portfolio players. Global economic
collapse could undermine, but in essence the LNG market looks almost certain to
remain short supply through at least 2016 with potential upside should the major
Australian developments suffer push back. For the portfolio players, such as BG and
Total, this represents a source of significant profit upside (Figure 69).

At 5% CAGR, demand expected healthy through 2025. Supported by the move
towards lower carbon energy and augmented by the, at best, delay in nuclear
investment we expect demand for LNG to remain robust through 2025, with growth
compounding at c5% out through 2025. Key to the growth will be the expansion of the
Chinese and Indian markets, suggesting that relationships with counterparties in these
countries will be of advantage in sealing contracts and gaining position. Given Shell’s
relationship with CNPC this suggests to us it is very well placed, the company together
with Total also gaining from market access in India. BG Group and Total also appear
favourably positioned given relationships with China’s NOCs.
Figure 69: Portfolio LNG: BG and GDF remain the standout names followed by TOTAL
BG
Chevron
GDF Suez
Shell
mtpa
20.0
18.0
BP
ExxonMobil
Repsol YPF
Total
16.0
14.0
12.0
10.0
8.0
6.0
4.0
2.0
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
Source: Deutsche Bank, Wood Mackenzie GLO

Shale gas a threat but over the coming decade a limited one outside the US.
Perhaps the greatest unknown for the LNG demand growth outlook is the emergence
of shale gas globally. Yet, whilst talk around the threat represented by shale gas is
plentiful, with the possible exception of China none of today’s major LNG importing
geographies looks likely to see the development of shale gas in any meaningful way.
Nor, the US asides, would we expect the emergence of shale gas in other territories to
represent a new source of supply, thereby adding to existing supply competition.
Excepting China, we believe that shale threatens to displace no more than 12mtpa of
existing LNG demand. And where the potential in China is real, more likely is that its
development takes longer than the aggressive forecasts central planners have
suggested with upside to LNG demand estimates through 2025 a likely consequence.
Page 41
17 September 2012
Integrated Oil
Global LNG

Long-term contract prices firming for now but …. The current market short
suggests a window of opportunity for those promoting new projects at this time, with
recent Qatari deals arguing that contract pricing is strengthening. Those able to
progress to FID over the next 12-18 months look well positioned, not least Shell
(Canada, Gorgon expansion and Abadi, Indonesia), BG (Sabine Pass), ENI (possibly
Mozambique), BP (Tangguh T3), Exxon (PNG T3, Gorgon expansion) and Chevron
(Gorgon expansion). However, as companies seek to take FID on projects from new
regions (US, Mozambique, Canada, East Med) competition for demand will intensify
and with it pricing likely erode. We consequently expect contract terms to fade from
c15% of crude today towards 12.5-13% by mid decade (or Hub plus $6-7/mmbtu).

Australia Greenfield pricing itself out of the market. The emergence of East Africa,
the US and, to a lesser extent, the Eastern Mediterranean offers up important new
supply options to meet the strong demand growth with the development costs of new
projects globally suggesting that a minimum net-back price of c$10-11/mmbtu will be
required for projects to go ahead. Whilst this new wealth of supply is needed, the
relative cost of projects across the different regions suggests that Australia is
increasingly pricing itself out of the market, with Russia also uneconomic. Although
Australian expansions look to have robust economics at this time, Greenfield
developments will prove challenged. Better positioned will be Canada followed by US
exports, Mozambique and Tanzania. From a portfolio perspective this favours
development options at ENI (Mozambique), BG/Exxon (Tanzania) and Shell (Canada). By
contrast Shell/CNPC’s Arrow project looks challenged as does the development of
Browse (BP, Shell, Exxon, Chevron). Total/Statoil’s Russian developments
(Shtokman/Yamal) also strike us as very high risk.

US expected to become a significant exporter but development likely to be
contained. We see the US capturing a near 10% share of global supply by 2025. Yet it
need be recognized that because of the $3/mmbtu capacity charge and higher shipping
costs (c$1-2/mmbtu), US exports are competitive but not as competitive as the
headline difference between the Henry Hub price and Asian LNG price would today
suggest. For Asia, in our view Canada looks a better source of supply benefitting from
lower gas costs, lower shipping costs, greater political acceptance and the ability
consequently for the Chinese to play a role and thus facilitate demand. This suggests
that Shell’s Canadian export development with CNPC looks well placed to move past
the FID post.

US exports offer portfolio players chance to renew portfolios and so extend life of
what have been wasting assets. A decided positive for the portfolio players not least
BG, Shell and Total all of whom we would expect to take US export capacity both to
trade and to seed future developments.

Oil-linked pricing makes sense. Contract prices may shift to incorporate Hub plus
contracts (or indeed NBP plus). But the fixed element will have to be high as economics
don’t work. In the absence of deeper hubs and better storage alternative price hubs
simply don’t work. Oil linked contacts as a proxy for price continue to make strong
sense given both the tendency of gas to be used as a fuel oil substitute in emerging
economies and the expected $10-11/mmbtu breakeven on new developments.

Higher cost breakevens for US LNG argue European pipe players better
positioned. This statement clearly implies we see a controlled build out of US LNG,
that European utility will remain a hesitant US contractor and sense that there will be
less portfolio gas as a % of the overall market than has been the case before. This
should also prove supportive of European gas prices both through the top and bottom
of the cycle given a decline in the proportion of flexible LNG in market. Positive for
European pipe, ENI and Shell.
Page 42
17 September 2012
Integrated Oil
Global LNG
Figure 70: The LNG majors: LNG value in absolute terms on an NPV 10 basis from
existing or post FID projects ($m)
$m NPV10
90000
45%
80000
40%
70000
35%
60000
30%
50000
25%
40000
20%
30000
15%
20000
10%
10000
5%
0%
0
Shell
ExxonMobil
Upstream
BG
Total
Downstream
Chevron
BP
Eni
% Group NAV
Figure 71: The LNG majors: LNG production as % group volumes 2017 vs. 2012
30%
25%
20%
15%
10%
5%
0%
BG
Shell
Total
LNG % group volumes 2012
Chevron
ExxonMobil
BP
Eni
LNG % group volumes 2017
Page 43
17 September 2012
Integrated Oil
Global LNG
The Companies: Overview
Comparing and contrasting the LNG majors – 2017 vs. 2012
Figure 72: Exxon – Steady growth, no trading
2012
Figure 73: Chevron – From nowhere to major player
2017
Gas into
30.0
2012
20.0
20.0
10.0
Marketing
2017
Gas into
30.0
Liquefaction
10.0
Marketing
0.0
Liquefaction
0.0
Ships
Re-gas
Ships
Re-gas
Source: Deutsche Bank; Wood Mackenzie data; all numbers in mtpa
Figure 74: BG Group – Well rounded growth throughout
Figure 75: BP – No progress envisaged through 2017
2012
2017
2012
Gas into
30.0
20.0
20.0
10.0
Marketing
2017
Gas into
30.0
Liquefaction
10.0
Marketing
Liquefaction
0.0
0.0
Ships
Ships
Re-gas
Re-gas
Figure 76: Shell – Big push upstream, trading static
Figure 77: Total – Upstream progress but slowing
2012
2017
2012
Gas into
30.0
20.0
20.0
10.0
Marketing
Liquefaction
10.0
Marketing
Re-gas
Page 44
Liquefaction
0.0
0.0
Ships
2017
Gas into
30.0
Ships
Re-gas
17 September 2012
Integrated Oil
Global LNG
Comparing and contrasting the LNG majors – Side by Side
Figure 78: Gas into LNG in kboe/d – Shell leads but
Figure 79: Re-gas capacity ex US (mtpa) – the broader,
Chevron and BG are the huge movers
the greater the options for access. Shell, Total and BG
2012
kboe/d
700.0
mtpa
10.0
2017
2012
2017
9.0
600.0
8.0
7.0
500.0
6.0
400.0
5.0
300.0
4.0
3.0
200.0
2.0
100.0
1.0
0.0
0.0
BG
BP
Shell
Total
Exxon
Chevron
ENI
BG
Statoil
BP
Shell
Total
Exxon
Chevron
ENI
Statoil
Figure 80: Marketing volumes (mtpa) – Only BG grows as
Figure 81: Shipping capacity (mtpa) – Excludes ships
Sabine Pass volumes start to impact
aligned to projects but BG the stand out trader
mtpa
2012
20.0
mtpa
2017
2012
2017
25.0
18.0
20.0
16.0
14.0
15.0
12.0
10.0
10.0
8.0
6.0
5.0
4.0
2.0
0.0
0.0
BG
BP
Shell
Total
Exxon
Chevron
ENI
Statoil
BG
BP
Shell
Total
Exxon
Chevron
ENI
Statoil
Page 45
17 September 2012
Integrated Oil
Global LNG
Chevron: From nowhere to industry major
More than any of its peers Chevron looks set to transform its position in global LNG
markets over the course of the next five years as it brings onstream some 15.6mtpa
(net) of new capacity not least in Australia. There are of course risks in the intervening
period – most notably that project cost inflation tends to undermine initial return
expectations. However, as annual LNG investment of c$8bn turns to cash generation of
a similar magnitude so we would expect the outlook for sustainable cash flow to
dramatically improve. Moreover, with significant additional resource available for
subsequent pole expansion, the outlook for continued profitable expansion in Pacific
Basin markets is stronger than most could ever hope for. Patience should be rewarded.
Buy.
Electing to invest in two major LNG projects in one country at one time was always
going to be challenging and so we suspect will be the case as Chevron looks to deliver
both 15.6mtpa Gorgon (47.3% and operator) and 8.9mtpa Wheatstone (CVX 72.1% and
operator). As the projects ramp the cash benefits to Chevron as a whole should,
however, be substantial as should will the opportunities for future project expansion. In
effect, Chevron is laying down the infrastructure for what should represent two
significant growth poles for a number of years to come.
Step outside Australia, however, and there is not much else to be seen. As with its
larger peer, Chevron has turned itself into something of a one geography pony. Yet in
fairness what there is should at least afford Chevron good scope for profitable
expansion most particularly the delivery of incremental feedgas into existing plant at
Indonesia’s Bontang for tolling.
We estimate NAV at $122. Our P/E methodology yields $137 (target 10.5x mid-cycle
EPS est of $13/share). Averaging the two is our blended $130/share price target.
Downside risks include Kazakhstan, West African deepwater and of course capex
increases at major projects, not least Australian LNG.
Page 46
17 September 2012
Integrated Oil
Global LNG
Figure 82: Chevron: Portfolio (traded) LNG by source
(mtpa) – Chevron is not a portfolio player
Figure 83: Chevron: Growth options on the cost curve –
largely Australia brownfield
$/mmbtu
mtpa
14
Wheatstone T2
Gorgon T4
2.0
13
1.8
1.6
12
1.4
11
1.2
10
1.0
Angola LNG
9
0.8
8
0.6
7
0.4
0.2
6
0.0
5
2030
2029
2028
2027
2026
2025
2024
2023
2022
2021
2020
2019
2018
2017
2016
2015
2014
2013
2012
2011
2010
Angola LNG
4
0
31
60
91
121
152
182
AB expansion
PB expansion
AB other Greenfield
Australia expansion
Canada LNG
US Brownfield LNG
FLNG
Mozambique
Tanzania
Australian Greenfield
Figure 84: Chevron: Build in cash flow through 2020 from
Figure 85: Chevron: Production bridge to 2017 –
post FID projects and existing facilities
Liquefaction moves from c3 to 19mtpa by 2017
$m FCF
Net cash flow
12000
Onstream 2012
213
ME expansions
mtpa
Development
20
10000
8000
6000
North West Shelf (2.8)
18
Angola LNG (1.9)
16
Gorgon (7.1)
Wheatstone (6.4)
14
4000
12
2000
10
0
8
-2000
2020
2019
2018
2017
2016
2015
2014
2013
2012
2011
2010
2009
2008
2007
2006
2005
2004
0
2003
2
-10000
2002
4
-8000
2001
6
-6000
2000
-4000
2011
2012
2015
2016
2017
Figure 86: Chevron LNG: NPV10 as % overall NPV10
value ($284bn) suggests c11% group is LNG related
Figure 87: Upstream LNG as % group volumes 2012 and
2017. Surge in growth envisaged
Upstream
11%
Downstream
0%
14%
12%
10%
8%
6%
Rest of Group
89%
4%
2%
0%
2012
2017
% Group production
Page 47
17 September 2012
Integrated Oil
Global LNG
ExxonMobil: The ultimate Qatari base load
An industry behemoth it is perhaps remarkable that it is only over the next five years
that Exxon will begin to significantly diversify away from Qatar. Following the cessation
of production in Indonesia, Qatar now accounts for all 16mtpa of Exxon’s LNG capacity.
Over the period to 2017 the addition of 6mtpa of capacity in PNG and Australia will
however significantly diversify the business and add important and well positioned new
poles for future growth. De-bottlenecking in Qatar could also add c1.5mtpa of highly
profitable capacity. Yet, despite recent discoveries with Statoil in Tanzania’s Block 2 for
such a material market player Exxon’s LNG portfolio looks significantly light of growth
options. Hold.
With a c20% share of Qatar’s aggregate capacity through 5 distinct developments
Exxon has very much been the emirates partner of choice, the company’s c16mtpa of
capacity driving estimated free cash flow of c$6bn p.a. The next five years will,
however, see the company strengthen its global position following the delivery of
Papua New Guinea LNG (XOM operated 32.2%) and Gorgon (XOM 25%). Taken
together we estimate that LNG accounts for around $60bn or 15% of group NPV10 and
a not dissimilar proportion of earnings.
The potential for lower cost expansion in Australia and PNG suggests that Exxon should
be capable of driving continued growth into the next decade from projects requiring
lower break-even prices than many Greenfield schemes. Further out however it is hard
not to feel that the Exxon portfolio is very light growth options.
Our $94/share price target is based on NAV implied target of $89 and $98 P/E implied
valuation. Key downside risks include rising taxes, shrinking access abroad and project
delays. Upside risks include major exploration discoveries and a strong recovery in the
US gas price.
Page 48
17 September 2012
Integrated Oil
Global LNG
Figure 88: Exxon: Portfolio (traded) LNG by source (mtpa)
– Exxon is not a player. Qatar is in control
Figure 89: Exxon: Growth options on the cost curve
appear limited but are lower cost expansions
$/mmbtu
mtpa
Scarborough
14
6.0
Gorgon T4
13
5.0
PNG LNG
12
11
4.0
10
3.0
9
8
2.0
7
1.0
6
-
5
2030
2029
2028
2027
2026
2025
2024
2023
2022
2021
2020
2019
2018
2017
2016
2015
2014
2013
2012
2011
2010
Qatargas-2
4
0
RL 3
31
60
91
121
152
182
213
ME expansions
AB expansion
PB expansion
AB other Greenfield
Australia expansion
Canada LNG
US Brownfield LNG
FLNG
Mozambique
Tanzania
Figure 90: Exxon: Build in cash flow through 2020 from
Figure 91: Exxon: Production bridge to 2017 –
Liquefaction (nominal) increases by c6mtpa by 2017
FCF $m
10000
Aggregate cash flow
Onstream 2012
mtpa
Development
25.0
8000
20.0
6000
4000
15.0
2000
Qatargas-1 (1)
Qatargas-2 (4)
0
10.0
RasGas I (1.7)
RasGas II (4.2)
-2000
RL 3 (5)
5.0
-4000
Gorgon (3.8)
PNG LNG (2.2)
2020
2019
2018
2017
2016
2015
2014
2013
2012
2011
2010
2009
2008
2007
2006
2005
2004
2003
2002
2001
2000
-6000
0.0
2012
2014
2015
2017
Figure 92: Exxon LNG: NPV10 as % overall NPV10 value
($406bn) suggests c15% group is LNG related
2017. Growth in line with portfolio
12%
Upstream
15%
10%
Downstream
0%
8%
6%
4%
Rest of Group
85%
2%
0%
2012
2017
% Group production
Page 49
17 September 2012
Integrated Oil
Global LNG
ConocoPhillips
Compared to its peers, ConocoPhillips’ LNG volumes constitute a small portion (7%) of
total volumes and we do not expect that picture to change in the next five years. As of
2011, ConocoPhillips has three operational LNG projects: Kenai (US), which will likely
drop to zero in 2013 unless more gas supplies can be secured, the 2.0mmtpa (net)
Darwin project in Australia, and Qatargas 3, which started up in October 2010 and
quickly reached net peak capacity of 2.3mtpa by mid-February last year.
Between now and 2017, the only incremental LNG project coming on-line is APLNG.
This is a major focus for the company, its single largest project and the single biggest
challenge it faces in terms of balancing its cashflows which at face value do not allow
the scale of capex and dividend commitments to be covered by cashflows. First LNG
from the first 1.9mtpa (net) train is targeted for June 2015, while LNG exports from the
second train (same capacity) are scheduled to commence in early 2016. Brass LNG
(Nigeria) and Greater Sunrise (Australia) scheduled to come online more likely in 2020+
add no more than 3mtpa of capacity.
That said, ConocoPhillips’ LNG projects are based in Australia, Qatar and US, which
enjoy a high degree of diversity and geopolitical stability. We wonder whether in due
course the company could spin or sell a separate LNG business and give the market an
alternate to BG in terms of pure play LNG stock.
We estimate adjusted net asset value at $78 based on a bottom-up analysis of future
cash flows with ROCE/WACC, but apply a 20% discount to arrive at $62. Our analysis of
Return on Capital Employed (ROCE) over cost of capital yields a target P/E of 9x, which
we apply to our mid-cycle EPS estimate of $6.40. Averaging the two methods we arrive
at our blended PT. Risks include project delays/faster progress, cost overruns and
accidents especially in environmentally sensitive lands in Australia.
Page 50
17 September 2012
Integrated Oil
Global LNG
Figure 94: COP: Portfolio (traded) LNG by source (mtpa) –
drops to zero in 2014
Figure 95: COP: Growth options on the cost curve
$/mmbtu
16.0
1.0
0.9
Greater Sunrise
0.8
14.0
mtpa
0.7
Darwin Alaska Valdez
12.0
0.6
0.5
10.0
0.4
Brass
0.3
8.0
0.2
6.0
0.1
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
Qatargas-3
4.0
0
31
60
91
121
152
182
213
244
274
305
335
ME expansions
Nigeria LNG
AB expansion
Iranian LNG
Trin/Egypt/Yemen
PB expansions
AB other greenfield
Australia expansion
Canada/Alaska LNG
US LNG
FLNG
East African LNG
Australian LNG
Venezuela LNG
Russian LNG
Figure 96: COP: Build in cash flow through 2020 from
Figure 97: COP: Production bridge to 2016 – Liquefaction
moves from c4.2 to 7.2mtpa by 2016
4,000
8.0
3,000
7.0
Kenai(0.3)
Qatargas-3 (2.3)
2,000
$M
Australia Pacific LNG (3.2)
6.0
1,000
Darwin (2.0)
5.0
0
mtpa
-1,000
-2,000
4.0
3.0
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
-3,000
Aggregate Cash Flow
Onstream 2012
Development
2.0
1.0
0.0
2011
2016
2017
Source: Deutsche Bank; Wood Mackenzie GEM
Source: Deutsche Bank;
Figure 98: COP: NPV10 as % overall NPV10 value
2017. Barely hits 10%.
LNG PV10 as a %
of Total
Upstream
14%
12%
10%
8%
6%
4%
2%
0%
2012
2017
% of Group Production
Other Upstream
PV10
86%
Page 51
17 September 2012
Integrated Oil
Global LNG
BG: Building out upstream; rejuvenating downstream
Time and again BG has shown itself to be more nimble and appreciative of the
changing trends in global LNG markets than many of its larger peers. Downstream the
portfolio appears better positioned than any of its IOC peers with Sabine Pass volumes
offering scope for rejuvenation whilst upstream the start-up of QGC LNG in 2014 will
dramatically increase the group’s overall exposure to LNG driven value. Growth options
in Tanzania and Australia (T3) also position the company well to continue to profitably
expand via LNG across much of the coming decade. Share price weakness should be
used to build holdings. Buy with a 1700p price target.
We expect LNG to prove a key driver of profits at BG Group into the medium term.
Initially profit growth is expected to arise on the back of a marked uptick from 2013
onwards in profits from LNG trading with downstream performance complimented
from 2014 by a surge in LNG derived upstream income as BG’s 8.5mtpa Australian LNG
starts to ramp. Further gains should in our view then become apparent as Sabine Pass
starts to materially drive downstream volume and with it income growth. Overall we
estimate that by 2017 LNG will represent north of 60% of group earnings from nearer
c40% today.
Of course there are risks, not least that a slowing global economy undermines Asian
LNG demand or that the delivery of QGC is pushed back. Unitization discussions in
Tanzania could also complicate the outlook for development of this option in a timely
fashion. Overall, however, our analysis of the LNG market suggests that strong
underlying market growth bodes very favourably for BG over coming decade.
In building its positions in Australia and Brazil, BG is in the execution phase on two
major developments. There are risks around both timing and delivery of value. Yet with
the shares trading at a 40% discount to our estimate of NAV these appear to us to be
largely in the price. Rather we target a c15% discount to our estimated NPV10 value of
2080p model which drives our target price of 1700p. Risks to our Buy stance include
delays in Australia and Brazil.
Page 52
17 September 2012
Integrated Oil
Global LNG
Figure 100: BG: Portfolio (traded) LNG by source (mtpa) –
BG has started to extend portfolio life
mtpa
20
Figure 101: BG: Growth options on the cost curve –
limited options but look exercisable
$mmbtu
14
18
13
16
12
14
11
12
10
10
9
8
8
6
7
4
Tanzania T1 & 2
QGC Expansion
6
2
5
0
Sabine Pass 3/4
2030
Sabine Pass 1/2
2029
ALNG 4
2028
ELNG 2
2027
ALNG 2/3
2026
2025
2024
2023
2022
2021
2020
2019
2018
2017
2016
2015
2014
2013
2012
Equatorial Guinea
4
0
Nigeria 4/5
31
60
91
121
152
182
213
ME expansions
AB expansion
PB expansion
AB other Greenfield
Australia expansion
Canada LNG
US Brownfield LNG
FLNG
Mozambique
Tanzania
Figure 102: BG: Build in cash flow through 2020 from
Figure 103: BG: Production bridge to 2017 – Liquefaction
moves from c20 to 29mtpa by 2017
FCF $m
Aggregate cash flow
6000
Onstream 2012
FCF $m
Development
16.0
4000
14.0
2000
12.0
0
10.0
Atlantic LNG 1 (0.8)
Atlantic LNG 2&3 (2.2)
ELNG 1 (1)
ELNG 2 (1.1)
QCLNG - T1 (3.8)
QCLNG - T2 (3.8)
8.0
-2000
6.0
-4000
4.0
-6000
2.0
2020
2019
2018
2017
2016
2015
2014
2013
2012
2011
2010
2009
2008
2007
2006
2005
2004
2003
2002
2001
2000
-8000
0.0
2011
2014
2015
2017
Source: Deutsche Bank; Wood Mackenzie GEM
Source: Deutsche Bank;
Figure 104: BG LNG: NPV10 as % overall NPV10 value
2017. Strong growth envisaged
30%
Upstream
18%
25%
20%
15%
Rest of Group
61%
10%
Downstream
21%
5%
0%
2012
2017
% Group production
Page 53
17 September 2012
Integrated Oil
Global LNG
BP: Fallen behind
Whether LNG becomes a greater point of focus for BP in the years to come remains to
be seen. Immediately apparent over the next five or so years, however, is that organic
growth will be negligible both upstream and downstream. No doubt this in part reflects
the company’s historical focus on higher return investment rather than duration cash. It
is, however, hard not to feel that BP has allowed a formerly strong position in a good
growth market to pass it by. There are options for growth, and growth at what should
be decent rates of return. But in totality the portfolio looks somewhat devoid of
opportunity particularly compared with its super-major peers.
BP has a strong incumbent position in LNG. The start-up in 2012 of Angola LNG in
which BP retains a 13.6% interest will, however, likely represent the only material
expansion of its portfolio over the course of the next five or so years. Moreover, looking
across the portfolio the opportunities for growth seem increasingly narrow. Certainly
there is scope for the addition of a further 1-2 trains at Tannguh and we would expect
announcements here over the course of the next 18 months. Options otherwise
however look limited and likely to be at the upper end of the cost curve. Given its
interest in India’s domestic gas market we are perhaps surprised that the company has
not moved more aggressively on acreage in East Africa.
Overall, our strong impression is that BP will likely decide to look more aggressively at
its LNG position over the coming years and move away from its historic bias towards
pipeline gas in local markets. A strong position in US gas markets and historic bent
towards trading also suggests that some greater interest in US exports might be
anticipated. In fairness though, none of these strike us as priorities for the company at
this time.
Our DCF model (9% CoC, 1% growth, 0.9x beta) suggests a fair share price of c480p
and a target multiple of 8x ‘12 EPS equating to a c10% discount to our sector target
(c9x). Risks to our Buy stance include negative litigation news and project delays in
Angola.
Page 54
17 September 2012
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Global LNG
Figure 106: BP: Portfolio (traded) LNG by source (mtpa) –
fades rapidly post 2025
mtpa
5.0
Figure 107: BP: Growth options on the cost curve seem
limited in number but gains from expansion potential
$/mmbtu
14
4.5
Browse
Tangguh T3
13
Angola LNG
4.0
12
3.5
11
3.0
2.5
10
2.0
9
1.5
8
1.0
7
0.5
6
-
2030
2029
2028
2027
2026
2025
2024
2023
2022
2021
2020
2019
2018
2017
2016
2015
2014
2013
2012
2011
2010
5
4
ADGAS
Angola LNG
Atlantic LNG 2&3
Atlantic LNG 4
Damietta
0
31
60
91
121
152
182
213
ME expansions
AB expansion
PB expansion
AB other Greenfield
Australia expansion
Canada LNG
US Brownfield LNG
FLNG
Mozambique
Tanzania
Figure 108: BP: Build in cash flow through 2020 from
Figure 109: BP: Production bridge to 2017 – Liquefaction
(nominal) broadly static at 12mtpa by 2017
FCF$m
Net cash flow
2500
Onstream 2012
mtpa
Development
14.0
2000
12.0
1500
10.0
ADGAS (0.6)
Atlantic LNG 2&3 (2.9)
Tannguh (2.7)*
Angola LNG (0.7)
ADGAS
8.0
1000
6.0
500
4.0
0
2.0
2020
2019
2018
2017
2016
2015
2014
2013
2012
2011
2010
2009
2008
2007
2006
2005
2004
2003
2002
2001
2000
-500
0.0
2011
2012
2015
2017
Figure 110: BP LNG: NPV10 as % overall NPV10 value
2017. Going backwards albeit slowly
Upstream
5%
Downstream
2%
13%
13%
12%
12%
Rest of Group
93%
11%
11%
2012
2017
% Group production
Page 55
17 September 2012
Integrated Oil
Global LNG
Shell: Cash flow to near double by 2017
Already the global leader, the addition of a further 6-7mtpa of upstream oil-linked
capacity by 2017 will see Shell further cement its position in this strongly growing
market. With it will come the delivery of c$12bn per annum of pre-expansion annuity
type cash flows providing the business with ample scope to fund expansion from a
broad set of opportunities. If we were to be critical our comment would be that Shell’s
control over its growth options appears more limited than we might like. Recent deals
at Abadi and Browse emphasize, however, that Shell is becoming more adept at using
its multiple advantages to access new options. Great portfolio, super business. BUY.
This just appears a really well placed business. The industry and technology leader Shell
has done much in recent years to augment an already strong hand. Whether it be
through the buildout of floating LNG or the establishment of relationships with key
customers and resource holders (not least CNPC and the Qatar state), Shell’s approach
to LNG has an increasingly intelligent and more practicable edge to it with a growing
bias towards control. By better use of its strengths Shell is gaining greater control over
its destiny, opening new and often well positioned growth options as it does so.
Already a very material part of the Shell portfolio we estimate the value of the post FID
portfolio at over $80bn on an NPV10 basis and expect the business to account for
approaching c25% of Shell’s net income by 2017 from nearer 20% today. Truly striking,
however, is the scale of the cash build as this already self funding business sees the
start up of new capacity across Australasia through 2017 with pre-investment cash flow
set to broadly double towards $12bn.
In a changing industry Shell feels like a long term winner and one that still holds the
potential for material profit upside with cash flow that should afford investors
significant comfort through this time of economic duress. Nor does it look expensive –
an FCFY of 8%, P/E of 8.4x and DY of 5% are hardly demanding. Targeting a 10%
premium to an 8x 2013 sector P/E we see fair value at 2475p. Risks to our stance
include Alaskan exploration failure.
Page 56
17 September 2012
Integrated Oil
Global LNG
Figure 112: Shell: Portfolio (traded) LNG by source (mtpa)
– Shell needs to extend portfolio life and options to seed
Figure 113: Shell: Growth options on the cost curve – a
good number and decent mix
$/mmbtu
mtpa
14
7.0
Sakhalin T3
Gorgon T4
Abadi FLNG
Shell CNPC
Browse/Arrow/Sunrise
13
6.0
12
5.0
11
4.0
10
3.0
9
8
2.0
7
1.0
6
-
2030
2029
2028
2027
2026
2025
2024
2023
2022
2021
2020
2019
2018
2017
2016
2015
2014
2013
2012
2011
2010
5
4
0
NLNG 6
NLNG Plus
Qatargas-4
31
Sakhalin 2
60
91
121
152
182
AB expansion
PB expansion
AB other Greenfield
Australia expansion
Canada LNG
US Brownfield LNG
FLNG
Mozambique
Tanzania
Figure 114: Shell: Build in cash flow through 2020 from
Figure 115: Shell: Production bridge to 2017 –
Liquefaction moves from c20 to 29mtpa by 2017
$m free cash
14000
Net cash flow
Onstream 2012
213
ME expansions
mtpa
30.0
Development
12000
25.0
10000
8000
20.0
6000
15.0
4000
2000
10.0
0
-2000
5.0
-4000
Brunei LNG (1.8)
MLNG Dua (1.4)
MLNG Tiga (1.1)
NLNG 6 (0.9)
NLNG Base (1.4)
NLNG Expansion (0.7)
NLNG Plus (1.9)
OLNG (1.6)
Qalhat LNG (0.4)
Qatargas-4 (2.3)
Sakhalin 2 (2.9)
Pluto (1.1)
Gorgon (3.8)
2020
2019
2018
2017
2016
2015
2014
2013
2012
2011
2010
2009
2008
2007
2006
2005
2004
2003
2002
2001
2000
Wheatstone (0.6)
Prelude (3.6)
2011
2012
2015
2016
2017
2017
Figure 116: Shell LNG: NPV10 as % overall NPV10 value
2017. Continued growth envisaged
20%
Upstream
21%
19%
18%
17%
Downstream
2%
Rest of Group
77%
16%
15%
14%
13%
12%
11%
10%
2012
2017
% Group production
Page 57
17 September 2012
Integrated Oil
Global LNG
Total SA: Strong and steady growth but options look challenged
The past five years have seen fantastic growth in LNG at Total as plants in Qatar, the
Yemen, Nigeria and Angola have all come onstream adding some 6mtpa of capacity
and the company has substantially expanded its downstream portfolio. The next five
years look likely to offer more of the same albeit this time with a Pacific Basin bias as
GLNG and Ichthys start up. Yet look across the list of options today and whilst the
resource base has to be described as plentiful our concern is that the options will be
hard to execute with positions in Russia (Yamal and Shtokman), Nigeria (Brass and
NLNG) and Pars (Iran) all beset with issues of one type or another. HOLD.
Building on legacy positions in the Middle East and Indonesia Total has successfully
built both significant sources of supply in the Atlantic and Pacific Basins working its
way into opportunities across the globe. In doing so it has established a business which
we estimate today accounts for around 25% of Upstream net income, the cash flows
from which have an NPV10 of c$30bn. At the same time the company has established
itself as one of the larger portfolio players with some 8-9mtpa of portfolio supply (albeit
much of it Qatari sourced). Total consequently looks very well placed to drive excellent
growth from LNG over the next five or so years.
Less certain, however, is the outlook from here given both the geographic bias of
Total’s remaining growth options and the continuing decline of volumes in Bontang (c45mtpa effective and falling). This is not to say that Total does not hold material
opportunities but rather that we are less than convinced that these will come to fruition
in a timely fashion. Consequently, we have to believe that Total will look to source other
opportunities for growth (E Africa)?
We are supportive of many of Total’s more recent strategic moves. Execution risk and
capital build suggest to us however that there is no rush to buy the value. Assuming a
9% WACC and sector growth, our DCF model suggests fair value of €42/share or a 10%
discount to our 9x sector PE target. Upside risks include exploration success off W.
Africa; downside Australian project delays.
Page 58
17 September 2012
Integrated Oil
Global LNG
Figure 118: Total: Portfolio (traded) LNG by source (mtpa)
– Part of that shown has been placed. Is Qatar really
Total?
mtpa
Figure 119: Total: Growth options on the cost curve seem
limited with a bias to difficult territories
$/mmbtu
16.0
10.0
9.0
14.0
Shtokman
Yamal
Angola
LNG
NLNG 7
OK LNG
PARS
8.0
12.0
7.0
6.0
10.0
5.0
4.0
8.0
3.0
6.0
2.0
1.0
4.0
-
0
2030
2029
Yemen LNG
2028
2027
2026
2025
Snohvit
2024
2023
2022
NLNG Plus
2021
2020
2019
2018
NLNG 6
2017
2016
2015
2014
2013
2012
2011
2010
Angola LNG
Qatargas-2
31
60
91
121
152
182
213
244
274
305
ME expansions
Nigeria LNG
AB expansion
Iranian LNG
Trin/Egypt/Yemen
PB expansions
AB other greenfield
Australia expansion
Canada LNG
US BF LNG
FLNG
East African LNG
Australian GF LNG
Venezuela LNG
Russian LNG
Figure 120: Total: Build in cash flow through 2020 from
Figure 121: Total: Production bridge to 2017 –
Liquefaction capacity to grow by c50% by 2017 to
c16mtpa
FCF $m
Aggregate cash flow
7000
Onstream 2012
mtpa
18.0
Development
6000
16.0
5000
14.0
4000
3000
12.0
2000
10.0
1000
8.0
0
-1000
6.0
-2000
4.0
-3000
2.0
2020
2019
2018
2017
2016
2015
2014
2013
2012
2011
2010
2009
2008
2007
2006
2005
2004
2003
2002
2001
2000
-4000
Yemen LNG (3.4)
Qatargas-2 (1.4)
NLNG Plus (1.2)
Qatargas-1 (1)
NLNG Base (0.9)
Snohvit (0.8)
NLNG 6 (0.6)
NLNG Expansion (0.5)
OLNG (0.3)
ADGAS (0.3)
Qalhat LNG (0.1)
Angola LNG (0.7)
GLNG (2)
Ichthys (2.5)
0.0
2011
2012
2015
2016
2017
Figure 122: Total LNG: NPV10 as % overall NPV10 value
2017. Bontang decline offsets gains in Australia
20%
Upstream
18%
19%
18%
17%
Downstream
5%
16%
15%
Rest of Group
77%
14%
13%
12%
11%
10%
2012
2017
% Group production
Page 59
17 September 2012
Integrated Oil
Global LNG
Appendix A: US exports and
European gas
Our comments on US gas exports in the main body of the text focused on the
implications of US LNG exports for Asian markets. In large part this reflects the current
market reality that the demand cycle is being driven by the needs of Asian rather than
European buyers with Asian pricing standing at a significant excess to the
c$1.50/mmbtu shipping premium required to move a cargo from Europe to Asia. As
seen through the 2008-10 downturn in global gas markets, however, this need not
always prove the case. Satisfy the Asian market and the marginal cargo will revert to
the next high priced regional market, namely Europe.
So what should we expect to happen in European gas markets as and when Asian
demand is saturated, not least at times of an economic downturn or indeed should a
genuine short appear in European gas markets (unlikely though this may seem at the
present time)?
Dealing with the latter first, logic dictates that in the event of the European market
being short gas it would have to compete with Asia for the marginal LNG molecule. To
the extent that non-committed volumes exist in the US we would expect these to be
diverted towards Europe provided that the net back to the supplier was higher in
Europe than in Asia. With the difference in shipping costs from the Eastern Seaboard at
the present time standing at around $1.50/mmbtu this would suggest that as the delta
in price between the two regions moved below this number, Europe would become the
preferred end destination. Assuming that sufficient flexible LNG existed this argues that
spot gas in Europe is always likely to trade at a $1/mmbtu plus discount to Asia.
More interesting however from our perspective is what should we expect to happen
through a downturn? For as the 2008/9 period has taught us, with a very substantial
proportion of Europe’s gas bought via pipeline on the basis of long term oil-linked
contracts with minimum call off requirements, European buyers will try to reduce
purchases to the minimum contractual level by sourcing cheaper supply from spot
markets thereby displacing pipeline demand and attracting LNG.
Figure 124: LNG: Share of European gas markets has
swings depending upon the price signal
LNG bcm
100.0%
89.0%
90.0%
Pipeline bcm
88.8%
85.4%
82.9%
81.2%
84.7%
87.6%
Figure 125: Over the past five years Qatari imports have
been key. Non-Qatar has proven far less fluid
40.0
80.0%
Non-Qatar
38.4
38.1
36.3
35.4
34.6
35.0
70.0%
60.0%
30.0
50.0%
25.0
40.0%
20.0
32.1
29.7
27.0
11.0%
11.2%
14.6%
17.1%
18.8%
15.3%
12.4%
10.0
5.5
6.0
5.0
10.0%
0.0
0.0%
2007
2008
Source: Deutsche Bank; BP Stat Review
Page 60
25.8
14.0
15.0
30.0%
20.0%
Qatar
mtpa
45.0
2009
2010
2011
2012E
2013E
2007
2008
2009
2010
2011
2012 Ann
Source: Deutsche Bank; US EIA
17 September 2012
Integrated Oil
Global LNG
It is this phenomenon, as much as anything that was responsible for the growth in
LNG’s share of the European gas market over the 2008-11 period (although Qatar’s
decision to withhold spot supplies from Asian markets as it sought to achieve premium
priced long term contracts undoubtedly aggravated the position). It is also the flexibility
of this supply that has helped support gas prices in Europe at this time with LNG
backing out of European markets as Asia’s need has risen, much to the volume benefit
of Europe’s pipeline suppliers.
Clearly to the extent that Asia no longer requires the marginal gas molecule our
expectation would be that US exports that are non-committed will flow to European
markets, very much akin to the experience of the past few years. On the face of it the
simple conclusion might, therefore, be that US LNG represents an incremental threat to
downside prices. In many respects, however, we suspect that the reality is probably the
opposite. This reflects the simple observation that because US LNG is sourced at a 15%
premium to the headline Hub gas price (in stark contrast to the multitude of existing
contracts which were priced at a c15-20% discount to Hub), it almost certainly
represents the highest VARIABLE cost source of LNG for trading across the globe.
Thus using BG’s off-take from Cheniere as an example, our expectation is that the
volumes would seek entry into the UK until the European spot price had fallen to
variable cost of US supply or in BG’s case 115% of the Hub gas price plus variable regas (c$0.1/mmbtu) together with the variable shipping costs (which because BG’s boats
are already owned or chartered is unlikely to be more than $0.30/mmbtu). Note that
because the $3/mmbtu capacity charge is payable whatever, i.e. is a sunk cost, it
should have no influence on bottom of cycle prices. At today’s prices this would
suggest a price at which US LNG would effectively shutter of c$3.85/mmbtu (ie
$3.0/mmbtu hub, $0.45/mmbtu premium, $0.1/mmbtu variable re-gas and shipping of
c$0.30/mmbtu).
Contrast this with supply from elsewhere in BG’s portfolio and depending upon location
and shipping costs, US LNG almost certainly has a break-even price some $0.90/mmbtu
above its existing contracts for supply. We would also note that relative to Qatar’s
integrated projects the difference is even more stark, at around $3/mmbtu.
The positive for European gas suppliers through all of this is thus that as the arbitrage
model shifts over the longer term from sourcing LNG at a discount to Hub to one which
effectively sources at a premium, so too does the floor price for Europe’s gas prices
look set to appreciate. This seems particularly so as Qatar continues to commit an
increasing proportion of its production under long-term contracts to Asia thereby
reducing the flexibility of its existing supply and the proportion of LNG that is likely to
land in Europe through a global economic downturn.
As ever the more important question not least for Europe’s pipeline suppliers therefore
is to what extent US-sourced LNG proves to be truly flexible or is developed with
European end markets in mind? Frustratingly, the issue here yet again comes back to
utility customer’s confidence in the long term outlook for both oil and gas prices and
their willingness to commit to a $3/mmbtu capacity charge. In essence, however, our
very strong view is that with US sourced gas competitive with that derived against an
oil linked contract (typically c11-13% of crude) European utility buyers should be
contracting to buy in US volumes.
Undoubtedly, there is price risk associated with this conclusion. But looking at the
below table it strikes us that, absent a total collapse in European gas prices, the price
risk is at the margin with European contracted gas at a long run $80/bbl and 11%
linkage (or $8.80/mmbtu) equating to a US gas price which, at $4.40/mmbtu is in line
with the estimated equilibrium price for US shale breakeven. From the perspective of
supply diversity let alone adding tension in price negotiations with European suppliers,
this argues that sourcing US gas must be deemed a sensible option.
Page 61
17 September 2012
Integrated Oil
Global LNG
Figure 126: US CIF to Europe pricing based on most recent Cheniere’s contracts
Hhub price
2.00
3.00
4.00
5.00
6.00
7.00
Energy cost (15%)
0.30
0.45
0.60
0.75
0.90
1.05
Capacity charge
3.00
3.00
3.00
3.00
3.00
3.00
FOB cost
5.30
6.45
7.60
8.75
9.90
11.05
Shipping
0.80
0.80
0.80
0.80
0.80
0.80
CIF cost
6.10
7.25
8.40
9.55
10.70
11.85
$8.80
$8.80
$8.80
$8.80
$8.80
$8.80
Oil linkage at 11% of $80/bl
Moreover, we are also acutely conscious of the fact that not only is Europe’s indigenous
gas supply faltering as production in the UK, Netherlands, Denmark and elsewhere
continues to decline. Having signed heads of agreement for at least 8mtpa of LNG with
Asian buyers over the past twelve months and with further commitments almost certain
to follow, Qatar’s flexibility is also rapidly fading if only because it was Qatar more than
any other country that was responsible for the substantial build in LNG supplied into
Europe through the last downturn (Figure 125). Europe is therefore going to find itself in
need of other sources and whilst the Caspian region certainly offers scope, we would
be surprised if this were deliverable into Northern Europe at a price much different from
that for US LNG.
The obvious threat for Europe’s pipe players in all of this is that the build out of US LNG
drives a significant increase in spot market gas or, because it represents an alternative
source of long term contract supply, strengthens European buyers negotiating position
on the pricing of long term supply. Yet given the size of the European gas market
(c17.65 tcf or 350mtpa) and the death of alternative sources of Atlantic Basin supply
post the US shale gas revolution (there is verging on nothing in the hopper as schemes
in Nigeria, Angola, Brazil and others have become more challenging to implement) we
find it hard not to question just how material the impact of US LNG is likely to be – over
the short to medium term at least. Assuming a controlled build out as discussed earlier
our perception is that whilst the addition of US LNG may well curb upside to pricing,
European focused volumes – either through utility purchases or via the portfolios of the
traders – are unlikely to be especially large. Moreover, as stated above, with Qatar now
placing supply long term with Asia, Europe will in time need additional sources of gas.
To the extent that those from the US will shut in at higher prices this also argues in
favour of a higher price for European gas at the trough of future cycles.
All told therefore, we don’t doubt that whether it be Gazprom, Statoil or Sonatrach, all
will regard US LNG as something of a threat. Price upside may well be curbed. Absent a
far larger build out than we think is ever likely the consequences are, however, likely to
be far more modest than many may fear.
Page 62
17 September 2012
Integrated Oil
Global LNG
Appendix B: US supplier
economics
Sabine Pass - what does it tell us about capacity charge flex?
With the US gas price trading at just under $3/mmbtu and landed LNG in Tokyo Bay at
nearer $15/mmbtu it is all too easy to observe the c$12/mmbtu price differential and
assume that US LNG must be a slam dunk winner. But what is the actual cost of
delivering LNG to from US to Asian shores actually likely to be?
In our opinion, with Cheniere expected to take the final investment decision on the first
US export scheme over the coming weeks the potential costs of US exports are now
becoming ever more apparent. For the first 9.0mtpa of the project Cheniere has guided
towards a capital cost of $4.5-5.0bn excluding interest charges. The company has also
pre-sold some 16.0mtpa of capacity to four off-takers at an average charge per mmbtu
of $2.72 (with the price per mmbtu ranging from $2.25/mmbtu for the founder contract
with BG Group to $3.00/mmbtu for the final three contracts for 9mtpa) with each
molecule of gas charged at a rate of 115% of the monthly Henry Hub gas price (the
excess covering energy costs and the costs of sourcing and delivering gas).
Cheniere expects to be able to take the final investment decision on Sabine Pass over
the coming months with LNG delivered from the first two trains over the 2015/16 years.
Thus assuming it is able to deliver its plans on time and in line with budget what does
this tell us about the minimum level of capacity charge that a US liquefaction utility
would likely be willing to accept if we assume that it requires at least a 10% rate of
return in order to commit to the capital build?
Using the details highlighted above we show overleaf our project model together with
the main assumptions, not least that opex per molecule costs $0.3/mmbtu,
maintenance capex runs at $25m p.a. and that the company is liable to federal tax at
35% and state tax at 8% with tax depreciation run on an accelerated MACRS basis.
Interestingly, the model suggests that at a $2.25/mmbtu capacity charge – in essence
that paid by BG on its initial contract – Cheniere would deliver a rate of return of exactly
10% on the project. Given the importance to Cheniere in our opinion of attracting a
heavyweight industry player to afford others confidence and get the project off the
ground our impression is that BG likely pushed the company has far as it would go.
Similarly, it suggests to us that with the return rising to nearer 15% at a capacity charge
of $3/mmbtu competition for the second two trains was likely quite intense. Whilst this
is not to say that the model need be correct, what it suggests to us is that absent a
large (and to be frank unexpected) reduction in build costs, $2.25/mmbtu is the lowest
one could sensibly assume the capacity owner to charge. Equally, however, there is
scope for $3/mmbtu to see some erosion – build costs permitting.
What does it all mean? Very simply that where the US gas price may show true
variability over the forecast period, capacity charges are unlikely to show the same
degree of flex although some downside ($2.75/mmbtu?) looks possible. But then this
would require construction costs to be no greater than those for Cheniere. And as
anyone who follows this industry knows, first to build in an emerging market tends to
get the best EPC deal. Just look at what has happened in Australia!
Page 63
17 September 2012
Integrated Oil
Global LNG
Figure 127: Sabine Pass Operating Model
Capex/tonne ($)
Federal tax (%)
$556
Tonne capacity (mtpa)
Fee per mmbtu ($)
NPV10
$245m
IRR
11.0%
9.0
State Tax (%)
8%
$2.37
Mscf/mmbtu
1.04
Committed mmbtu
396
Tax Depn
Opex per mmbtu ($)
$0.3
Capex total
11%
Operating rate
Assumed energy (% gas)
Maintenance capex
35%
MACRS
$5.0bn
90%
$25m
Gas in
(mscf/d)
Capacity
charge ($m)
Capex
($m)
Opex
($m)
State
tax $m
Pre-Federal tax
$m
Federal
Tax $m
Cash flow
$m
2012
625
-625
2013
1250
-1250
2014
1250
IRR
%
-1250
2015
305
877
1250
111.2
61
-545
0
-545
2016
914
877
625
111.2
61
80
0
80
2017
1219
877
25
111.2
61
680
0
680
2018
1219
877
25
111.2
61
680
0
680
2019
1219
877
25
111.2
61
680
0
680
-12%
2020
1219
877
25
111.2
61
680
0
680
-5.3%
2021
1219
877
25
111.2
61
680
0
680
-1.0%
2022
1219
877
25
111.2
61
680
0
680
2.1%
2023
1219
877
25
111.2
61
680
0
680
4.4%
2024
1219
877
25
111.2
61
680
230
449
5.6%
2025
1219
877
25
111.2
61
680
230
449
6.6%
2026
1219
877
25
111.2
61
680
230
449
7.4%
2027
1219
877
25
111.2
61
680
230
449
8.0%
2028
1219
877
25
111.2
61
680
230
449
8.6%
2029
1219
877
25
111.2
61
680
230
449
9.1%
2030
1219
877
25
111.2
61
680
230
449
9.5%
2031
1219
877
25
111.2
61
680
230
449
9.8%
2032
1219
877
25
111.2
61
680
230
449
10.1%
2033
1219
877
25
111.2
61
680
230
449
10.3%
2034
1219
877
25
111.2
61
680
230
449
10.5%
2035
1219
877
25
111.2
61
680
230
449
10.7%
2036
1219
877
25
111.2
61
680
230
449
10.8%
2037
1219
877
25
111.2
61
680
230
449
11.0%
SUM
9791bcf
20173
5525
2558
1409
13806
3225
$245M
Figure 128: Sabine Pass – Sensitivity analysis of capex ($/mtpa) and capacity charge ($/mmbtu) on NPV10 and IRR %
IRR %
$450
$2.00
11.1%
$2.25
12.8%
$2.50
14.7%
$2.75
$500
$550
$600
$650
$700
$750
NPV10
$450
$500
$550
$600
$650
$700
$750
9.7%
8.6%
7.6%
6.7%
6.0%
5.3%
$2.00
227
(60)
(351)
(647)
(947)
(1,250)
(1,557)
11.4%
10.2%
9.1%
8.2%
7.4%
6.7%
$2.25
583
316
44
(234)
(517)
(806)
(1,099)
13.1%
11.9%
10.7%
9.8%
8.7%
8.0%
$2.50
978
721
464
202
(67)
(408)
(683)
16.8%
14.8%
13.4%
12.2%
10.9%
10.1%
9.3%
$2.75
1,445
1,106
859
612
272
19
(241)
$3.00
18.5%
16.7%
14.8%
13.6%
12.6%
11.3%
10.5%
$3.00
1,808
1,573
1,234
997
761
420
177
$3.25
20.0%
18.1%
16.6%
14.9%
13.8%
12.5%
11.7%
$3.25
2,149
1,927
1,701
1,362
1,136
796
568
$3.50
21.9%
19.4%
17.9%
16.5%
14.9%
13.9%
12.7%
$3.50
2,589
2,258
2,045
1,829
1,490
1,274
934
$3.75
23.1%
21.2%
19.0%
17.6%
16.4%
15.0%
14.1%
$3.75
2,889
2,698
2,368
2,163
1,957
1,618
1,412
Page 64
17 September 2012
Integrated Oil
Global LNG
Appendix C: Shipping in brief
Those relying on short term charters risk losing upside
The consequences of the loss of nuclear in Japan have been significant for LNG charter
rates. With limited new fleet capacity anticipated onstream over the 11-13 period the
increase in cargoes flowing to Asia has significantly increased shipping times as well as
demand for charters. As a consequence shipping rates since early 2011 have increased
markedly, moving from around $30k/day in 2010 to nearer $130k/day currently. Whilst
the increase in rates will likely have minimal impact on those who either own ships or
have contracted capacity under long term charter the volatility should not impact.
However, any trader looking to charter ships on a short term basis is likely to have
faced significant pain in recent quarters.
Given the build anticipated over the period to 2014, shipping is not expected to prove
an ongoing constraint for LNG deliveries. The volatility in spot rates does, however,
raise some points of note not least for US exports with spot rates at c$4.40/mmbtu
almost $2/mmbtu above the long term and eating significantly into spot delivery upside.
By implication this suggests that if US exporters wish to capture potential upside, they
would be well advised to commit to charters. As added costs we suspect this will likely
further serve to reduce the number of those committing to take US LNG.
Figure 129: Freight rates are currently almost twice the
Figure 130: The build in capacity suggests that shipping
long run average at c$130k/d
should only prove a temporary bottleneck
$k/day
160
60
No.
<50,000
100,000-149,999
200,000-249,999
Capacity (mm3) - RHS
140
50
mm3 capacity
50,000-99,999
150,000-199,999
250,000+
80
70
120
60
40
100
80
50
30
40
60
30
20
40
20
20
10
10
0
Q1 13
Q2 12
Q1 12
Q4 11
Q3 11
Q2 11
Q1 11
Q4 10
Q3 10
Q2 10
Q1 10
Q4 09
Q3 09
Q2 09
Q1 09
Q4 08
Q3 08
0
0
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
Figure 131: Estimated shipping distances, boil off and costs
Country
from
Port
At Sea
(days)
Miles
Charter
return ($)
Boil
off ($)
Total
cost ($)
Cost per
mmbtu
Spot
(today)
To Tokyo
Australia
Barrow
8
3727
1500
524
2024
0.65
1.13
Australia
Curtis
8
3860
1500
524
2024
0.65
1.13
Mozambique
Maputo
16
7594
2700
1048
3748
1.20
2.07
US GC via Panama
Sabine Pass
19
9209
3150
1245
4395
1.41
2.42
US GC via Cape
Sabine Pass
35
16754
5550
2293
7843
2.51
4.29
Canada
Kitimat
8
3954
1500
524
2024
0.65
1.13
Indonesia
Jakarta
5
2511
1050
328
1378
0.44
0.78
US East
Sabine Pass
10
4588
1800
468
2268
0.73
1.30
Qatar
Doha
13
6091
2250
608
2858
0.92
1.64
To UK Milford Haven
Source: Deutsche Bank Note for cost we assume 0.3% oil off pr day at $14/mmbtu Japan/$10/mmbtu Uk. Charter rates are taken at $75k per day for mid cycle
but c$140 at spot. We assume 20 knots per day and that it takes 2 days to load and 2 days to discharge cargoes.
Page 65
17 September 2012
Integrated Oil
Global LNG
Appendix D: Portfolios & options
Chevron – Staggering growth to come but very narrow focus
Figure 132: Chevron: LNG infrastructure by 2017. Limited infrastructure but very big
positions. Dramatic growth to come
Figure 133: Chevron: Growth options in 2012 largely East facing and with decent
economics given status is largely as expansions
Page 66
17 September 2012
Integrated Oil
Global LNG
Exxon – Building out from its Qatar dominated base
Figure 134: Exxon: LNG infrastructure by 2017 – Very clear focus. What to do if Qatar
stands still?
Figure 135: Exxon: LNG growth options as at 2012 – a decent clutch in the Pacific but
not as broad as one would hope given the company’s status
Page 67
17 September 2012
Integrated Oil
Global LNG
ConocoPhillips
Figure 136: ConocoPhillips: LNG infrastructure by 2017
1
3
*Freeport LNG 6.8mtpa
*Golden Pass LNG 1.9mtpa
4
2
4
LNG Plant (onstream)
LNG plant in progress
Regas facility
ConocoPhillips – LNG infrastructure 2017E
1.Kenai (1969) – 1.5mtpa, COP
has a 100% interest, export
license expires in 2013
3. Qatar Gas-3 (2010)–
7.8mtpa, COP has a 30%
interest in liquefaction
2. Darwin (2005) – Single
train facility with a capacity of
3.7mtpa, COP has a 56.9%
interest in upstream and
liquefaction
4. AP LNG (2015)– Two train
9mtpa facility, COP owns
37.5% in liquefaction
*LNG Import facilities
Figure 137: ConocoPhillips: LNG growth options as at 2012
4
7
4
3
1
2
1
LNG growth
option
ConocoPhillips LNG – Growth options
1. AP LNG (2015)– Two train 9mtpa
facility, COP owns 37.5% in
liquefaction
2. Greater Sunrise (2021)–
Proposed 4mtpa, COP has a
30% interest in upstream and
liquefaction
3. Brass LNG (2020)– Proposed
10mtpa, COP has 20% interest in
Upstream, 17% interest in the
liquefaction plant
4. Alaska Valdez(2023)–
20mtpa proposed, COP owns
36.1% in Upstream
Page 68
17 September 2012
Integrated Oil
Global LNG
BG Group – Expanding position, east facing options
Figure 138: BG: LNG infrastructure by 2017 – far more modest than the majors but so
too is its size
Figure 139: BG Growth options – Relatively well placed with potential in Canada to
come?
Page 69
17 September 2012
Integrated Oil
Global LNG
Shell – Footprint dwarfs peers, as do options
Figure 140: Shell: LNG infrastructure by 2017 – Very broadly based with a strong Pacific
focus
Figure 141: Shell: LNG options 2012 – Multiple but how much control?
Page 70
17 September 2012
Integrated Oil
Global LNG
BP – Broad legacy position but limited growth potential
Figure 142: BP: LNG infrastructure by 2017 – Really let slip a very strong position
Figure 143: BP: LNG Growth options – Startling in their absence. East Africa must be of
appeal not least given Indian bias
Page 71
17 September 2012
Integrated Oil
Global LNG
Total – A decade of reinforcement now slows. Difficult options
Figure 144: Total SA: LNG infrastructure by 2017. Company has done a superlative job
on positioning over the past decade
Figure 145: Total SA: Growth options 2012 - more worrying are the options for future
growth which look to be in difficult to execute markets and overly Atlantic basin
Page 72
17 September 2012
Integrated Oil
Global LNG
Sector Investment Thesis
Outlook
In our recent sector review we argued that far from being structurally broken the
integrated model remained relevant, that the sector had been undergoing a period of
strategic and operational transition, and that sentiment toward a materially undervalued
group should begin to improve driven by expected growth in volumes, cash and
exploration activity. 2012 should prove a key staging-post for this thesis as the sector
shows the first signs of operational rejuvenation. First, after a decade of stagnant
volumes we expect the broad-based delivery of modest production growth. Seeing is
believing; but even allowing for ‘normal’ slippage we expect the group to return a
sentiment boosting uptick in volumes. Second, leveraging margin accretive barrel
growth we forecast a 15% expansion in OCF by 2015 at constant oil prices driving a 2025% increase in FCF (ex WC/A&D). Third, 2011 was a vintage year with the drill-bit. We
expect another robust year in 2012 as the Majors continue to increase investment in
exploration and with a greater emphasis on frontier plays. Re-rating will likely require
sustained evidence of improved performance, but as operational momentum builds we
believe that the scene is set for a period of improved share price performance.
Valuation
We use several earnings and cash flow valuation techniques to value the oils. These
include P/E relative, cash return on capital analysis (CROCI), discounted cash flow
models, Free Cash Flow Yield and a cash-flow asset valuation based Sum-of-the-Parts.
The absolute valuation of the sector presently appears attractive: (1) the group trades at
an aggregate c39% discount to SOTP with asset disposals made across the past year
suggesting that our asset-valuation is conservative relative to the asset-market. (2) the
group trades at just 0.78x 2012e Net Capital Invested, consistent with the level of
economic profitability registered at the 2009 trough, but c20% below the multiple
consistent with our forecast for 2012 CROCI/COC and at odds with our assessment of
potential returns on reinvestment. On a market relative basis we observe that the 12
month forward consensus PE of the sector stands at just 0.77x the market as compared
to a trailing 10-year average of 0.88x. Furthermore, with the sector balance sheet robust
and limited absolute downside we regard the sector as defensive in the event of any
market pull-back. Aggregating our company target prices implies a 2012E sector target
PE multiple of 9.7x and a sector target EV/NCI of 1.0x compared to a long-run average
closer to 1.3x.
Risks
As ever, the key risk to our estimates remains the outlook for commodity prices and
crude oil in particular. Specifically, we note exposure to evolving expectations for
economic growth in the key consuming countries and to expectation around the
behaviour of OPEC particularly in light of geopolitical tensions in the MENA region.
Thus our forecasts are consequently vulnerable to moves in the price of crude about our
$107/bbl 2012 oil price estimate. As a sector whose functional currency is the US dollar,
a sharp fall in that currency would be counter to our current expectations and could
significantly undermine asset values and the local currency value of dividend payments.
Considering company-specific factors we note that equity value will be sensitive to
perceived changes in economic/fiscal conditions in key countries of operation, to the
physical risks inherent in an asset intensive business, and to the risks borne of the
environmental challenges directly associated with producing crude oil and gas.
Page 73
17 September 2012
Integrated Oil
Global LNG
Figure 146: Valuation Comparison
Ticker
Company
Super Majors
BP.L
BP
CVX.N
Chevron
XOM.N
ExxonMobil
RDSa.L
Royal Dutch Shell a
RDSb.L
Royal Dutch Shell b
TOTF.PA Total SA
Average
North American Mid-Majors
COP.N
ConocoPhillips
HES.N
Hess Corporation
MRO.N
Marathon Oil
MUR.N
Murphy Oil
OXY.N
Occidental Petroleum
SU.TO
Suncor Energy
CNQ.TO Canadian Natural Resources
Average
North American E&P
APA.N
Apache Corporation
APC.N
Anadarko Petroleum
CHK.N
Chesapeake Energy
DVN.N
Devon Energy
ECA.TO
Encana Corporation
EOG.N
EOG Resources
NFX.N
Newfield Exploration
NBL.N
Noble Energy
PXD.N
Pioneer Natural Resources
RRC.N
Range Resources
SWN.N
Southwestern Energy
UPL.N
Ultra Petroleum
Average
European Mid-majors
BG.L
BG Group
ENI.MI
Eni
REP.MC
Repsol
STL.OL
Statoil
Rec
Buy
Buy
Hold
Buy
Buy
Hold
Hold
Hold
Buy
Hold
Buy
Hold
Hold
Buy
Buy
Hold
Hold
Hold
Buy
Hold
Buy
Hold
Hold
Hold
Hold
Buy
Buy
Hold
Hold
Share Price
GBp
$
$
GBp
GBp
EUR
$
$
$
$
$
C$
C$
$
$
$
$
C$
$
$
$
$
$
$
$
GBp
EUR
EUR
NOK
451.50
117.14
91.91
2254.50
2319.50
41.42
58.30
55.48
30.81
55.63
90.06
34.02
33.13
92.10
74.17
20.17
63.14
22.38
116.39
34.89
95.05
112.02
69.44
34.45
23.30
1291.00
18.51
16.56
153.80
Price Target NAV/Share
480.0
130.0
94.0
2475.0
2475.0
42.0
60.0
50.0
32.0
56.0
125.0
37.0
32.0
110.0
91.0
23.0
71.0
20.0
125.0
40.0
115.0
124.0
65.0
35.0
25.0
1700.0
21.0
15.5
170.0
806
125
75
4198
4198
58
81
59
39
75
113
35
41
119
119
33
81
23
150
38
121
124
65
33
25
NA
NA
NA
NA
Market
Cap
(US$bn)
137.69
229.76
425.60
226.86
233.40
130.61
73.29
18.88
21.85
10.84
72.80
53.37
36.93
37.14
37.10
15.15
25.54
16.67
31.43
4.69
17.11
13.98
11.10
12.01
3.57
70.15
93.36
29.64
87.42
Average
Ticker
Company
Super Majors
BP.L
BP
CVX.N
Chevron
XOM.N
ExxonMobil
RDSa.L
Royal Dutch Shell a
RDSb.L
Royal Dutch Shell b
TOTF.PA Total SA
Average
North American Mid-Majors
COP.N
ConocoPhillips
HES.N
Hess Corporation
MRO.N
Marathon Oil
MUR.N
Murphy Oil
OXY.N
Occidental Petroleum
SU.TO
Suncor Energy
CNQ.TO Canadian Natural Resources
Average
North American E&P
APA.N
Apache Corporation
APC.N
Anadarko Petroleum
CHK.N
Chesapeake Energy
DVN.N
Devon Energy
ECA.TO
Encana Corporation
EOG.N
EOG Resources
NFX.N
Newfield Exploration
NBL.N
Noble Energy
PXD.N
Pioneer Natural Resources
RRC.N
Range Resources
SWN.N
Southwestern Energy
UPL.N
Ultra Petroleum
Average
European Mid-Majors
BG.L
BG Group
ENI.MI
Eni
REP.MC
Repsol
STL.OL
Statoil
Average
Page 74
Price/Earnings Ratio (x)
2011
2012E
2013E
EV/DACF
2011
2012E
2013E
EV/EBITDA
2011
2012E
EV/ 1P
Reserves
2013E
$/boe
6.2
7.6
9.7
8.7
8.8
7.8
8.1
9.1
12.3
9.2
9.2
8.1
8.0
9.2
11.1
8.5
8.6
7.7
4.3
4.8
7.1
5.7
5.7
4.6
7.2
6.1
7.7
5.6
5.6
5.7
5.7
5.9
7.7
5.3
5.3
5.4
3.8
3.7
5.7
5.2
5.2
3.3
4.3
4.3
6.3
5.5
5.6
3.6
6.2
4.4
7.4
5.1
5.2
3.4
9.9
19.7
17.4
17.5
18.0
13.2
8.1
9.3
8.8
5.4
6.3
5.9
4.5
4.9
5.3
16.0
6.3
11.9
6.6
10.6
11.4
10.4
18.1
10.3
10.1
11.7
10.2
12.9
11.0
15.7
9.5
9.2
9.0
8.0
11.0
9.6
12.7
4.6
5.6
4.5
5.4
6.5
6.2
8.1
6.6
5.7
5.7
4.1
6.7
5.5
6.7
5.3
5.8
4.7
4.0
5.7
4.9
5.8
3.3
4.7
3.4
4.2
5.7
5.7
6.8
4.3
3.8
3.3
3.7
5.6
5.1
6.1
4.2
4.0
3.0
3.5
4.7
4.6
5.2
10.8
16.8
14.6
21.9
24.1
30.3
11.8
10.7
11.7
9.8
5.8
5.9
5.2
4.8
4.6
4.2
18.6
9.3
22.6
10.1
12.5
50.8
26.4
14.9
16.8
21.1
52.7
21.7
16.0
7.6
23.2
44.4
21.0
21.2
26.5
14.4
18.6
28.5
99.7
-94.9
12.2
8.5
16.8
13.6
14.9
36.0
17.3
9.9
13.1
17.6
57.7
20.1
16.7
5.2
16.7
5.8
5.6
6.2
6.6
6.6
7.9
7.9
16.2
8.7
7.7
4.8
5.8
6.5
6.4
7.4
7.1
6.0
7.3
9.8
20.4
8.1
6.8
4.2
4.5
2.8
5.6
7.4
6.1
4.4
6.5
7.7
14.5
7.0
7.6
6.0
9.2
7.7
6.1
5.8
11.4
6.9
9.1
11.8
88.2
9.4
10.1
4.2
5.8
5.0
5.8
81.8
6.7
4.7
6.4
11.1
19.8
21.3
-4.6
3.6
5.0
2.9
5.3
6.9
6.0
4.1
5.6
7.2
14.0
7.0
7.3
16.7
19.2
6.0
10.5
9.9
17.9
11.9
15.2
16.6
16.9
13.9
6.0
20.2
11.2
14.9
7.7
6.9
5.8
8.5
13.5
5.5
13.4
16.7
8.5
14.0
7.6
15.1
8.9
10.9
9.6
12.4
8.5
11.1
9.4
12.8
5.3
6.9
4.0
9.4
4.6
6.4
4.2
8.6
3.8
6.1
4.7
8.6
3.3
5.6
2.0
6.9
2.9
5.6
2.0
6.6
2.4
5.4
2.2
25.9
16.3
21.8
17.9
11.7
11.1
10.3
7.2
6.2
5.8
4.9
4.4
4.2
20.5
Dividend Total Cash
Net Debt/Total Cap.
Yield
Employed (%)
Yield
2012E
2013E
2012E
2012E
Discounted
Oil Price
$/bbl
2011
ROCE
2012E
2013E
94.56
85.44
72.85
79.82
79.82
107.36
86.64
11%
21%
24%
11%
11%
11%
15%
8%
18%
19%
10%
11%
10%
13%
8%
16%
19%
11%
11%
10%
12%
6.0
4.9
7.0
6.1
6.1
4.5
5.8
5.7
6.3
7.7
4.9
4.9
4.7
5.7
4.7
6.0
7.5
4.7
4.7
4.4
5.3
-3%
7%
9%
7%
7%
2%
5%
4%
5%
7%
8%
7%
3%
6%
6%
4%
6%
7%
7%
6%
6%
15%
-6%
1%
7%
8%
16%
7%
14%
-4%
3%
5%
5%
15%
6%
4.4%
3.0%
2.4%
4.9%
4.7%
5.6%
4.2%
4.4%
5.1%
7.0%
4.9%
4.7%
5.6%
5.3%
91.29
102.04
88.06
98.77
101.41
77.23
96.15
93.56
14%
10%
12%
11%
16%
12%
9%
12%
10%
8%
9%
11%
12%
10%
8%
10%
11%
8%
10%
12%
13%
11%
9%
11%
3.9
4.8
3.7
5.7
6.3
5.7
7.0
5.3
5.8
4.4
4.8
3.8
6.3
5.2
5.6
5.1
4.4
4.2
4.0
3.5
5.7
4.7
4.8
4.5
15%
-6%
-9%
-4%
3%
11%
-1%
1%
2%
-7%
-1%
-10%
3%
5%
0%
-1%
6%
-8%
5%
-5%
4%
6%
1%
1%
24%
28%
19%
8%
8%
12%
28%
18%
21%
30%
15%
13%
1%
9%
27%
17%
4.5%
0.7%
2.2%
2.5%
2.4%
1.5%
1.3%
2.2%
11.2%
0.7%
2.2%
2.4%
3.4%
3.5%
1.6%
3.6%
125.07
97.95
118.44
169.27
184.62
136.98
120.01
145.14
163.75
160.18
104.02
160.00
14%
5%
9%
22%
2%
6%
8%
11%
12%
1%
14%
13%
10%
12%
5%
3%
4%
4%
7%
5%
10%
7%
1%
8%
10%
6%
10%
7%
9%
6%
4%
9%
6%
12%
8%
3%
10%
10%
8%
4.5
15.6
3.8
5.1
4.9
5.8
5.0
7.3
7.1
14.7
8.0
6.1
7.3
3.7
4.6
5.4
5.5
5.3
5.6
3.8
6.8
7.5
16.3
6.5
5.0
6.3
3.4
4.1
3.2
4.6
5.5
5.1
2.8
5.8
6.7
12.1
6.4
6.1
5.5
-1%
-9%
5%
-4%
2%
-4%
-8%
-6%
-4%
-8%
-2%
-8%
-4%
-9%
5%
29%
-14%
13%
-3%
-2%
3%
-9%
-9%
-2%
14%
1%
5%
16%
22%
-4%
-9%
-5%
-2%
-8%
-2%
-7%
2%
-1%
1%
26%
33%
7%
21%
45%
28%
41%
13%
37%
56%
29%
67%
33%
21%
17%
-9%
23%
53%
31%
39%
22%
33%
59%
23%
62%
31%
0.7%
0.5%
1.7%
1.3%
3.6%
0.6%
0.0%
0.9%
0.0%
0.2%
0.0%
0.0%
0.8%
0.7%
0.4%
1.7%
1.2%
3.6%
0.5%
0.0%
0.8%
0.4%
5.0%
0.0%
0.3%
1.2%
149.48
95.84
111.51
102.18
114.75
10%
10%
5%
16%
10%
9%
10%
5%
14%
10%
10%
11%
5%
13%
10%
11.4
3.8
6.5
4.0
6.4
8.2
4.0
3.6
5.2
5.2
7.1
3.6
3.7
4.3
4.7
-5%
5%
4%
5%
2%
-1%
20%
4%
4%
7%
-3%
15%
3%
2%
4%
25%
18%
33%
11%
22%
27%
10%
31%
13%
20%
1.3%
5.8%
5.4%
4.3%
4.2%
1.3%
5.8%
-0.7%
4.4%
2.7%
Price/Cash Flow from
Operations (x)
2011
2012E
2013E
Free Cash Flow Yield
2011
2012E
2013E
17 September 2012
Integrated Oil
Global LNG
Appendix 1
Important Disclosures
Additional information available upon request
Disclosure checklist
Company
Ticker
Recent price*
Disclosure
Chevron
CVX.N
117.14 (USD) 17 Sep 12
7,14,15,17
ExxonMobil
XOM.N
91.91 (USD) 17 Sep 12
14,15,17
BG Group
BG.L
1,287.00 (GBp) 17 Sep 12
14,15
Royal Dutch Shell Plc
RDSb.L
2,317.39 (GBp) 17 Sep 12
7,8,14,SD11
*Prices are sourced from local exchanges via Reuters, Bloomberg and other vendors. Data is sourced from Deutsche Bank and subject companies
Important Disclosures Required by U.S. Regulators
Disclosures marked with an asterisk may also be required by at least one jurisdiction in addition to the United States.
See Important Disclosures Required by Non-US Regulators and Explanatory Notes.
7.
Deutsche Bank and/or its affiliate(s) has received compensation from this company for the provision of investment
banking or financial advisory services within the past year.
8.
Deutsche Bank and/or its affiliate(s) expects to receive, or intends to seek, compensation for investment banking
services from this company in the next three months.
14. Deutsche Bank and/or its affiliate(s) has received non-investment banking related compensation from this company
within the past year.
15. This company has been a client of Deutsche Bank Securities Inc. within the past year, during which time it received
non-investment banking securities-related services.
Important Disclosures Required by Non-U.S. Regulators
Please also refer to disclosures in the Important Disclosures Required by US Regulators and the Explanatory Notes.
7.
Deutsche Bank and/or its affiliate(s) has received compensation from this company for the provision of investment
banking or financial advisory services within the past year.
17. Deutsche Bank and or/its affiliate(s) has a significant Non-Equity financial interest (this can include Bonds,
Convertible Bonds, Credit Derivatives and Traded Loans) where the aggregate net exposure to the following
issuer(s), or issuer(s) group, is more than 25m Euros.
Special Disclosures
11. A director of the covered company is a director of Deutsche Bank.
For disclosures pertaining to recommendations or estimates made on securities other than the primary subject of this
research, please see the most recently published company report or visit our global disclosure look-up page on our
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Analyst Certification
The views expressed in this report accurately reflect the personal views of the undersigned lead analyst about the
subject issuers and the securities of those issuers. In addition, the undersigned lead analyst has not and will not receive
any compensation for providing a specific recommendation or view in this report. Paul Sankey
Page 75
17 September 2012
Integrated Oil
Global LNG
Historical recommendations and target price: Chevron (CVX.N)
(as of 9/17/2012)
140.00
Previous Recommendations
120.00
4
100.00
Security Price
Strong Buy
Buy
Market Perform
Underperform
Not Rated
Suspended Rating
6
5
2
80.00
1
3
Current Recommendations
Buy
Hold
Sell
Not Rated
Suspended Rating
60.00
40.00
20.00
*New Recommendation Structure
as of September 9,2002
0.00
Sep 09
Dec 09 Mar 10 Jun 10
Sep 10
Sep 11
Date
1.
10/05/2009:
Hold, Target Price Change USD75.00
4.
01/12/2011:
2.
05/02/2010:
5.
04/11/2011:
3.
06/15/2010:
6.
02/28/2012:
Upgrade to Buy, Target Price Change USD130.00
Historical recommendations and target price: ExxonMobil (XOM.N)
(as of 9/17/2012)
100.00
5
90.00
4
3
80.00
70.00
Security Price
6
12
60.00
Strong Buy
Buy
Market Perform
Underperform
Not Rated
Suspended Rating
50.00
Buy
Hold
Sell
Not Rated
Suspended Rating
40.00
30.00
20.00
10.00
0.00
Sep 09
Sep 10
Sep 11
Date
1.
09/02/2010:
Buy, Target Price Change USD70.00
4.
02/01/2011:
2.
09/13/2010:
Downgrade to Hold, Target Price Change USD65.00
5.
04/18/2012:
Upgrade to Buy, Target Price Change USD100.00
3.
01/12/2011:
6.
07/16/2012:
Downgrade to Hold, Target Price Change USD94.00
Page 76
17 September 2012
Integrated Oil
Global LNG
Historical recommendations and target price: BG Group (BG.L)
(as of 9/17/2012)
1,800.00
4 5
1,600.00
Security Price
1,400.00
1,200.00
6
7
8
3
2
9
10
1
1,000.00
Strong Buy
Buy
Market Perform
Underperform
Not Rated
Suspended Rating
800.00
Buy
Hold
Sell
Not Rated
Suspended Rating
600.00
400.00
200.00
0.00
Sep 09 Dec 09 Mar 10 Jun 10 Sep 10 Dec 10 Mar 11 Jun 11 Sep 11 Dec 11 Mar 12 Jun 12
Date
1.
10/19/2009:
Upgrade to Buy, Target Price Change GBP1,275.00
6.
05/10/2011:
Buy, Target Price Change GBP1,675.00
2.
11/03/2010:
Downgrade to Hold, Target Price Change GBP1,330.00 7.
07/26/2011:
3.
01/07/2011:
Upgrade to Buy, Target Price Change GBP1,500.00
8.
11/03/2011:
4.
02/09/2011:
9.
05/24/2012:
5.
03/24/2011:
10. 07/03/2012:
Historical recommendations and target price: Royal Dutch Shell Plc (RDSb.L)
(as of 9/17/2012)
3,500.00
3,000.00
Security Price
5
4
2,500.00
3
2,000.00
1
6
2
Strong Buy
Buy
Market Perform
Underperform
Not Rated
Suspended Rating
Buy
Hold
Sell
Not Rated
Suspended Rating
1,500.00
1,000.00
500.00
0.00
Sep 09 Dec 09 Mar 10 Jun 10 Sep 10 Dec 10 Mar 11 Jun 11 Sep 11 Dec 11 Mar 12 Jun 12
Date
1.
03/31/2010:
4.
04/04/2011:
2.
11/24/2010:
5.
02/02/2012:
3.
01/07/2011:
6.
07/03/2012:
Page 77
17 September 2012
Integrated Oil
Global LNG
Equity rating key
Buy: Based on a current 12- month view of total
share-holder return (TSR = percentage change in
share price from current price to projected target price
plus pro-jected dividend yield ) , we recommend that
investors buy the stock.
Sell: Based on a current 12-month view of total shareholder return, we recommend that investors sell the
stock
Hold: We take a neutral view on the stock 12-months
out and, based on this time horizon, do not
recommend either a Buy or Sell.
Notes:
1. Newly issued research recommendations and
target prices always supersede previously published
research.
2. Ratings definitions prior to 27 January, 2007 were:
Equity rating dispersion and banking relationships
450
400
350
300
250
200
150
100
50
0
50 %
48 %
44 %
35 %
2 %21 %
Buy
Hold
CompaniesCovered
Sell
Cos. w/ BankingRelationship
NorthAmerican Universe
Buy: Expected total return (including dividends)
of 10% or more over a 12-month period
Hold:
Expected
total
return
(including
dividends) between -10% and 10% over a 12month period
Sell: Expected total return (including dividends)
of -10% or worse over a 12-month period
Page 78
17 September 2012
Integrated Oil
Global LNG
Regulatory Disclosures
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Aside from within this report, important conflict disclosures can also be found at https://gm.db.com/equities under the
"Disclosures Lookup" and "Legal" tabs. Investors are strongly encouraged to review this information before investing.
2. Short-Term Trade Ideas
Deutsche Bank equity research analysts sometimes have shorter-term trade ideas (known as SOLAR ideas) that are
consistent or inconsistent with Deutsche Bank's existing longer term ratings. These trade ideas can be found at the
SOLAR link at http://gm.db.com.
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Australia and New Zealand: This research, and any access to it, is intended only for "wholesale clients" within the
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preparation of this research report, the Brazil based analyst whose name appears first assumes primary responsibility for
its content from a Brazilian regulatory perspective and for its compliance with CVM Instruction # 483.
EU
countries:
Disclosures
relating
to
our
obligations
under
MiFiD
can
be
found
at
http://www.globalmarkets.db.com/riskdisclosures.
Japan: Disclosures under the Financial Instruments and Exchange Law: Company name - Deutsche Securities Inc.
Registration number - Registered as a financial instruments dealer by the Head of the Kanto Local Finance Bureau
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Page 79
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