What price is right? By Sriharsha Pappu and Tareq Alarifi Feedstock pricing changes likely to be announced in 2011. We expect this decision to be influenced by a combination of both economic and policy factors, and we forecast a phased increase that does not fundamentally alter the competitive position of the industry The impact on margins from these feedstock price increases is highest for companies with the biggest cost advantages (eg SAFCO), while those with lower cost advantages and margins (eg SABIC) are least affected. The increase in HSBC's energy price forecasts however, outweighs the impact of higher feedstock costs Yet despite generally raising our target prices, we are cautious on the sector for 2011 given recent strong performance, elevated expectations and high valuations. Our top picks in the sector are Tasnee (OW(V), TPSAR44), Yansab (OW(V), TP SAR65) and SABIC (OW(V), TP SAR130). We downgrade Petrochem (TP SAR25) and Sahara (TP SAR25) to N(V) from OW(V) and Industries Qatar (TP QAR135) to UW from N Disclosures and Disclaimer This report must be read with the disclosures and analyst certifications in the Disclosure appendix, and with the Disclaimer, which forms part of it Natural Resources & Energy/Middle East Chemicals - Equity January 2011 What price is right? Re-evaluating the feedstock price environment Natural Resources & Energy/Middle East Chemicals - Equity January 2011
HSBC outlook for chemical feedstocks in the Middle East
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Wh
at p
rice is
righ
t?
By Sriharsha Pappu and Tareq Alarifi
Feedstock pricing changes likely to be announced in 2011. We expect this decision to be
influenced by a combination of both economic and policy factors, and we forecast a phased
increase that does not fundamentally alter the competitive position of the industry
The impact on margins from these feedstock price increases is highest for companies with the
biggest cost advantages (eg SAFCO), while those with lower cost advantages and margins
(eg SABIC) are least affected. The increase in HSBC's energy price forecasts however, outweighs
the impact of higher feedstock costs
Yet despite generally raising our target prices, we are cautious on the sector for 2011 given
recent strong performance, elevated expectations and high valuations. Our top picks in the
sector are Tasnee (OW(V), TPSAR44), Yansab (OW(V), TP SAR65) and SABIC (OW(V), TP SAR130).
We downgrade Petrochem (TP SAR25) and Sahara (TP SAR25) to N(V) from OW(V) and
Industries Qatar (TP QAR135) to UW from N
Disclosures and Disclaimer This report must be read with the disclosures and analyst
certifications in the Disclosure appendix, and with the Disclaimer, which forms part of it
Natural Resources and Energy Middle East Chemicals January 2011
abc
The feedstock pricing question Pricing revision – topical in 2011
In the wake of constrained gas supply, multiple competing uses and a burgeoning cost advantage, there
are serious questions being raised about the feasibility of continuing with the current gas pricing regime
within Saudi Arabia. The view gaining traction among industry participants is that some form of
modification to the pricing framework is required both as an incentive for companies to provide new gas
supply and to ensure a more efficient distribution of limited gas resources. This discussion is particularly
relevant today as some of the feedstock formulae – particularly for liquids – run only until 2011, which
means a new pricing benchmark, at least for liquids, will need to be approved before the end of the year.
We believe that a new gas pricing framework will be approved at the same time, and therefore that a
change in the feedstock price environment is imminent.
A combination of economics and policy
In our opinion, any change to the feedstock pricing regime will be driven by a combination of economic
and policy factors. The economic argument based on incentives for supply growth, efficient allocation of
scarce resources and demand rationalisation would call for Saudi gas prices to reflect global levels of
USD4-5/mmbtu vs. the current price of USD0.75/mmbtu. However, an increase of this magnitude would
deliver a significant economic blow to the industry which would run counter to the key policy objective
of driving downstream chemical investment and generating employment.
We believe that policymakers will work to ensure that feedstock price increases take place in a manner so
as not to shock the industry or dramatically alter its competitive dynamic. We also believe that policy
makers will be just as conservative with their underlying energy price assumptions while assessing the
competitiveness of the petrochemical industry as they are while setting their annual budgets.
We are raising our estimates for Saudi gas and ethane equivalent prices from the current USD0.75/mmbtu to
USD2.0/mmbtu by 2015. We expect that this increase will take place in a phased manner, with prices rising
first to USD1.25/mmbtu by 2012 and in a staged manner thereafter (see table below). We also assume that the
liquids discount will decline by 1ppt each year from the current 28% before being fixed at 25% by 2014.
Summary
We expect to see a change in the feedstock pricing regime in 2011. We believe this will be influenced by a combination of both economic and policy factors and we are factoring in a phased increase in prices that does not fundamentally alter the competitive position of the industry. The increase in HSBC's energy price forecasts however, outweighs the impact of higher feedstock costs.
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In terms of margins, the rule of thumb is that companies with the biggest cost advantages and the highest
margins (eg SAFCO) are impacted more by an increase in feedstock prices than companies with lower
cost advantages and margins (eg SABIC). Our oil and gas team has increased its energy price forecasts
for 2011-15 by around 10% which has resulted in an increase in our product pricing estimates. In most
cases, the impact from higher product pricing outweighs the impact of higher feedstock costs.
Sector investment thesis Peak conditions to return by 2013/14, market likely to remain balanced in 2011
Rising emerging market demand and limited supply growth will create an environment of higher capacity
utilisation rates. Based on our supply assumptions and HSBC Economics global economic growth
forecasts, we expect to see a return to peak conditions (utilisation rates of over 90%) within the
commodity chemical sector by 2013/14.
However, while we are bullish on the sector in the medium term, we believe that in the near term supply growth in
2011 could potentially come in above expectations. We expect incremental supply from existing plants to match
demand growth for the year as improving macroeconomic conditions ease some of the bottlenecks (in terms of
feedstock supply) that resulted in a tight market in 2010. This should be particularly true for European cracker
operating rates, which are tied to operating rates at refineries in the region. An improving macro environment in
Europe should lead to higher ethylene supply on greater naphtha availability from refineries.
Furthermore, higher oil-product demand and higher oil prices could lead to an increase in OPEC
production quotas which would make more associated gas available, particularly in Saudi Arabia, and
result in an incremental increase in operating rates at newer crackers – which we estimate are currently
running on average at 80% – owing to feedstock supply constraints. In both these cases, incremental
supply would materialise from existing capacity only if demand growth continued to be strong and hence
should not result in a big dip in utilisation rates due to an oversupply situation. However, this incremental
supply would, in the short term, prevent a sharp rise in utilisation rates. We forecast ethylene utilisation
rates to improve by only 70bps in 2011 over 2010 levels.
Cautious on sector performance in 2011
We believe that after two years of exceptional stock market performance from the Middle East chemical
sector with stocks on average up 47% in 2009 and 24% in 2010, it is time to take a more cautious view on
the sector in 2011. Our cautious stance on performance is based on by high valuations and elevated
consensus expectations. Middle East chemical sector valuations are now above mid-cycle levels, with
stocks trading on average on a 15.6x forward PE versus the historical sector median forward multiple of
14x. While fundamentals are healthy, these appear to be already factored into share prices and we think it
it is unlikely that in 2011 the sector will generate the same level of returns seen in 2009/10.
HSBC Saudi feedstock pricing assumptions
2011e 2012e 2013e 2014e 2015e
Gas price (USD/mmbtu), New 0.75 1.25 1.50 2.00 2.00 Gas price (USD/mmbtu), Old 0.75 0.75 0.75 0.75 0.75 % Propane Discount, New 28% 27% 26% 25% 25% % Propane Discount, Old 28% 28% 28% 28% 28%
Source: HSBC estimates
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Consensus expectations for chemical company earnings in 2011 also fully reflect the recovery in
fundamentals in our opinion. Sector outperformance will require reported earnings to beat estimates
significantly, which we believe they will struggle to do given that current 2011 EPS consensus estimates
for the Middle East chemicals sector are on average 45% higher than they were a year ago.
We prefer stocks with structural pricing drivers – Tasnee and Yansab
Our favoured plays within the Middle East petrochemical sector for 2011 are Tasnee, Yansab and
SABIC. Tasnee and Yansab have strong price momentum within important product chains (TiO2 for
Tasnee and MEG for Yansab) which is being driven by structural factors.
SABIC has significant operating leverage to improving fundamentals at its acquired GE Plastics business.
The business at its peak had EBITDA of USD1bn, and we expect a return to close to peak profitability by
the end of 2011from levels of cUSD200m in EBITDA in 2010e. SABIC also has volume leverage from
the expected commercial start up of Kayan towards H2 2011. Kayan is by far the single largest plant
SABIC has ever built and should drive revenue and profit growth y-o-y for SABIC in 2011.
For Tasnee, we believe that the TiO2 market will remain undersupplied well into 2012 given the lead
times for adding new capacity. We therefore predict 12-18 months of strong pricing power within the
TiO2 segment. This segment constitutes 35% of Tasnee’s earnings and will be a key contributor to the
company’s earnings in 2011. For more details, see our 1 November 2010 report on Tasnee, Painting a
stronger picture.
Yansab is a key beneficiary of the record levels of cotton prices – cotton and polyester are both used in
the textile industry and large price differences between the two often provide a catalyst for substitution.
The current price delta between cotton and polyester fibre stands at USD1,780/tonne – over 5.2x the
average of the differential between 2000 and 2009 which should spur greater polyester demand. This
substitution demand drives pricing for the raw materials used to make polyester such as paraxylene and
Mono Ethylene Glycol (MEG). Yansab has the strongest leverage to rising MEG prices among our
coverage and is our preferred play on this theme of strong cotton prices and interfibre substitution.
Downgrading Petrochem and Sahara to N(V) from OW(V); Industries Qatar to UW from N
We downgrade Petrochem to Neutral (V) from Overweight (V) on account of the stock’s strong
performance since the start of 2010 (up 50%) and limited upside from current levels to our target price
(7%), which we maintain at SAR25. The valuation disconnect between SIIG and Petrochem, flagged in
our April 2010 note Shifting into focus, which was the primary driver for our buy case on Petrochem has
also now closed making us less positive on the stock.
We are downgrading Sahara to Neutral (V) from Overweight (V) on disappointing execution of the Al Waha
project, which has resulted in our target price being cut to SAR25 from SAR30. We had initially factored in a
Q2 2010 start-up for the Al Waha polypropylene plant but the company has repeatedly pushed back the
commercial start-up date for the plant, with the most recent date given being the end of Q1 2011. Al Waha now
accounts for c40% of our valuation for Sahara as the repeated delays coupled with continued start up risks have
resulted in an assumption of lower operating rates and value for the asset.
We also downgrade Industries Qatar (IQ) from Neutral (V) to Underweight (V) on valuation grounds, despite
increasing our target price to QAR135 from QAR110. The stock has rallied sharply in the last six months and
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Natural Resources and Energy Middle East Chemicals January 2011
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is up more than 40% since the start of H2 2010. This rally is partly explained by stronger fundamentals for IQ’s
products – fertilisers and petrochemicals – and partly by a stronger macro environment for Qatar, including the
award of the 2022 Fifa World Cup. We believe that all of these factors are more than adequately priced into the
stock and that the risks to the current share price are to the downside.
In addition to these three ratings changes, we have also made some adjustments to our target prices for
much of the rest of our coverage. These changes have been driven by: changes to our product pricing
estimates and crude price assumptions; changes to our feedstock pricing assumptions; rolling forward our
DCF’s to a 2011 start date; and changes to our cost of equity to reflect the new HSBC Strategy team
assumptions for the risk free rate and country risk premium. The changes to our ratings and target prices
Natural Resources and Energy Middle East Chemicals January 2011
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Sector view – 2011 6
Feedstock pricing today 10
Feedstock pricing tomorrow 18
Impact on product pricing and margins 26
SABIC 34
Yansab 37
Tasnee 40
Sahara Petrochemical Co. 43
National Petrochemical Company (Petrochem) 46
Advanced Petrochemical Company (APC) 49
Chemanol 52
Sipchem 55
Industries Qatar 58
Saudi Fertiliser Company (SAFCO) 61
SIIG 64
Saudi Kayan 67
Disclosure appendix 73
Disclaimer 76
Contents
We acknowledge the assistance of Mohit Kapoor in the preparation of this report.
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Mid-cycle: trough behind, peak ahead The cyclical trough witnessed in late 2008 and
early 2009 is now well behind us with demand
having recovered during 2010, partly led by
restocking. The big question for 2011 and
thereafter is whether the recovery gains
momentum towards cyclical peak conditions or
whether it stalls, leading to a lower demand
growth, mid-cycle margin environment.
The view from chemical company management
teams, particularly after the Q3 2010 earnings
season, was that a robust recovery driven by
emerging market demand strength was in place
and would continue through 2011. This view was
reiterated by SABIC, Tasnee and Industries Qatar
on our recent investor trip in December.
The key takeaway from the trip for us was that
industry participants seemed to be the most
optimistic they have been for the best part of three
years. This bullish sentiment was based on robust
current demand, strong order books, expectations
of continued emerging market demand growth
outweighing weak developed market demand and
limited supply growth on the horizon.
Furthermore, the view was that chain inventories
are still well below pre-crisis levels which should
allow companies to push through any increases in
raw material prices. We expect to see this
environment of strong demand and limited supply
result in an increase in utilisation rates and a
return to a cyclical peak margin environment by
2013-14.
Long-term supply outlook favourable
After accounting for over 40% of global supply
additions over 2008-11, the Middle East has very
little to contribute in terms of new supply after
2011 (see chart at the top of the next page).
There are no new ethylene crackers planned in
Saudi Arabia between 2012 and 2015, and the
Dow-Aramco project is only tentatively set for
2016. Abu Dhabi, Qatar and Kuwait, which make
up the rest of the GCC petrochemical universe,
are contributing one additional cracker between
them in 2014. Iran, which has the potential to add
more supply, faces tremendous challenges from
economic sanctions and is unlikely to add
capacity in the medium term.
The lack of new Middle East supply is based on a
combination of factors: the limited availability of
cheap feedstock, the push towards downstream,
employment-generating industries and
diversification.
Sector view – 2011
Limited new capacity, robust emerging market demand to drive a
return to peak operating rates by 2013-14
However, market likely to remain balanced in the near term
We forecast a mid-cycle margin environment through 2011
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Natural Resources and Energy Middle East Chemicals January 2011
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The only other region to add capacity apart from the
Middle East over the last decade has been Asia. We
do not see significant risks from current capacity
additions in Asia, particularly China. Based on the
latest directive from the National Development and
Reform Commission (NDRC) on domestic refining
and the chemicals sector for China’s 12th five-year
plan (2011-15), we believe the country will
continue to focus on increasing the average
production size of local refinery and chemical plants
while shutting outmoded capacity and thus
preventing overcapacity. For more details on
Chinese capacity addition plans please refer to our
Asian chemical team’s report from September 2010,
Asia Refining and Petrochemicals: Refining to hit
sweet spot in 2011-12.
Stronger demand, limited supply to drive next peak by 2013-14
Rising emerging market demand and limited
supply growth will create an environment of
higher capacity utilisation rates. As utilisation
rates increase pricing power starts to shift back to
producers; operating rates of over 90% are
considered peak conditions for the industry. Based
on our supply assumptions and HSBC Economics'
global economic growth forecasts, we expect to
see a return to peak conditions within the
commodity chemical sector by 2013-14 (see chart
at the top of the next page).
Talk of ‘supercycle’ premature, in our opinion
The limited visibility on any new supply in the
medium term has started to prompt talk in
investor circles of a potential “supercycle” in the
chemical sector. The idea being touted is that
feedstock availability concerns pose an
insurmountable obstacle to any meaningful supply
growth while rising emerging market demand
growth will continue to increase operating rates,
resulting in a multiyear period of high margins.
While we believe in a stronger fundamental
picture for the sector in the medium term, we are
not quite in the ‘super-cycle’ camp yet, for a
couple of reasons.
Firstly, we are barely 18 months removed from
one of the worst industry troughs in living
memory. Developed market demand for
commodity chemicals is still well below the levels
Middle East ethylene supply update Ethylene capacity adds (000 tons) Location Country 2008 2009 2010 2011 2012 2013 2014
Middle EastArya Sasol Bandar Assaluyeh Iran 940Gachsaran PC Gachsaran Iran 500 500Ilam PC Ilam Iran 458Jam PC Bandar Assaluyeh Iran 990 330Kavyan PC Bandar Assaluyeh Iran 1000Morvarid PC Bandar Assaluyeh Iran 500TKOC Shuaiba Kuwait 106 744QAPCO Umm Said Qatar 95QP/Exxon Mobil Ras Laffan Qatar 325RLOC Ras Laffan Qatar 975 325Jubail ChevPhill Al Jubail Saudi Arabia 150 150Kayan Al Jubail Saudi Arabia 325 1000Petro-Rabigh Rabigh Saudi Arabia 975 325Saudi Polymers Al Jubail Saudi Arabia 600 600SEPC Al Jubail Saudi Arabia 450 550SHARQ Al Jubail Saudi Arabia 100 1100Yansab Yanbu Saudi Arabia 867 433Borouge II Ruwais Abu Dhabi 700 700Borouge III Ruwais Abu Dhabi 750Total Middle Eastern Incremental Capacity adds 2731 3716 4358 3083 1100 500 2075
Completed and fully operationalCompleted and ramping upDoubtfulIncremental between now and 2014
Source: CMAI, HSBC estimates
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Natural Resources and Energy Middle East Chemicals January 2011
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of 2007 with some major end markets, such as US
autos and US housing, still at a fraction of their
peak activity levels. While emerging market
demand remains robust, developed markets still
account for 60% of the commodity chemical
market by volume, and a sustained multiyear peak
is unlikely as long as developed markets continue
to drag, in our opinion.
Secondly, for a commodity sector with widely
diffused technology, multiyear peaks driven by
supply limitations often prove to be a mirage.
Once margins reach reinvestment levels, the
sector has a way of attracting new investment in
supply that leads to a balancing of operating rates.
A sustained period of higher margins would make
naphtha cracking attractive in the Middle East and
lead to a push for heavy feed crackers in the
region which would balance supply and demand.
To sum up our medium-term sector view in a
sentence: we are bullish on the chemical cycle,
but we are not super-cycle bulls.
Market to remain in balance in 2011 as incremental supply likely
While we are bullish on the sector in the medium
term, we believe that in the near term supply
growth could potentially come in above
expectations in 2011. We expect incremental
supply from existing plants to match demand
growth for the year as improving macroeconomic
conditions ease some of the feedstock supply
bottlenecks that resulted in a tight market in 2010.
This is particularly true of European cracker
operating rates which are tied to operating rates at
refineries in the region. As the chart at the top of
the next page illustrates, ethylene availability
from European naphtha-based crackers dropped
20% below 2007 peak levels as a result of reduced
naphtha supply. An improving macro
environment in Europe would lead to higher
ethylene supply due to greater naphtha availability
from refining.
Furthermore, higher oil-product demand and
higher oil prices could lead to an increase in
OPEC production quotas which would make more
associated gas available, particularly in Saudi
Arabia, and result in an incremental increase in
operating rates at newer crackers – which we
estimate are currently running on average at 80%
owing to feedstock supply constraints.
In both these cases, incremental supply would
materialise from existing capacity only if demand
growth continued to be strong. Therefore it should
HSBC: Ethylene operating rate outlook
88 .9%
8 7 . 0%
8 3 .4 %
84 .1%
8 5 . 3%
8 8 .0 %
90 .0%
8 1 .0 %
8 3 .0 %
8 5 .0 %
8 7 .0 %
8 9 .0 %
9 1 .0 %
20 08 2 00 9 2 0 10 2 01 1E 2 01 2 E 2 0 13 E 2 01 4E
Ope
ratin
g ra
tes
(%
)
HS BC Eth y le ne o pe r a tin g r a tes
Source: HSBC estimates
9
Natural Resources and Energy Middle East Chemicals January 2011
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not result in a big dip in utilisation rates.
However, this incremental supply would prevent a
sharp rise in utilisation rates in the short term. We
forecast ethylene utilisation rates to improve by
only 70bps in 2011 over 2010 levels.
Cautious on chemical sector for 2011
We believe that after two years of exceptional
stock market performance from the Middle East
chemical sector, with stocks on average up 47% in
2009 and 24% in 2010, it is time to take a more
cautious view on the sector in 2011.
Our cautious stance is driven by two main
considerations: current market valuations and
consensus forecasts, and the outlook for supply in
2011.
Valuations and expectations
Middle East chemical sector valuations are now
above mid-cycle levels, with stocks trading on
average on a 15.6x forward PE vs. the historical
sector median forward multiple of 14x. While
fundamentals are healthy, these appear to be
already factored into share prices.
Consensus expectations for chemical company
earnings in 2011 also fully reflect the recovery in
fundamentals, in our opinion. Sector
outperformance will require reported earnings to
beat estimates significantly, which we believe
they will struggle to do given that current 2011
EPS consensus estimates for the Middle East
chemicals sector are on average 45% higher than
they were a year ago.
With supply also likely to surprise on the upside -
as production bottlenecks ease as discussed earlier
- we therefore think it unlikely that 2009-10 sector
stock performance will be repeated in 2011.
Western European cracker operating rates Saudi: new cracker operating rates in Q3 2010
Saudi Oil Production (Mboe pa) Saudi Gas Production (Mboe pa)
0
50,000
100,000
150,000
200,000
250,000
300,000
350,000
400,000
450,000
1970 1974 1978 1982 1986 1990 1994 1998 2002 2006
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
40,000
45,000
Gas consumption- public (Mboe) Power Generation Capacity (MW) Source: SAMA Source: SAMA
12
Natural Resources and Energy Middle East Chemicals January 2011
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oil, which detracted from the amount of oil
available for export. Substituting stranded natural
gas for some of that oil, which was then exported,
was the most appropriate use of both the gas and
the heavy oil.
Master Gas System (MGS)
Once the decision was made to utilise the stranded
associated natural gas for domestic consumption,
there still remained two open questions: how to
deliver the gas from the oil fields to the
consumption centres on the coast, and what price
to charge for the gas. The answer to both of these
questions lay in the development of the Saudi
Master Gas System (MGS), a network of
pipelines linking gas produced at the oil fields to
various end users across the Kingdom designed to
provide Saudi Arabia with natural gas as a
commercial resource.
The MGS was developed in the late 1970s in an
effort by Aramco to recover associated gas
produced at the oilfields, process it and supply the
country with dry and liquid gases. The idea was to
feed the gas to the two main industrial cities that
were being developed concurrently: Jubail on the
eastern coast and Yanbu on the western coast.
The system was initially designed to process up to
3.5 billion scfd of gas, of which 2 billion scfd was
methane, primarily used as fuel for utilities and as
a feedstock for methanol and fertilisers. The
system was also designed to process 370 million
scfd of ethane as well as natural gas liquids
(NGL) which were to be used as petrochemical
feedstock.
The MGS (see chart below) is one of the largest
of its kind in the world and includes more than 65
gas/oil separation plants located at various oil
fields. Five gas processing plants separate out
methane gas which is then supplied by a 2,400km
pipe network that includes an east-west pipeline
running across the breadth of Saudi Arabia to
power plants, refineries, fertiliser plants, methanol
plants, and steel plants in the two industrial cities.
The system also includes two gas fractionation
plants that separate ethane, propane, butane and
natural gas liquids (NGLs) from the raw gas.
Ethane is then supplied to petrochemical plants in
Jubail and Yanbu. LPGs and NGLs are currently
used internally by the petrochemicals industry,
however at the time that the MGS was built, these
feedstocks were mostly exported.
In its early stages of implementation, the MGS
was used to power the entire energy requirements
of the east coast as well as a few desalination
plants along with multiple industrial projects. The
establishment of the MGS also resulted in several
international oil & gas companies setting up joint
venture projects in Saudi, mainly in the
petrochemical arena, to take advantage of the
availability, and relative inexpensiveness, of
feedstock at the newly inaugurated industrial
cities of Jubail and Yanbu.
Gas pricing and the MGS
Gas volume processed initially 3,500 mmscfd Heat content of delivered gas 35,00,000 mmbtu Gas price 0.5 USD/mmbtu Annual gas revenues 639 USD mn Initial investment in the MGS 12,000 USD mn Gas prices raised to fund expansion Expanded capacity 2,500 mmscfd Heat content of delivered gas 25,00,000 mmbtu Gas price increase 0.25 USD/mmbtu Incremental revenue from price increase 548 USD mn Cost of expansion 7,500 USD mn
Source: Saudi Aramco, HSBC
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Natural Resources and Energy Middle East Chemicals January 2011
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The first MGS phase began operations in 1982
and was entirely dependent on associated gas
supply from the oil fields. This coincided with a
peak in Saudi oil production at the time and when
Saudi Arabia’s oil production dropped by over
50% to a low of 2.5mbpd in 1985 this resulted in
lower gas availability within the new system.
Power outages and shortages in feedstock supply
to the petrochemical sector followed, with
Aramco then deciding on supplementing the
system with the little non-associated gas supply it
had at the time.
The logic behind existing gas pricing
The cost associated with setting up the MGS
provided the first data points for establishing a gas
price given the lack of economically viable
alternate markets for the gas. Aramco needed to
charge end users a rate for the gas that would at
least provide some return on capital given the large
investment cost associated with the project. Based
on the capital invested and the amount of gas
processed, a price of USD0.5/mmbtu was deemed
appropriate at the time. The link between the MGS
and gas prices is further highlighted when one
considers the fact that the only time that gas prices
have been raised in the Kingdom (in 1998 from
USD0.5 to USD0.75/mmbtu) was when Aramco
decided to spend USD7.5bn on upgrading the MGS
and increasing its processing capacity.
Surge in petrochemical investment
The availability of feedstock, not so much its pricing
at the time, spurred investment in the basic
petrochemical industry in the region. The largest
investments came in Saudi Arabia which, given its
oil production, obviously had the most amount of
associated gas available. Saudi took the first step in
jumpstarting the regional sector by establishing the
Saudi Basic Industries Corp. (SABIC).
Saudi Master Gas System in 2011
RED SEA
JEDDAH
SAUDI ARABIAYanbu Indus trial City
Jubail Industrial City
YANBU
JU’AYMAH
BE RRI SHEDGUM
UTHMANIYAH
HAWIY AH
HARADH
NA Gas
NA Ga s
Gas WellNA Gas
RIYADH
Gas We ll
Natural gas pipeline
NGL pipe line
RED SEA
JEDDAH
SAUDI ARABIAYanbu Indus trial City
Jubail Industrial City
YANBU
JU’AYMAH
BE RRI SHEDGUM
UTHMANIYAH
HAWIY AH
HARADH
NA Gas
NA Ga s
Gas WellNA Gas
RIYADH
Gas We ll
Natural gas pipeline
NGL pipe line
Source: Saudi Aramco
14
Natural Resources and Energy Middle East Chemicals January 2011
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SABIC’s growth was driven by the successful
deployment of the Master Gas System and further
supported by subsidised electricity costs and soft
government loans. These incentives, coupled with
the creation of the industrial cities of Jubail and
Yanbu along with supporting industrial
infrastructure at the two cities. laid the foundation
for SABIC’s success.
Feedstock advantage rising
It was not generally expected in the 1990s that the
Middle East would hold the cost advantage that it
currently does as global energy prices remained
low through the 1990s which meant that
petrochemical investment was made in regions
with the largest markets – the US, developed
Europe – rather than feedstock-rich regions such
as the Gulf.
However, the boom in oil and gas prices over the
past decade increased the cost advantage enjoyed
by the fixed-cost ethane based petrochemical
producers in the Middle East and also drove a
wave of investment in new capacity (see charts at
the top of the page). The new capacity placed
constraints on gas availability at a time when
competing uses for gas started to emerge while
the significant increase in the cost advantage
enjoyed by the petrochemical companies started
to raise questions about a revision to the gas
pricing framework.
Gas pricing – the new normal Competing uses for gas, limited supply growth
The single biggest driver for a change to the
existing gas price regime is the number of
competing uses for what is now a scarce resource.
A return on infrastructure investment model,
which is what the existing USD0.75/mmbtu price
was based on, was acceptable when the MGS was
being built and there were limited uses for the
stranded gas. However, with a massive increase in
gas demand within the region and production
failing to keep pace, a new pricing mechanism is
necessary in order to balance both policy and
economic interests.
This is particularly relevant in light of limited
production growth. While Saudi proven gas
reserves have continued to grow, from 263trn scf
in 2008 to 275trn scf (or 286,200 trn btu) at the
end of 2009, the amount of gas being delivered
has not kept pace with reserve growth. According
to Aramco data sales gas (methane) deliveries
declined by 0.281 trn btu in 2009 and delivered
ethane only increased by 0.092 trn btu in 2009
(see chart at the top of the next page).
One of the key reasons for limited growth in
delivered gas is that, as argued in our note of 26
November 2009, Saudi Infrastructure: Spending for
this generation, Aramco’s highest priority has until
Growth of ethylene capacity in the Middle East (000 tonnes) Saudi capacity vs. ethane cost advantage
----
5,000
10,000
15,000
20,000
25,000
30,000
2004 2005 2006 2007 2008 2009 2010 2011 2012
IranIraqKuwaitQatarKSAUAEMiddle East
----
5,000
10,000
15,000
20,000
25,000
30,000
2004 2005 2006 2007 2008 2009 2010 2011 2012
IranIraqKuwaitQatarKSAUAEMiddle East
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
Jan-1990
Jan-1992
Jan-1994
Jan-1996
Jan-1998
Jan-2000
Jan-2002
Jan-2004
Jan-2006
Jan-2008
Jan-2010
0
200
400
600
800
1,000
1,200
LHS: Saudi Ethylene capacity ('000 ton)US Ethane (USD/Ton)Saudi Ethane (USD/Ton)
Source: CMAI, HSBC Source: CMAI, HSBC
15
Natural Resources and Energy Middle East Chemicals January 2011
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recently been oil-related exploration projects. Given
the lead time between exploration and production
within the oil and gas sector, the lack of focus on gas
in the last decade or so is constraining current
supply. However, this has now changed, with
Aramco increasingly aware of the requirement to
increase gas supply. Aramco has set itself a goal of
discovering 3 to 7 trillion scf of additional non-
associated gas reserves annually.
Another supply constraint is that much of the gas
extracted is a by-product of oil production, despite
the fact that non-associated gas accounts for 75%
of total gas reserves versus 48% in 1990; i.e.
while non-associated gas reserves have grown,
production from those fields has not. Aramco has
again refocused on developing its non-associated
gas production, which is evident from the fact that
currently 50% of all offshore rigs are deployed for
gas production, as opposed to between 20% and
40% in the past.
Moreover there are several sources of competing
demand for this gas, mainly from electricity
generation - which currently uses about 1 billion
to 1.5 billion scfd of gas and 0.9m bpd of oil in
Saudi Arabia - and water desalination which
currently uses 0.5 billion scfd of gas. Aramco
expects total domestic fuel demand to rise from
3.3 million bpd of oil equivalent in 2009 to
approximately 8.3 million bpd of oil equivalent in
2028. To put this in context, Saudi Arabia’s
current production capacity is 13.75 million bpd
of oil equivalent. To rephrase, if demand were to
increase as projected without a concurrent
increase in supply, within two decades over 60%
of Saudi Arabian energy production would go
towards meeting domestic consumption. This
would not only result in a significant revenue loss
for Saudi Arabia, but would also be very bullish
for global energy prices given Saudi Arabia’s
position as a swing producer of crude.
We outline the various calls on Saudi gas
production from the various sectors below.
Power demand
The Saudi Electricity and Cogeneration
Regulatory Authority has said about 0.9 million
barrels of oil are currently used to generate power
every year and, as the authority plans to raise
power capacity from 44.6GW at the end of 2009
to 121GW by 2032, the requirement will increase
to 2.4 million barrels of fuel oil per day – this
excludes the current amount of natural gas used.
Saudi Electricity (SEC) expects power
consumption to increase from 193GWh in 2009 to
251GWh in 2013, similar to our expectations
(please see our note of 9 June Saudi Electricity
Company – N: New tariff plan priced in, next
move key to unlock value) which is equivalent to a
Saudi gas deliveries (bn scf) Saudi Electricity Company: planned capex (SARm)
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
2005 2006 2007 2008 2009
Delivered sales gas Delivered ethane gas
30,000
0
5,000
10,000
15,000
20,000
25,000
2010e 2011e 2012e 2013e 2014e
Generation Transmission and Distribution Replacement Total
30,000
0
5,000
10,000
15,000
20,000
25,000
2010e 2011e 2012e 2013e 2014e0
5,000
10,000
15,000
20,000
25,000
2010e 2011e 2012e 2013e 2014e
GenerationGeneration Transmission and DistributionTransmission and Distribution ReplacementReplacement TotalTotal
Source: Saudi Aramco Source: Corporate reports, HSBC
16
Natural Resources and Energy Middle East Chemicals January 2011
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requirement of another 0.3 million boe per day.
To meet growing consumption, SEC plans to
increase generation capacity by 7GW between
2009 and 2013, with a further 4.5GW coming on
line over 2014 and 2015. We estimate that another
6GW will come on line via Independent Power
Producers (IPPs) and Integrated Independent
Water and Power Projects (IWPPs) by 2015.
At present half of electricity generation comes
from gas, with consumption of electricity set to
increase by c30% by 2013, according to SEC. It is
expected that this will lead to a significant
increase in gas requirement in the kingdom.
Water
Water is a critical issue for the Saudi government.
Domestic water consumption is equivalent to 230
litres per day per person, compared with Europe’s
100-200 litres per day, but is not covered fully by
desalinated water. Production of desalinated water
in 2008 was 1.1bn cubic metres, up 3.4% y-o-y.
The government estimates that demand for
drinking water will increase to about 10m cubic
metres per day over the next 20 years, if the
increase in the daily per capita consumption rate
continues at its current level. A significant
increase in desalination capacity is planned to
meet the higher demand. We estimate that
desalination capacity needs to double over the
next 20 years to cover drinking water needs alone,
and calculate that this would lead to a requirement
for an additional c0.5 billion scfd of gas.
Refining and petrochemicals
Integrated refining projects are a priority for the
government in order to both meet fuel demand and
introduce a more complex set of petrochemical
products that would help create a downstream
chemical industry and spur employment. Introducing
natural gas into the feedstock mix for integrated
refining projects will enhance margins thereby
improving the initial payback and encouraging more
complex petrochemical projects.
We estimate that the refineries due to come on
line will consume around 0.3 billion scfd of gas.
However, until the non-associated gas fields come
online, the majority of non-integrated
petrochemical projects will be delayed
indefinitely, in our view. The key integrated
refining and petrochemical projects that will
require gas supply over the next four to five years
are detailed below.
Saudi Aramco Total refining & petrochemical
company (SATORP): Aramco (62.5% share of
the JV) and Total are building a joint venture
400,0000 bpd refinery at Jubail which could
potentially add an world-scale integrated cracker
complex. Financing for the refinery part of the
project is complete and parts of the project are
under construction.
Yanbu refinery: The proposed Yanbu export
refinery, a 400,000 bpd full-conversion refinery on
the Red Sea coast, is designed to produce refined
products and petrochemicals. ConocoPhillips pulled
out of the venture in April 2010 and Aramco has
since said that it will go it alone if it cannot find a
partner. The refinery is a priority as it is needed to
process the additional heavy crude that is due to
come out of the Manifa oil field.
Aramco/Dow petrochemical project: Aramco and
Dow Chemical were originally planning to build an
integrated petrochemicals complex alongside a
400,000 bpd expansion to the existing 500,000 bpd
Ras Tanura refinery. This was modified in April
2010 when the two companies announced that they
would move the project to Jubail. The cost of the
complex has been reduced from USD20bn initially
to less than USD15bn. It is most likely that the
project will now be fed largely by ethane gas
provided by Aramco and, to a lesser extent, liquid
feedstocks provided by the Jubail refinery.
17
Natural Resources and Energy Middle East Chemicals January 2011
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Gas exploration – the supply response
State oil companies such as Aramco have started
to respond to the rising demand for gas. For
Aramco, increased production of non-associated
gas is now a priority and new discoveries have
been principally made offshore as the exploration
in Rub al-Khali (the Empty Quarter, onshore) has
continued to disappoint. As a result, more
offshore exploration is under way with Aramco
increasing the number of active offshore rigs to
about 15 in 2009 from just one in 2000,
dedicating USD6bn (or 10% of its capital
investment) to the development of six offshore
facilities over the next five years.
The most significant non-associated gas field to
come online will be the Karan offshore field.
When completed in 2013, the field will be capable
of delivering 1.8 billion scfd of raw gas. Under
the USD1bn Shaybah scheme, Aramco wants to
build a plant to separate the equivalent of 228,000
bpd of natural gas liquids from crude oil produced
at the field.
In addition, under the Wasit scheme, estimated to
cost USD 6bn, Aramco aims to produce 2.5
billion scfd of sulphur-rich gas from the newly
discovered offshore Arabiyah and Hasbah fields
before transporting it to a central processing
facility at Wasit. The plan is to construct seven
offshore wellhead production platforms at the
Hasbah field, which can produce up to 1.3 billion
scfd of gas from the field, and six wellhead
platforms at the Arabiyah field, capable of
producing 1.2 billion scfd.
The scheme also includes six 12-inch flowlines, a
150km pipeline linking the facilities with Wasit, a
150km pipeline between Arabiyah and Wasit, and
a 91km submarine power cable. However, the
lead time required for completing such
developments, and the constraints on production
of oil due to OPEC quotas, will mean gas
production will be limited for the next three years.
Pressure on gas pricing
In the wake of constrained gas supply, multiple
competing uses and a burgeoning cost advantage,
there are now serious questions being raised
regarding the feasibility of continuing with the
current gas pricing regime within Saudi Arabia.
The view gaining traction among industry
participants is that some form of modification to
the pricing framework is required both to provide
an incentive for new gas supply and to ensure a
more efficient distribution of limited gas
resources.
This discussion is particularly relevant at the
current time given that some of the feedstock
contract pricing formulae – particularly for liquids
– run only until 2011, implying that a new pricing
benchmark, at least for liquids will need to be
approved before the end of the year. We believe
that a new gas pricing framework will also be
approved at the same time and so a change in the
overall feedstock price environment is imminent.
However, any such change is unlikely to be driven
by economic factors alone, with policy factors
likely to play just as big a role in the decision. We
outline our thoughts on the potential framework
for a change to the feedstock pricing mechanism
in the next section.
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Natural Resources and Energy Middle East Chemicals January 2011
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The economic argument Rising energy prices have increased the cost advantage
When the Saudi petrochemical sector was first
established in the early 1980s, foreign technology
partners for SABIC were attracted to Saudi Arabia
by low cost gas feedstock at a price of
USD0.50/mmbtu. With US natural gas prices in
the USD1-2/mmbtu range at the time the Saudi
gas price, while attractive, was not dramatically
lower than prevailing international prices.
The Saudi gas price was raised once to
USD0.75/mmbtu in 1998 and has since remained
at that level despite there having been a secular
shift in the global energy price environment in
recent years. The chart at the bottom of the page
illustrates this shift. The Saudi cost advantage for
the production of ethylene using pure ethane as
feed has tripled on average over the 2003-10
period compared to its 1990-2003 average, driven
exclusively by changes in global energy prices.
The dramatic increase in the cost advantage enjoyed
by Saudi petrochemical producers is at odds with the
lack of changes to the domestic feedstock pricing
regime over the last twelve years. The economic
argument for an increase in domestic feedstock
prices is therefore twofold: that the current cost
advantage is well in excess of what was implicitly
guaranteed when the industry was established; and
that with rising energy prices having allowed the
Feedstock pricing tomorrow
Economics would suggest a sharp increase to USD4-5/mmbtu
However, policy more than economics will set future feedstock prices
We expect to see a gradual rise in feedstock prices, with fundamental
industry competitiveness unaltered
Saudi ethylene cost advantage vs. Naphtha based producers (1990-2010)
0
200
400
600
800
1000
1200
1400
1600
1800
2000
1990 1993 1996 1999 2002 2005 2008 2011
USD
/ton
Saudi ethane cost advantage
1990 to 2003 average USD240/ton
2003 to 2010 average USD760/ton
0
200
400
600
800
1000
1200
1400
1600
1800
2000
1990 1993 1996 1999 2002 2005 2008 2011
USD
/ton
Saudi ethane cost advantage
1990 to 2003 average USD240/ton
2003 to 2010 average USD760/ton
Source: HSBC estimates
19
Natural Resources and Energy Middle East Chemicals January 2011
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Saudi petrochemical industry to generate exceptional
profits over the last seven years, some of those
profits now need to be shared with the government
through an increase in feedstock costs.
Higher prices needed to incentivise production growth and limit demand
New sources of gas, higher production costs
With the exception of Qatar, which has large
resources of non-associated gas, the Gulf
Cooperation Council (GCC) countries have
traditionally been reliant on associated gas (a by-
product of crude production) for their gas needs.
The amount of associated gas available, though, is
limited by the amount of crude production, which
in turn is limited by OPEC quotas.
In recent years, as demand for gas from the power,
infrastructure and petrochemical sectors has grown,
oil companies in the region have started to focus
heavily on exploring for non-associated gas. Their
efforts have borne fruit to a certain extent as the
chart at the bottom of the page shows. Gas
production has increased by 50% since the start of
the last decade while crude production has grown by
only 2% over the same period, highlighting that the
bulk of the gas production growth has come from
non-associated gas fields.
As non-associated gas production grows, the
question of gas pricing starts to gain greater
attention. It is one thing to price associated gas at
very low levels because the costs of production –
since it is a by-product – are minimal and this gas
would have been flared if it were not used by the
petrochemical industry. However, when gas is
produced from non-associated fields, the costs of
production and extraction are dramatically higher
than those for associated gas. In addition, there
are now competing uses for gas from the power,
fertiliser, metal and petrochemicals sectors which
render the traditional argument of a lack of
alternative uses void.
Furthermore, there is a strong case to be made that
if this growth in non-associated gas production is
to be maintained, then exploration companies,
particularly the international ones, need sufficient
incentives to invest in exploring for offshore gas
fields. These companies need to see the potential
to generate an adequate return on capital that
compensates them for both discovery, as well as
production, costs. As almost all of this new gas
production will be consumed domestically,
capping domestic gas prices at the current low
levels limits the attractiveness of gas exploration
in the region and therefore constrains potential
supply. The economic argument for raising
GCC ex Qatar: Oil vs. gas production
12,000
13,000
14,000
15,000
16,000
17,000
18,000
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009
(000
bbl
/d)
10.0
11.0
12.0
13.0
14.0
15.0
16.0
17.0
18.0
19.0
(bcf
/d)
GCC ex Qatar (oil production) GCC ex Qatar (gas production)
12,000
13,000
14,000
15,000
16,000
17,000
18,000
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009
(000
bbl
/d)
10.0
11.0
12.0
13.0
14.0
15.0
16.0
17.0
18.0
19.0
(bcf
/d)
GCC ex Qatar (oil production) GCC ex Qatar (gas production)
Source: BP World Energy Statistical Review 2010
20
Natural Resources and Energy Middle East Chemicals January 2011
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domestic gas prices therefore is that higher prices
would incentivise new production and allow
supply to keep pace with growing demand.
Lower prices result in uneconomic resource allocation
The other economic argument for higher domestic
gas pricing comes from the demand side. Low gas
prices and consequently low retail electricity
prices mean that there is little incentive for users
to ration their consumption, driving rapid demand
growth as shown in the charts at the top of the
page. Power demand in both Saudi Arabia and
Qatar is expected by MEED to double from
current levels over the next decade.
In the absence of supply growth from non-
associated gas, the incremental increase in power
generation will have to come from burning
heavy/fuel oil to generate electricity. On our
estimates, this would imply an increase in fuel oil
consumption to 2.4m bpd from the current levels
of 0.9m bpd, an incremental loss of 1.5m bpd that
could potentially have been exported and a
potential revenue loss of USD110m per day at
current international market prices.
The low gas prices also create the potential for using
ethane for fuel rather than converting it into higher
value added petrochemicals. Ethane can be burnt for
fuel use and at the current delta between Saudi
ethane prices and global fuel oil prices (see table at
the bottom of the page), ethane is being sold at
roughly one tenth of its heating value equivalent.
Ethane has so far not been used for fuel, given its
value as a petrochemical feedstock. However, if
power generation demand continues to grow at the
projected rate and results in a large fall in revenue
due to lost fuel oil sales, the argument for
replacing some of the heating oil that is consumed
with ethane at a tenth of its price will likely start
to take hold. Raising domestic prices would not
only incentivise new gas supply, freeing up
heating oil for export, it would also make ethane
less attractive as a heating oil substitute resulting
in a more economic resource allocation.
To sum up, the economic rationale would be to
raise feedstock prices to levels in line with global
natural gas prices (USD4-5/mmbtu). This would,
in theory, still provide a degree of cost advantage
to the petrochemical producers relative to crude-
based producers while incentivising new supply
and curtailing runaway demand growth.
GCC ex Qatar: Gas consumption Projected growth in power demand (Saudi and Kuwait)
8.0
10.0
12.0
14.0
16.0
18.0
20.0
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009
Gas consumption (bcf/d)
8.0
10.0
12.0
14.0
16.0
18.0
20.0
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009
Gas consumption (bcf/d)
40
10.8
85
21
0102030405060708090
Saudi Arabia Kuwait
GW
2010 2020e
40
10.8
85
21
0102030405060708090
Saudi Arabia Kuwait
GW
2010 2020e
Source: BP World Energy Statistical Review 2010 Source: MEED, HSBC
Natural Resources and Energy Middle East Chemicals January 2011
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A hint as to what policy makers consider a floor for
energy prices is available in the oil price assumption
used while setting annual budgets. Saudi Arabia, for
example, used an average crude price of USD55/bbl
while setting its budget for 2011. It would be
unlikely that the very same policy makers would
then move to considering the current oil price of
USD90/bbl when examining the issue of feedstock
costs for the petrochemical industry.
The table at the bottom of the page outlines our
approach to calculating potential feedstock price
increases for the petrochemical sector. We believe
that the base oil price used to derive industry
competitiveness will be similar to that used by the
Saudi government to set its budget – USD55/bbl.
At that level of crude prices, the marginal cost of
producing a tonne of ethylene is around
USD700/tonne.
Working back from that marginal cost of ethylene
and backing out variable and other operating costs
for the Middle East we get an implied equivalent raw
material cost for the Middle East of USD500/tonne.
At this stage we assume that in order to keep the
competitiveness of the Middle Eastern industry
intact and its cost position firmly within the first
quartile, policy makers would allow a cost advantage
equivalent to the historical average over the 1990-
2010 period of USD375/tonne.
Adjusting for the allowed cost advantage would
imply Saudi ethane costs of USD101/tonne which,
given the ethane requirements for a tonne of
ethylene, translates to an implied gas price of
USD2.1/mmbtu.
Liquids discount unlikely to drop below 25%
Both gas and liquid feedstocks are priced on an
opportunity cost basis. For stranded gas, that
opportunity cost is very low allowing gas to be
priced at a substantial discount to international
prices. For liquids such as propane and butane
which have liquid international markets, the
discount provided to the domestic industry is not a
subsidy, but is in fact a ‘netback’ equivalent price.
In Saudi, for example, if Aramco were to sell
propane in the international market rather than
supplying it to the domestic sector, its effective
net realised price would be significantly lower
than observed market prices on account of supply
chain costs (such as liquefaction, storage,
shipping, distribution and tariffs).
These chain costs are the justification for the
current c30% discount on liquid feedstock prices.
The current schedule for liquids pricing (see table
on page 25) runs up to 2011. We expect to see a
further decrease in the discount, to 25% over the
Potential Saudi feedstock cost framework
Naphtha consumption 3.46 tonne/tonne
Floor Crude price assumption 55 USD/bbl Naphtha costs 495 USD/tonne Raw material costs 1,716 USD/tonne Co product credits 1390 USD/tonne Variable operating costs 300 USD/tonne Incremental costs 80 USD/tonne Marginal cost of ethylene production at crude price of USD55/bbl 706 USD/tonne Working back to derive a Middle East feedstock price in this context Marginal cost of ethylene production at crude price of USD55/bbl 706 USD/tonne less Middle East variable and incremental costs 200 USD/tonne Implied raw material costs 506 USD/tonne less average cost advantage over 1990-2010 period 375 USD/tonne Implied Saudi ethane costs 131 USD/tonne Ethane requirement for a tonne of ethylene 1.29 tonne/tonne Implied ethane costs per tonne 101.3 USD/tonne Implied ethane [gas?] costs 2.1 USD/mmbtu
Source: HSBC estimates
25
Natural Resources and Energy Middle East Chemicals January 2011
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next five years, but believe that given the netback
argument and the fact that the bulk of new Saudi
ethylene capacity has a large proportion of liquids
cracking it is unlikely that the liquids discount
will drop below 25%.
Feedstock pricing forecasts As discussed earlier in the section, we believe that
while there is broad consensus that feedstock
prices in Saudi need to be raised, the decision on
the quantum and timing of the increase will
balance economic considerations with policy
objectives.
While the Saudi government is keen to incentivise
new gas exploration and supply and to ensure
economic resource allocation, it is also cognisant
of the role the Saudi petrochemical industry needs
to play in employment generation. This will likely
be a key consideration driving policymakers to
ensure that feedstock price increases take place in
a phased fashion without shocking the industry or
dramatically altering its competitive dynamic.
We also believe that policy makers will be just as
conservative with their underlying energy price
assumptions when assessing the competitiveness
of the petrochemical industry as they are when
setting the annual budgets. We assess the range of
possible feedstock prices under these constraints
and derive our feedstock pricing framework as
detailed on the previous page.
We raise our forecasts for Saudi gas and ethane
equivalent prices, now factoring in a gradual
increase to USD2.0/mmbtu by 2015, vs a flat
USD0.75/mmbtu previously (see table at the bottom
of the page). We also assume that the liquids
discount will decline by 1ppt each year from the
current 28% before being fixed at 25% in 2014.
HSBC Saudi feedstock pricing assumptions
2011e 2012e 2013e 2014e 2015e
Gas price (USD/mmbtu), New 0.75 1.25 1.50 2.00 2.00 Gas price (USD/mmbtu), Old 0.75 0.75 0.75 0.75 0.75 % Propane Discount, New 28% 27% 26% 25% 25% % Propane Discount, Old 28% 28% 28% 28% 28%
Source: HSBC estimates
26
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Feedstock price impact driven by product and feedstock mix The increases to our feedstock pricing estimates,
taken in isolation, result in a drop in product
margins for the companies within our coverage.
The extent of the drop in margins, though,
depends on the product portfolio of each company
as well as their feedstock mix.
The biggest increases in our feedstock price
estimates are those for natural gas, which impact
products that are methane based – methanol,
ammonia and urea – the most. While the increase in
gas prices also affects the price of ethane, as ethane
prices are quoted on a gas equivalent basis, the drop
in ethane-based product margins is far lower due to
the higher degree of value added in ethane-based
products versus methane-based products (see table at
the bottom of the page).
For liquids based products, the margin impact is
easier to forecast as the product margins are
directly linked to the discount (c30%) to global
feedstock prices. As the discount is reduced in our
estimates by 1ppt each year through 2015, the
margin impact would be similar (ie a drop of 1ppt
each year for liquids based products).
Impact on product pricing and margins
HSBC crude oil price forecast raised to USD82/bbl for 2011, rising a
dollar a year thereafter
We modify our chemical product price and margin estimates to reflect
higher energy prices as well as changes in feedstock pricing
On average the impact of higher crude prices outweighs higher
feedstock costs
Impact of gas feedstock price increases (methane vs. ethane-based products)
Natural gas price (USD/mmbtu) 0.75 2.00
Methane price (USD/mmbtu) 0.75 2.00 Raw material costs for 1 tonne of methanol 26.25 70.00 Change in raw material costs 43.75 Current methanol price (USD/tonne) 380 Margin impact from cost increase -12%
Implied ethane price (USD/tonne) 36.7 97.8 Raw material costs for 1 tonne of ethylene 47.3 126.2 Change in raw material costs for PE (polyethylene) production 78.85 Current LDPE (low density PE) prices (USD/tonne) 1450 Margin impact from cost increase -5%
Source: HSBC estimates
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Natural Resources and Energy Middle East Chemicals January 2011
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Very few companies have either a purely liquid or
purely gas-based product portfolio and therefore
there are multiple moving parts when trying to
assess the impact of a change in feedstock prices
on company profitability. We list the impact of
our feedstock pricing changes on each company
under our coverage assuming constant product
prices below. The rule of thumb is that companies
with the biggest cost advantages and the highest
margins (eg SAFCO) are impacted more on a
percentage basis than companies with the lowest
advantage and margins (eg SABIC).
Of course, one cannot look at product margins on
a feedstock basis alone. Product prices are an
important factor within our margin outlook and
are influenced by both energy costs and supply/
demand. Our bullish long-term supply/demand
outlook (as detailed earlier in the note), coupled
with increases in our oil and gas team’s energy
price forecasts, have resulted in an increase in our
product pricing estimates. In most cases, the
impact from higher product pricing outweighs the
impact of higher feedstock costs.
Changes to HSBC’s oil price forecasts Our global oil and gas team have raised their forecasts
for crude oil prices. The extract below is from the note
“Oil sector outlook” published on 23 January 2011
(Paul Spedding, +44 207 991 6787) highlighting the
rationale behind the change in their oil price forecasts.
Please see the full note for greater detail.
Oil price assumptions
Our Brent assumption for 2011 rises from USD76
to USD82, rising a dollar a year thereafter. We
assume a USD1 premium for WTI.
Oversupply remains
We estimate that OPEC has spare capacity of up
to 6MMbbl/d, or nearly 7% of world demand.
Even assuming not all of this capacity is palatable
to the world’s refining system due to quality,
spare capacity is still probably in the 5MMbbl/d
area. Unlike many other commodities, therefore,
the crude market is not tight; it is potentially in
oversupply.
It is only OPEC’s discipline in keeping crude off the
market since the price collapse in late 2008 that
enabled crude prices to recover to current levels.
What has perhaps been surprising is how stable
crude prices have been during much of 2010, at
least until recently. With hindsight, we suspect
that OPEC was helped by the strong recovery in
its efforts to help oil prices recover from around
USD40 in early 2009.
This meant that it was rarely called upon to
defend the oil price on the downside. So, OPEC
was normally faced with the relatively simple
Impact of feedstock price changes on EBITDA margins *
Company ________ 2012e__________ _________2013e _________ _________ 2014e _________ ________ 2015e _________ New Old New Old New Old New Old
Reuters (Equity) 2350.SE Bloomberg (Equity) KAYAN ABMarket cap (USDm) 7,709 Market cap (SARm) 28,875Free float (%) 25 Enterprise value (SARm) 58710Country Saudi Arabia Sector CHEMICALSAnalyst Sriharsha Pappu Contact 971 4 4236924
Price relative
79
1113151719212325
2009 2010 2011 2012
791113151719212325
Saudi Kayan Petrochemical Rel to TADAWUL ALL SHARE INDEX
Source: HSBC Note: price at close of 19 Jan 2011
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Notes
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Notes
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Notes
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Disclosure appendix Analyst Certification The following analyst(s), economist(s), and/or strategist(s) who is(are) primarily responsible for this report, certifies(y) that the opinion(s) on the subject security(ies) or issuer(s) and/or any other views or forecasts expressed herein accurately reflect their personal view(s) and that no part of their compensation was, is or will be directly or indirectly related to the specific recommendation(s) or views contained in this research report: Sriharsha Pappu and Tareq Alarifi
Important disclosures
Stock ratings and basis for financial analysis HSBC believes that investors utilise various disciplines and investment horizons when making investment decisions, which depend largely on individual circumstances such as the investor's existing holdings, risk tolerance and other considerations. Given these differences, HSBC has two principal aims in its equity research: 1) to identify long-term investment opportunities based on particular themes or ideas that may affect the future earnings or cash flows of companies on a 12 month time horizon; and 2) from time to time to identify short-term investment opportunities that are derived from fundamental, quantitative, technical or event-driven techniques on a 0-3 month time horizon and which may differ from our long-term investment rating. HSBC has assigned ratings for its long-term investment opportunities as described below.
This report addresses only the long-term investment opportunities of the companies referred to in the report. As and when HSBC publishes a short-term trading idea the stocks to which these relate are identified on the website at www.hsbcnet.com/research. Details of these short-term investment opportunities can be found under the Reports section of this website.
HSBC believes an investor's decision to buy or sell a stock should depend on individual circumstances such as the investor's existing holdings and other considerations. Different securities firms use a variety of ratings terms as well as different rating systems to describe their recommendations. Investors should carefully read the definitions of the ratings used in each research report. In addition, because research reports contain more complete information concerning the analysts' views, investors should carefully read the entire research report and should not infer its contents from the rating. In any case, ratings should not be used or relied on in isolation as investment advice.
Rating definitions for long-term investment opportunities
Stock ratings HSBC assigns ratings to its stocks in this sector on the following basis:
For each stock we set a required rate of return calculated from the risk free rate for that stock's domestic, or as appropriate, regional market and the relevant equity risk premium established by our strategy team. The price target for a stock represents the value the analyst expects the stock to reach over our performance horizon. The performance horizon is 12 months. For a stock to be classified as Overweight, the implied return must exceed the required return by at least 5 percentage points over the next 12 months (or 10 percentage points for a stock classified as Volatile*). For a stock to be classified as Underweight, the stock must be expected to underperform its required return by at least 5 percentage points over the next 12 months (or 10 percentage points for a stock classified as Volatile*). Stocks between these bands are classified as Neutral.
Our ratings are re-calibrated against these bands at the time of any 'material change' (initiation of coverage, change of volatility status or change in price target). Notwithstanding this, and although ratings are subject to ongoing management review, expected returns will be permitted to move outside the bands as a result of normal share price fluctuations without necessarily triggering a rating change.
*A stock will be classified as volatile if its historical volatility has exceeded 40%, if the stock has been listed for less than 12 months (unless it is in an industry or sector where volatility is low) or if the analyst expects significant volatility. However,
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stocks which we do not consider volatile may in fact also behave in such a way. Historical volatility is defined as the past month's average of the daily 365-day moving average volatilities. In order to avoid misleadingly frequent changes in rating, however, volatility has to move 2.5 percentage points past the 40% benchmark in either direction for a stock's status to change.
Rating distribution for long-term investment opportunities
As of 23 January 2011, the distribution of all ratings published is as follows: Overweight (Buy) 48% (23% of these provided with Investment Banking Services)
Neutral (Hold) 37% (20% of these provided with Investment Banking Services)
Underweight (Sell) 15% (22% of these provided with Investment Banking Services)
Information regarding company share price performance and history of HSBC ratings and price targets in respect of its long-term investment opportunities for the companies the subject of this report,is available from www.hsbcnet.com/research.
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3 months. 3 At the time of publication of this report, HSBC Securities (USA) Inc. is a Market Maker in securities issued by this
company. 4 As of 31 December 2010 HSBC beneficially owned 1% or more of a class of common equity securities of this company. 5 As of 30 November 2010, this company was a client of HSBC or had during the preceding 12 month period been a client
of and/or paid compensation to HSBC in respect of investment banking services. 6 As of 30 November 2010, this company was a client of HSBC or had during the preceding 12 month period been a client
of and/or paid compensation to HSBC in respect of non-investment banking-securities related services. 7 As of 30 November 2010, this company was a client of HSBC or had during the preceding 12 month period been a client
of and/or paid compensation to HSBC in respect of non-securities services. 8 A covering analyst/s has received compensation from this company in the past 12 months. 9 A covering analyst/s or a member of his/her household has a financial interest in the securities of this company, as
detailed below. 10 A covering analyst/s or a member of his/her household is an officer, director or supervisory board member of this
company, as detailed below. 11 At the time of publication of this report, HSBC is a non-US Market Maker in securities issued by this company and/or in
securities in respect of this company Analysts, economists, and strategists are paid in part by reference to the profitability of HSBC which includes investment banking revenues.
For disclosures in respect of any company mentioned in this report, please see the most recently published report on that company available at www.hsbcnet.com/research.
* HSBC Legal Entities are listed in the Disclaimer below.
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Additional disclosures 1 This report is dated as at 24 January 2011. 2 All market data included in this report are dated as at close 19 January 2011, unless otherwise indicated in the report. 3 HSBC has procedures in place to identify and manage any potential conflicts of interest that arise in connection with its
Research business. HSBC's analysts and its other staff who are involved in the preparation and dissemination of Research operate and have a management reporting line independent of HSBC's Investment Banking business. Information Barrier procedures are in place between the Investment Banking and Research businesses to ensure that any confidential and/or price sensitive information is handled in an appropriate manner.
4 As of 31 December 2010, HSBC and/or its affiliates (including the funds, portfolios and investment clubs in securities managed by such entities) either, directly or indirectly, own or are involved in the acquisition, sale or intermediation of, 1% or more of the total capital of the subject companies securities in the market for the following Company(ies) : ADVANCED PETRO CHEMICAL C
5 As of 07 January 2011, HSBC owned a significant interest in the debt securities of the following company(ies) : SAUDI BASIC INDUSTRIES CO
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Disclaimer * Legal entities as at 31 January 2010 'UAE' HSBC Bank Middle East Limited, Dubai; 'HK' The Hongkong and Shanghai Banking Corporation Limited, Hong Kong; 'TW' HSBC Securities (Taiwan) Corporation Limited; 'CA' HSBC Securities (Canada) Inc, Toronto; HSBC Bank, Paris branch; HSBC France; 'DE' HSBC Trinkaus & Burkhardt AG, Dusseldorf; 000 HSBC Bank (RR), Moscow; 'IN' HSBC Securities and Capital Markets (India) Private Limited, Mumbai; 'JP' HSBC Securities (Japan) Limited, Tokyo; 'EG' HSBC Securities Egypt S.A.E., Cairo; 'CN' HSBC Investment Bank Asia Limited, Beijing Representative Office; The Hongkong and Shanghai Banking Corporation Limited, Singapore branch; The Hongkong and Shanghai Banking Corporation Limited, Seoul Securities Branch; The Hongkong and Shanghai Banking Corporation Limited, Seoul Branch; HSBC Securities (South Africa) (Pty) Ltd, Johannesburg; 'GR' HSBC Pantelakis Securities S.A., Athens; HSBC Bank plc, London, Madrid, Milan, Stockholm, Tel Aviv, 'US' HSBC Securities (USA) Inc, New York; HSBC Yatirim Menkul Degerler A.S., Istanbul; HSBC México, S.A., Institución de Banca Múltiple, Grupo Financiero HSBC, HSBC Bank Brasil S.A. - Banco Múltiplo, HSBC Bank Australia Limited, HSBC Bank Argentina S.A., HSBC Saudi Arabia Limited., The Hongkong and Shanghai Banking Corporation Limited, New Zealand Branch.
Issuer of report HSBC Bank Middle East Ltd PO Box 502601 Dubai UAE Telephone: +97 14 5077333 Fax: +97 14 3535079 Website: www.research.hsbc.com