CHINA ENERGY IN FOCUS INDUSTRY UPDATE -...

EQUITY RESEARCH 27 March 2012

CHINA ENERGY IN FOCUS US shale gas – a model for China?

There are views that the exploitation of shale gas reserves in the US and the subsequent collapse in gas prices has opened opportunities to exploit the price differential between America and emerging economies like China, where prices are higher and resources are limited by lack of developed infrastructure. After taking a closer look at the debate as well as discussing the impact that developing China's own vast reserves will have on its industrial base in the future, we conclude that low US natural gas prices will not challenge China’s low-cost model but accelerate the country’s own resource development.

Benefits for power equipment makers: The US shale gas revolution could be a model for China in accelerating production and infrastructure to secure long-term supply beyond pipeline/LNG. Increasing gas supply should support the increased buildout of gas-fired power generation significantly beyond the 4% of total electricity consumption today vs. 20-25% in mature countries, with benefits including 1) lower pollution, 2) higher efficiency, 3) low capital investment and 4) load balancing. Key beneficiaries would likely be the power equipment makers: Shanghai Electric (1-OW, PT HK$5.0) and Dongfang Electric (1-OW, PT HK$35.0).

US chemicals companies’ low-cost advantage unlikely to impact China near term: Despite the sharp fall in US production costs for commodity chemicals, exports may still not find their way to China as the US recovery picks up and Europe offers better profitability for exports as pricing improves. In the long term, low-cost chemical production in the US has stimulated new capacity investments; however, these are unlikely to come onstream until after 2015 and, hence, should have only a minimal impact on global chemical supply/demand balances.

No large-scale shifts for steel producers: Although we believe that the lower US natural gas price will benefit the US steel industry, cost benefits are not large enough to cause a large-scale shift in global steel capacity to North America from Asia, in our view. We remain cautious over Asian steel with our key underweight being China Steel (3-UW, PT HK$25.0).

US LNG exports may benefit shipbuilders: The removal of the US as a potential “growth customer” for LNG has two knock-on effects: 1) the potential for increased demand for LNG vessels for which Samsung Heavy (010140 KS, not rated) is the largest builder and 2) the strengthening of China’s bargaining position, which could be leveraged to expedite Chinese’s shipyards move into higher-end off-shore construction. YZJ Shipbuilding (1-OW, PT HK$2.20) has begun a join venture with Qatar Investment Corp. to build off-shore platforms in China.

Barclays Capital Inc. and/or one of its affiliates does and seeks to do business with companies covered in its research reports. As a result, investors should be aware that the firm may have a conflict of interestthat could affect the objectivity of this report.

Investors should consider this report as only a single factor in making their investment decision.

This research report has been prepared in whole or in part by equity research analysts based outside theUS who are not registered/qualified as research analysts with FINRA.

PLEASE SEE ANALYST(S) CERTIFICATION(S) AND IMPORTANT DISCLOSURES BEGINNING ON PAGE 30.

INDUSTRY UPDATE Asia ex-Japan Marine Transportation 2-NEUTRAL Unchanged Asia ex-Japan Metals & Mining 1-POSITIVE Unchanged Asia ex-Japan Oil & Gas 1-POSITIVE Unchanged China Power Equipment 1-POSITIVE Unchanged

Asia ex-Japan Oil & Gas Scott Darling +852 290 33998 [email protected] Barclays Bank, Hong Kong Clement Chen +852 290 32498 [email protected] Barclays Bank, Hong Kong China Power Equipment Guo Shou, CFA +852 290 34536 [email protected] Barclays Bank, Hong Kong Asia ex-Japan Metals & Mining Ephrem Ravi +852 290 34892 [email protected] Barclays Bank, Hong Kong Asia ex-Japan Marine Transportation Jon Windham, CFA +852 290 34672 [email protected] Barclays Bank, Hong Kong

Barclays | China Energy In Focus

27 March 2012 2

EQUITY VALUATIONS

Figure 1: Valuations for selected Asian companies mentioned in this report*

EV/EBITDA, x P/E, x P/B, x

Dividend yield, %

Company* Rating

s

Closing Price 23-Mar

Price target

Potential Upside/

Downside to PT 11E 12E 13E 11E 12E 13E 11E 12E 13E 11E 12E 13E

Power equipment 1-Pos

Dongfang Electric 1-OW HK$ 19.4 35.0 80% 4.9 4.0 3.6 9.9 8.6 7.6 2.3 1.9 1.5 1.0 1.2 1.3

Harbin Electric 2-EW HK$ 8.14 9.50 17% 0.3 0.3 0.3 8.3 7.8 7.3 0.8 0.8 0.7 2.6 2.0 2.2

Shanghai Electric 1-OW HK$ 3.86 5.00 30% 3.0 2.7 2.4 12.9 11.2 9.7 1.3 1.2 1.0 2.4 2.7 3.1

Oil & Gas 1-Pos

CNOOC 1-OW HK$ 16.38 21.0 28% 4.6 4.4 4.1 8.7 8.3 7.9 1.8 1.5 1.3 3.1 3.3 3.4

PetroChina 1-OW HK$ 11.04 13.5 22% 6.0 5.5 5.1 12.4 11.4 10.4 1.2 1.1 1.0 3.6 4.0 4.3

Sinopec 2-EW HK$ 8.64 10.0 16% 4.3 4.1 3.9 8.2 7.2 6.9 1.3 1.1 1.0 3.0 3.5 3.6

Sinopec Shanghai NR - - - 12.9 10.3 8.4 13.3 10.3 7.7 0.9 0.9 0.8 2.0 1.9 2.7

Metals & Mining 1-Pos

Angang Steel 2-EW HK$ 4.85 8.30 71% - 6.9 3.9 - - 5.7 0.9 0.6 0.5 - 1.5 7.6

China Steel 3-UW NT$ 30.05 25.0 (17%) - - 14.4 - - 20.2 1.8 1.8 1.7 3.6 2.4 4.3

Maanshan 3-UW HK$ 2.17 2.81 29% 9.6 6.4 4.1 24.9 - 8.3 0.8 0.5 0.5 - 2.3 4.2

Industrials 2-Neu

China COSCO 3-UW HK$ 4.42 3.20 (28%) - 18.0 7.1 - - 19.6 0.9 1.0 0.9 - - -

China Merchants 1-OW HK$ 26.2 26.6 (2%) 14.6 13.7 12.8 10.3 12.6 11.2 1.5 1.4 1.3 4.0 3.0 4.0

Daewoo Shipping NR - - - 7.8 9.4 8.3 8.7 11.4 9.4 1.4 1.3 1.1 1.0 1.5 1.5

Hyundai Heavy NR - - - 10.8 9.0 8.2 12.5 8.0 7.7 1.7 1.2 1.1 2.0 1.9 2.2

Samsung Heavy NR - - - 6.8 8.1 7.4 9.4 10.4 9.3 1.9 1.5 1.3 1.0 1.2 1.2

Yangzijiang 1-OW S$ 1.33 2.20 65% 4.6 6.1 6.0 6.4 8.1 7.9 2.0 1.7 1.4 6.0 3.0 3.0

Notes: *This is not a complete list of Barclays Research’s Asian equity research coverage as only selected equities shown. Data omitted for rated companies is either not applicable or meaningful. Stock ratings: 1-OW: 1-Overweight, 2-EW: 2-Equal Weight, 3-UW: 3-Underweight. NR = Not rated. Sector views: 1-Pos: 1-Positive, 2-Neu: 2-Neutral, 3-Neg: 3-Negative. For full disclosures on each rated company, including details of company-specific valuation methodology and risks, please refer to: http://publicresearch.barclays.com. Prices as of the market close on 23 March 2012 in local currency. Valuation data for equities that are not rated by Barclays Research are consensus estimates from Bloomberg. Source: Bloomberg, Barclays Research estimates


27 March 2012 3

CONTENTS

EQUITY VALUATIONS........................................................................................................................2

US SHALE GAS – A MODEL FOR CHINA? .......................................................................................4

US NATURAL GAS OUTLOOK: FINDING A NEW COAL FLOOR...................................................8

POWER & EQUIPMENT: CHINA TO ACCELERATE NATURAL GAS CONSUMPTION..............11

PETROCHEMICALS: LIMITED IMPACT ON SUPPLY/DEMAND DYNAMICS IN CHINA.........17

METALS & MINING: NO LARGE SCALE SHIFT FOR STEEL PRODUCERS.................................20

INDUSTRIALS: IMPACT FROM CHANGING LNG DYNAMICS....................................................26


27 March 2012 4

US SHALE GAS – A MODEL FOR CHINA?

The tight natural gas market has prompted China to accelerate progress in shale gas developments with the auctioning of new blocks and government proposals to offer fiscal support to developers.

China shale gas still faces several challenges namely export pipeline availability to demand centres and water availability.

These obstacles are secondary relative to the real issues such as development economics (cash break evens at US$7-9/mbtu), application of technology and project management rather than geology and resource quality, in our view.

China is tapping its own unconventional gas reserves

China ranks as one of the largest non-conventional (coal bed methane and shale gas) resource holders globally (Figures 2-4). According to China’s Ministry of Land and Resources, China has 25.08 trillion cubic meters (tcm) of technically recoverable onshore shale gas reserves and 134.42 tcm of total resources. This compares with the technically recoverable reserves of the US at only 12-13 tcm (according to the US Energy Information Administration in its 2012 Annual Energy Outlook, in which it downgraded the US shale reserves by 42%).

Figure 2: Non-conventional gas by region

Figure 3: Shale gas geographical split

0

20

40

60

80

100

120

140

160

180

200

NorthAmerica

SouthAmerica

Europe Africa Asia

CBM Shale gas Tight gastcm

Europe10%

US13%

Other Asia8%

Canada6%

Africa16%

South America

28%

China19%

CBM = coal bed methane Source: IHS, Barclays Research

Chart shows technically recoverable resources of shale gas Source: US Energy Information Administration, Barclays Research

Tight market should promote new supply sources We have previously highlighted that we see a gradual increase in natural gas pricing reform and price harmonisation in China with the eventual development of a provincial natural gas grid structure (see Barclays research: Initiating coverage on China Oils: value in upstream growth, 12 December 2011). Domestic natural gas production growth in China has only averaged c14% pa 2000-10. In contrast, natural gas demand growth has averaged 16% pa over the same period and a government target for 240bcm in 2015, implying 15% pa growth, which looks increasingly achievable should China meet or exceed power capacity

EQUITY RESEARCH Asia ex-Japan Oil & Gas 1-POSITIVE Scott Darling +852 290 33998 [email protected] Barclays Bank, Hong Kong China Power Equipment 1-POSITIVE Guo Shou, CFA +852 290 34536 [email protected] Barclays Bank, Hong Kong

China has one of the world’s largest recoverable shale gas

resources

https://live.barcap.com/go/publications/content?contentPubID=FC1773505�



27 March 2012 5

Figure 4: China has the highest percentage of the world’s shale gas reserves

Proved Natural Gas Reserves Recoverable Shale Gas Resources

(trillion cubic meters) (trillion cubic meters)

Europe/Eurasia

Poland 0.12 5.30

France 0.01 5.10

Norway 2.04 2.35

North America

United States 7.72 12-13*

Mexico 0.49 19.28

Canada 1.73 10.99

Asia

China 2.81 25.05*

India 1.45 1.78

Pakistan 0.82 1.44

Australia 2.92 11.21

Africa

South Africa 0.00 13.73

Libya 1.55 8.21

Algeria 4.50 6.54

South America

Argentina 0.35 21.92

Brazil 0.42 6.40

Chile 0.10 1.81

Note: * updated in 2012 Source: US Energy Information Administration, BP Statistical Review 2011, Barclays Research

targets.1 This suggests the country’s natural gas supply/demand balance is very tight in the medium term (Figure 5); thus, we expect the government to incentivise natural gas investment (in both conventional and non-conventional natural gas) to manage the country’s natural gas requirements.

Figure 5: China’s natural gas supply/demand

050

100150200250300350400450500

2008A 2010A 2012E 2014E 2016E 2018E 2020E 2022E 2024E 2026E 2028E 2030EChina Domestic Contracted LNG Turkmenistan BaseMyanmar China Shale/CBM LNG UpsideOther Central Asia Turkmenistan Upside Russia WestRussia East Demand (Low) Demand (Mid)Demand (High)

bcm

China’s natural gas market remains tight until end of the

decade, assuming demand (mid case in figure) growth at 15% pa

to 2015E then 4% pa to 2030E

Source: Oxford Institute for Energy Studies, Barclays Capital

1 See Barclays research, China Power Equipment, Power up for the long ride, 29 November 2011


27 March 2012 6

Slow shale gas progress, but starting to gather pace China continues to outline its non-conventional gas targets. The government has the set 6.5bcm/year by 2015 and 60-100bcm/year for shale gas production by the end of the decade. Although we believe that these targets may seem ambitious2, the pace of progress in acquiring non-conventional asset for technology/process knowledge and domestic developments is starting to gather pace. China is committed to supporting development with numerous overseas joint ventures (JVs) and acquisitions for exploratory technology and production experience, namely:

August 2010, PetroChina acquired Arrow Energy jointly with Shell, which focuses on exploratory technology learning in Australia’s coal-seam gas reserves.

October 2010, CNOOC entered into a landmark US$2bn deal with Chesapeake Energy (US) for a 33% stake in Eagle Ford (a significant producing US shale gas asset).

October 2011, Sinopec Group acquired Canada’s Daylight Energy for US$2.1bn, gaining access to Canada’s oil and shale gas reserves.

January 2011, Sinopec Corp and CNOOC invested in Enbridge Energy’s pipeline that connects oil sands in Alberta to the West Coast.

January 2012, Sinopec Group farmed in to one third of Devon Energy’s shale gas assets in North America for US$2.5bn.

March 2012, Sinopec and Total sign a joint venture agreement for the development of shale gas in China.

March 2012, Shell and PetroChina sign China’s first shale gas production sharing agreement in Fushun-Yongchuan block in Sichuan basin.

There are also significant advancements in domestic development – China launched the country’s first shale gas tender offer for four blocks in southern China in mid-2011 with six domestic firms competing (PetroChina, CNOOC, Sinopec, Shaanxi Yanchang, China United Coalbed Methane, Henan Provincial Coal Seam Gas Development). Foreign partners are only allowed to partner with domestic bidders. In addition, CNPC along with foreign partners such as Royal Dutch Shell and Chevron are developing shale gas blocks in Sichuan province. The Ministry of Land and Resources announced in March 2012 that it will hold another 1-2 shale tenders in 2012.

Less about geology, more about cost and project management We have previously highlighted the challenges facing China’s non-conventional gas development, namely export pipeline availability to demand centres and water availability (see Barclays Commodities research, Natural gas weekly kaleidoscope, China: the next big shale story, 16 November 2010). However, while these factors are important, we believe the key issues in determining the pace of shale gas developments in China relate to development economics, application of technology and project management rather than geology and resource quality. For most of the shale gas deposits in China, the technology is in place (ie the US and most parts of China are based on the same type of marine shales3). Shale gas is positioned at the high end of the hydrocarbon cost curve (Figure 6), and first

2 Sinopec’s recent management meeting, the company believe “non-conventional resources can be a major contributor for not only Sinopec, but China overall” in the long term. In addition, Sinopec management see the government’s target shale gas resource and production guidance as “a little conservative”. 3 We appreciate that the shale gas resource base in China also contains laucstrine shale, ie fresh water derived, which tends to have “clay-like” quality with a high water content and lower hydrocarbon content.

First shale gas block tenders launched in mid-2011

Assuming clarity over subsidy and tax terms, we see project

management and application of existing technology as the key factors for China reaching its shale gas production targets




27 March 2012 7

projects are likely to have high capital costs where project cash break even requires about US$7-9/mbtu for example in Sichuan province according to Wood Mackenzie (Figure 7). We would expect the government to provide some subsidy or tax breaks to support shale gas development similar to coal bed methane.4 However, if these issues can be overcome with clarity over subsidy and tax terms, the main issue is project management to fine-tune the extraction process. We would expect the international oil companies to manage projects assuming there is sufficient economic incentive to invest. We see Shell, Chevron, BP and ExxonMobil well positioned to work with Chinese energy companies having been in the country for many years or having overseas JV projects.

Figure 6: Global energy cost curve

0

20

40

60

80

100

120

0 3 6 9 12Cumulative resources (trillion boe)

Oil: 4.3 trillion bbl @ US$67/bbl Gas: 7 trillion boe @ US$42/boe

MENAConventional gas

Other conventional oil Tight gas CBM Shale gas

Deepwater Heavy oil

Arctic

Shale oilBreakeven price US$/bl

Non-conventional gas is large proportion of the global

hydrocarbon resource base, but typically conventional gas

remains lower cost

Chart shows a broad estimate by hydrocarbon type. Economics

may vary significantly by country and project

CBM = Coal Bed Methane. MENA = Middle East and North Africa Source: US Energy Information Administration, US Geological Survey, Barclays Research

Figure 7: Full cycle cash costs for selected US project vs China

China will need to provide subsidies and tax break to

incentivise shale gas projects

0123456789

Eagle

Ford

Niobrara

Marc

ellus (

dry gas)

Montn

ey

Barnett

Fayett

eville

Horn Rive

r

China CBM

Haynes

ville

Bossier

Woodford

China shale gas

US$/mbtu

Source: Talisman from Wood MacKenzie, Barclays Research estimates

4 China’s National Energy Administration, a division of the NDRC are discussing with the Ministry of Finance a plan to increase the coal bed methane subsidy from Rmb0.2/cm to Rmb0.5/cm. To our knowledge, there are no published fiscal terms for shale gas developments. We would expect a production sharing contract type which may have a similar fiscal structure to some coal bed methane contracts where terms tend to have a royalty up to 3%, cost recovery c70%, profit oil up to 80-90% (contractor share based on production sliding scale), VAT rebate and subsidy.


27 March 2012 8

US NATURAL GAS OUTLOOK: FINDING A NEW COAL FLOOR

The oversupply in the gas market has been even larger than market expectations. Chunky supply additions coupled with mild winter weather have crushed natural gas prices starting in 4Q11.

With a record inventory overhang expected at the end of the winter season (end of March 2012), the market will need the power sector to absorb a record amount of gas. This should push coal displacement to at least an annual average of 6 Bcf/d, about a third higher than in 2011, to avoid challenging storage capacity in October. We expect coal displacement to ramp up slowly through the year, balancing the natural gas market at an annual average price of $3.05/MMBtu.

Although we expect supply growth to slow somewhat in 2013, prices are likely to recover only slightly from 2012 levels as a large supply overhang next year is expected to again require 2012 levels of coal displacement to balance the market. We expect prices in 2013 to average $3.25.

Overwhelming supply growth keeps pressuring 2012 prices Although our forecast has been among the most bearish in the market, natural gas supply last year exceeded our expectations (Figure 8). Despite an increasingly widespread pessimistic mood in the market, we believe no one expected prices to fall so far and so fast in 4Q11 and into 1Q12. Prices have hit multi-year lows. The compound effects of warm weather and accelerating supply growth have been matched by power demand that appears to be slow in reacting to tumbling prices.

The market fears that supply will run so much higher than demand that there will be no spare storage capacity at the end of the injection season. One might expect producer restraint in an over-supplied market with low prices, yet we expect US production in 2012 to grow an incremental 2.7 Bcf/d y/y, even after growing almost 4 Bcf/d y/y in 2011. The incremental growth reflects our view that gas production should be strong due to the following: a still-too-high gas-directed rig count; associated gas from liquids-rich and unconventional oil plays; the completion and connection of drilled-but-uncompleted wells; and the debottlenecking of the Marcellus shale basin as new pipelines enter service. Figure 9 shows that even though the natural gas-directed rig count has fallen recently, natural gas production has surged. Although producers have been shifting rigs from dry gas basins to liquids-rich areas, these liquids-rich wells often yield significant volumes of natural gas. Figure 10 shows that producers are adding oil rigs at a rate that is almost three times faster than the drop-in gas-directed rigs.

We believe producers are loathe to cut flowing gas production. During the previous plunge in prices (2009), very little gas was shut in, although this round of low prices could test producer resolve. In addition, producers are fairly well hedged for 2012. Our credit research team released its regular producer hedging report last month showing that producers had 46% of oil/gas production hedged for 2012, with natural gas hedges at $5.52-5.67. Producers have since added modestly to hedge positions. Furthermore, producer revenue is also less sensitive to gas prices even when they are not hedged. According to data from our equity analysts, by 2012, the sample of producers in our analysis is expected to derive 64% of revenues from liquids owing to strong oil and NGLs prices. Therefore, when hedges are also considered, producers are fairly well insulated from low gas prices.

COMMODITIES RESEARCH Shiyang Wang* +1 212 526 7464 [email protected] Michael Zenker* +1 212 526 2081 [email protected] This is an excerpt from “Global Energy Outlook: Oil upside, rising capex”, 1 March 2012. *Commodities analysts are members of the Fixed Income Research department and are not equity research analysts. For analyst certifications and important disclosures, please refer to "Global Energy Outlook: Oil upside, rising capex", as above.

Supply has outpaced expectations

Producers are relatively well hedged for 2012





27 March 2012 9

With supply climbing significantly, the only demand component that could aid an over-supplied market is the power sector. Since 2009, power plant dispatchers in the Eastern US have worked to re-shuffle the merit order of natural gas and coal units in the region as gas prices dipped into the range of coal prices. As a result, whenever it is possible economically and logistically, gas runs instead of coal. Coal displacement in 2011 averaged roughly 4.5 Bcf/d, about 2 Bcf/d higher than our estimate for 2010. To not exceed the maximum working gas storage capacity given our supply estimates, our models indicate that coal displacement would need to grow to nearly 6 Bcf/d on average in 2012. This represents more than 8% of total natural gas demand. With certain periods of the year reaching as high as 7-8 Bcf/d of coal displacement, we expect natural gas to start displacing a fair amount of Illinois Basin and some Power River Basin coal delivered to the East, Midwest and Texas during parts of the year. Simply put, gas must price lower to find new demand.

These and other factors are weighing on near-term prices. We believe natural gas prices do not have a floor in the short term. The market is nervous that coal displacement may not be high enough to rid the market of surplus supply. Moreover, contractual obligations that require owners of gas in certain storage fields to draw down their inventory by the end of March (storage ratchets) could create a short-term glut of gas, which would severely drag prices lower. We expect to end winter (end of March 2012) with storage levels at a record high of 2.2 Tcf, which is 22% above the previous record.

This surplus would automatically put the market on track for high inventories for the remainder of 2012. With the market nervous that demand cannot soak up spare gas even with low prices, there will be an ongoing fear of insufficient room in storage for surplus supply. Thus, if the market tests the maximum working gas storage capacity at the end of October, which we expect, it will create another period later this year of very weak prices.

Supply growth slows in 2013 but prices will have limited upside

Our balances indicate that production growth in 2013 will slow slightly compared with 2011 and 2012 (Figure 11). Associated gas production from liquids-rich and oil drilling, along with further debottlenecking of supply basins, will continue to add to supply. However, prices should still have trouble rebounding significantly as the large supply overhang from 2012 will still need to be worked off in 2013. Even with a boost in demand from an assumed return to normal weather in 2012-13, we are depending on coal displacement to be the marginal demand.

With only 20% or so of 2013 gas hedged, drilling next year could be a very different story. While we believe drilling is not highly responsive to short-term prices, we have found producer actions greatly affected by whether they are hedged. Forward prices have fallen in near lockstep with prompt-month prices, dragging 2013 rapidly lower ($3.76/MMBtu as of this writing). If producers refrain from hedging 2013 gas, this could mean a bullish pullback in drilling heading into next year, although there is plenty of time to hedge 2013 production. However, a significant pullback in gas-directed drilling might still be too late for prices to recover in any meaningful sense in 2013. With a higher level of supply in 2013 and our forecast for 1% organic demand growth, we continue to expect downward pressure on prices and for gas to price deeply into the coal stack in 2013 to balance the market.

The market needs a lot of coal displacement to balance

Storage ratchets could push cash prices even lower in March

Gas supply growth will continue, albeit at a lower rate in 2013


27 March 2012 10

$3 gas

Our price forecast for 2012 is $3.05/MMBtu. We expect the market to still balance above $3.00 for the year as power generators increasingly respond to low natural gas prices and displace coal in growing size. However, gas must remain near this level to price a sufficient amount of coal out of the market. As production growth slows a bit in 2013, we expect natural gas prices to average $3.25, about 50 cents below the current price of calendar 2013.

Figure 8: Amount that supply has exceeded our production forecast for the US excluding Alaska(Bcf/d)

Figure 9: US natural gas production excluding Alaska (Bcf/d, LHS) vs gas-directed rig count lagged by one month (RHS)

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

Jul-11 Aug-11 Sep-11 Oct-11 Nov-11 Dec-11

56

57

58

59

60

61

62

63

64

65

Jan-11 Mar-11 May-11 Jul-11 Sep-11 Nov-11760

780

800

820

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860

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920

940lower-48 natural gas production

gas-directed rig count

56

57

58

59

60

61

62

63

64

65

Jan-11 Mar-11 May-11 Jul-11 Sep-11 Nov-11760

780

800

820

840

860

880

900

920

940lower-48 natural gas production

gas-directed rig count

Source: US Energy Information Administration, Bentek, Barclays Research Source: US Energy Information Administration, Baker Hughes, Barclays Research

Figure 10: Cumulative change in gas-directed and oil-directed rig count in the US

Figure 11: US quarterly supply growth, y/y, Bcf/d

-300

-200

-100

0

100

200

300

400

500

600

700

Aug-10 Nov-10 Feb-11 May-11 Aug-11 Nov-11

decline in gas-directed rig count

gain in oil-directed rig count

0.00.51.01.52.02.53.03.54.04.55.0

Q1

2011

Q2

2011

Q3

2011

Q4

2011

E

Q1

2012

E

Q2

2012

E

Q3

2012

E

Q4

2012

E

Q1

2013

E

Q2

2013

E

Q3

2013

E

Q4

2013

E

Source: Baker Hughes, Bloomberg, Barclays Research Source: US Energy Information Administration, Barclays Research estimates


27 March 2012 11

POWER & EQUIPMENT: CHINA TO ACCELERATE NATURAL GAS CONSUMPTION

We estimate China’s domestic installed gas power capacity at 73 GW by 2015 and 140 GW by 2020, above the National Energy Administration’s (NEA) target of 60GW by 2015. Gas currently accounts for only c.4% of primary energy consumption in China. Although China has seen consistent double-digit growth in gas consumption since 2000, we believe current supply/infrastructure problems are hindering even faster growth. We see continued acceleration in gas consumption growth, particularly from power generation as its 1) low pollution status, 2) high efficiency with co-generation (heating + electricity) properties, 3) low capital investment, and 4) importance in load balance and renewable power integration become evident in the coming decade. For additional details on our gas power end-market outlook, see “China Power Equipment: Power up for the long ride” of 29 November 2011.

The US natural gas evolution, brought on by the development in shale gas, could be a model for China in the next decade. We see favourable and increasing policy support in gas supply, infrastructure and consumption in China. The National Development Reform Commission (NDRC) targets gas usage at 8% of primary energy consumption by 2015 and 10% by 2020 (vs. about 4.4% in 2010). This translates into about 240 billion cubic meters (bcm) of demand by 2015 and 450 bcm by 2020 vs. 106 bcm in 2010, or a CAGR of 18% and 14% in the 12th and 13th Five-Year periods (Figure 12). Near term, the NEA calls for a doubling of large gas powered plants to 60GW by 2015 vs. c.30GW today (

Figure 13) and support for 50GW of gas-fired distributed generation by 2020 (vs. 5GW today).

Figure 12: China’s gas industry – we see accelerating consumption in the next 5 years

5yr CAGR:0.0% 4.6%

7.0%13.2%

17.4%

2011-2015 CAGR:17.8%

106

240

0

50

100150

200

250

300

1985

1990

1995

2000

2005

2010

2015

ENat

ural

Gas

Con

sum

ptio

n (b

illio

n cu

bic

met

ers)

2010 – 2015 Supply Bridge: LNG regas: +47 Bcm Pipelines: +67 Bcm CBM + Shale: +20 Bcm Total incremental: +134 Bcm

Source: China’s National Bureau of Statistics, Barclays Research estimates

Figure 13: China’s gas industry – forecasts for total installed power capacity

18 22 25 27 31 33 40 53 67 82 100 122 145 170 195220

3.7%

6.5%

10.2%

0

50

100

150

200

250

2005 2006 2007 2008 2009 2010 2011E 2012E 2013E 2014E 2015E 2016E 2017E 2018E 2019E 2020E

Tota

l Cap

acit

y (G

W)

0.0%

2.0%

4.0%

6.0%

8.0%

10.0%

12.0%Natural Gas Power Total Capacity (CCGT, Co-gen, distributed gen)

% of total power gen by capacity

Source: China Electricity Council, China’s National Energy Administration, Barclays Research estimates

EQUITY RESEARCH China Power Equipment 1-POSITIVE Guo Shou, CFA +852 290 34536 [email protected] Barclays Bank, Hong Kong

“We will … tackle key problems more quickly in the exploration and development of shale gas, and increase the share of new energy and renewable energy in total energy consumption.”

– Premier Wen Jiabao 11th National People’s Congress,

5 March 2012



27 March 2012 12

Positive implications on power equipment makers and gas power producers

Shanghai Electric (2727 HK, 1-OW, PT HK$5.0), Dongfang Electric (1072 HK, 1-OW, PT HK$35.0) and Harbin Electric (1133 HK, 2-EW, PT HK$9.5) all produce gas turbines for power plants (via JVs with foreign partners – Siemens, MHI, GE, respectively) and we believe could see substantial increases in demand over the coming years. As gas turbines have high entry barriers given technological hurdles, we see the oligopoly of three dominating the market as it expands over the next decade.

Our estimate of 73GW in installed gas power capacity by 2015 and 140 GW by 2020 (100/220 GW including distributed generation) translates into an equipment market of RMB265.5bn from 2011-20 or an average of RMB26.5bn/yr vs. an average of RMB3.9bn/yr from 2006-10. We assume an average installed cost of about RMB3,500/kW, of which about 40% is in equipment (Figure 14-17).

We see a gas equipment market of RMB265.5bn from 2011-2020

Figure 14: China’s power equipment makers – market shares for gas equipment

Figure 15: China’s power equipment makers – gas exposure as percentages of backlogs

Harbin21%

Others (foreign)

20%

Dongfang25%

Shanghai34%

2%

3% 3%

0%

1%

2%

3%

4%

Harbin(1133 HK)

Shanghai(2727 HK)

Dongfang(1072 HK)

Source: Company reports, Barclays Research estimates Source: Company reports, Barclays Research estimates

Figure 16: China’s power equipment makers – annual gas equipment demand forecasts

Figure 17: China’s power equipment makers – substantial increase in domestic gas turbine production in 2011

220 GW

100 GW

40 GW

0

5

10

15

20

25

30

35

40

2006

2008

2010

2012

E

2014

E

2016

E

2018

E

2020

E

Ann

ual G

as E

quip

. Mkt

(R

MB

bn)

0

50

100

150

200

250

Gas

tota

l cap

acit

y (G

W)

Annual Equip. MktTotal Capacity

253150

1349

200

400

600

800

1000

1200

1400

1600

2009 2010 2011

Gas

turb

ine

prod

ucti

on (M

W) Domestic Gas Turbine

Production (MW)

Source: China Electricity Council, Barclays Research estimates Source: China Machinery Industry Federation, Barclays Research


27 March 2012 13

Gas-fired generation is currently only a small percentage of total power capacity in China (3.7%), and amongst the large power producers, only Beijing Jingneng Clean Energy (579 HK, not-rated) has substantial exposure with about 52% of its listed assets in gas generation (all in Beijing). Beijing is the largest consumer of gas by municipality orprovince in China (Figure 18) and expects to further quadruple its gas-fired power capacity to 8GW from 2GW at the end of 2010 (BJCE will add another 2.24GW by 2013/14 from 1.2GW today). We see continued policy support for gas generation in Beijing (and across the country) at the expense of coal with stricter standards on air quality, especially with the introduction of the PM2.5 standard in early 2012. For BJCE, policy support comes in the form of favourable tariffs, especially in Beijing where cost increases are subsidised by the local government.

Figure 18: China’s gas industry – provincial gas supply profile (2010)

7.2

5.3 4.7 4.53.3

2.51.7 1.7 1.6 1.6 1.5 1.4 1.3 1.2 1.1 1.1 1.1 1.1 0.7 0.7 0.7 0.7 0.6 0.5 0.4 0.1 0.1 0.1 0.0 0.0

012345678

Beiji

ng

Sich

uan

Jiang

su

Shan

ghai

Shan

dong

Cho

ngqi

ng

Gua

ngdo

ng

Tian

jin

Shaa

nxi

Hen

an

Hub

ei

Shan

xi

Xin

jiang

Zhe

jiang

Anh

ui

Hun

an

Nin

gxia

Heb

ei

Gan

su

Hei

long

jiang

Inne

r

Liao

ning

Qin

ghai

Fujia

n

Jilin

Hai

nan

Jiang

xi

Gua

ngxi

Gui

zhou

Yunn

an

Tibe

t

Gas

con

sum

ptio

n (b

n cu

bic

met

er)

Source: National Bureau of Statistics, Barclays Research

Benefits of gas-fired generation

Gas-fired generation has multiple benefits (Figure 19), including 1) low pollution, 2) high efficiency (generating both heat and power), 3) low capital investment and 4) fast start-up times, which means it can be used as load balancing/peak shaving power for grid efficiency (this is especially important for integrating variable power from renewable energy such as wind and solar).

With a significant increase in heat demand in northern China during the winter months, power companies adopt a cogeneration model whereby steam from the power generator is further utilised to provide heat supply in the city or sold to industrial end-users. This allows cogeneration plants to achieve a higher energy utilisation rates (as much as 80%) and lower land and water usage vs. traditional coal-fired generators. These benefits have allowed cogeneration plants to receive favourable policy support in past years (especially in Beijing). During the winter, cogeneration plants tend to enjoy priority dispatch of electricity.

Figure 19: Natural gas power generation vs. coal

Advantages of a natural gas based power plant over coal

Land use Natural gas power plants typically require 54.0% of the land area compared with a thermal coal power plant Water consumption A natural gas power plant consumes one-third of the water that a thermal coal power plant consumes Emission levels A 500 MW gas power plant produces 81% lower levels of nitrogen oxide, 58% lower CO2 and almost no sulfur

oxide compared with an equivalent capacity thermal coal power plant Post installation expenditure Natural gas power plants do not require follow-up investment on environmental protection compared with coal

power plants, which require additional expenditures to meet environment-related standards Efficiency Gas and steam combined power generator delivers an efficiency of 60.0% (and as much as 80% during winter

months) against 41.9-45.3% for coal power generators.

Source: CNPC CPPEI, Barclays Research

Gas co-gen plants have as much as 80% energy efficiency in the

winter months


27 March 2012 14

We believe gas-fired generation could play an increasingly important role in power load balancing in China over the next decade. Two of the major advantages of gas plants are 1) their flexibility as cycling or peaking plants to balance load curves and 2) their low capital cost. This means that gas plants can be built fast and cheap (cheapest RMB/kW in construction cost) and fired up only when necessary to optimise overall fleet operating costs for utilities. This feature is well utilised in countries with mature gas-fired generation such as the US (25% of total power generation vs. 4% in China) and can be applied favourably both to baseload generation (such as coal and nuclear) as well as renewables (wind and solar).

The European Climate Foundation estimates in its “Roadmap to 2050” report that about 1 MW of backup capacity is needed for every 7-8 MW of wind and solar PV capacity. This translates to 32-36 GW of gas-fired capacity by 2020 (vs. our estimated 140 GW) just to manage wind/solar power generation (Figure 20).

Figure 20: Natural gas plants have the cheapest construction costs

3,576 4,064 4,185 4,5946,882

9,52911,200

14,68716,000

20,957

0

5,000

10,000

15,000

20,000

25,000

Nat Gas (CCGT)

Coal (SC)

Coal (USC)

CombinedHeat &Power

Hydro (conven.)

Wind onshore

NuclearCPR-1000(Gen II+)

NuclearAP-1000(Gen III)

Wind offshore

Solar PV

Ove

rnig

ht C

onst

ruct

ion

Cost

(R

MB/

kW)

Construction timeline: Non-hydro renewables: < 1 year Gas-fired plants: 1-2 years Coal-fired plants: 2-3 years Nuclear power plants: 5-6 years

Source: International Energy Agency, Nuclear Energy Agency, Barclays Research estimates

China’s gas consumption and future gas supply

Gas usage in China accounts for only about 4% of energy consumption vs. 21% global average (Figure 21). While China saw double-digit CAGR in gas consumption since 2000, we believe current gas supply/infrastructure problems in China are hindering faster growth. However, we see numerous positive shifts in China’s gas infrastructure development and supply. China’s gas demand has outpaced production meaningfully in the past decade and we believe its strategy in securing future supply is both on imports (pipeline and LNG) and tapping its own conventional and unconventional gas reserves (shale, coal-bed methane). Policy-makers are also initiating pricing reforms to stimulate domestic production such as 1) market-linking Guangdong and Guangxi gas prices in December 2011 and 2) setting targets for shale gas production at 6.5bcm/year by 2015 and 60-100bcm/year that amount by 2020).

While numerous technical challenges remain in tapping unconventional gas reserves, China seems committed to supporting its costly development (vs. conventional gas) with numerous overseas JVs and acquisitions for exploratory technology and production experience. We think the reason is simple – energy security. It is difficult to justify the build-out of a large complicated and extremely expensive gas infrastructure (similar to the US)

Gas generation is important in power load balancing

Gas consumption is only 4% of energy consumption vs. 21%

global average


27 March 2012 15

unless longer term (50+ years) of supply can be secured, which extends much beyond the fickle security of 10-20year pipeline and LNG contracts. The significant potential for domestic unconventional gas on the tail-end of the gas supply chain gives China confidence to develop its gas infrastructure from large diameter long-haul transmission to distribution networks, including the last mile of the gas reticulation system as in developed countries (centralized storage of gas to provide instant supply to households vs. hazardous small gas tanks). This is especially true if China will be competing for gas from other Asian neighbors such as Japan as well as developing nations such as India.

Figure 21: China’s gas consumption per capita is significantly lower than global levels

82

2,182

7471,163

2,287

5,003

476 590

0

1,000

2,000

3,000

4,000

5,000

6,000

Chi

na

USA

Japa

n

Euro

pe

Am

eric

as

Mid

dle

East

Afr

ica

Asi

aPa

cific

Gas

con

sum

ptio

n pe

r ca

pita

(c

ubic

met

ers/

popu

lati

on) gas power plants only

account for half of consumption

Source: BP Statistical Review 2011, Barclays Research

Multiple pipeline and LNG import projects may increase gas availability Pipeline gas imports could significantly increase over the next few years. China’s only operating import pipeline (1,833 km West-East pipeline), began operations in 2009 with 3.6 bcm of imports in 2010. However, with the completion of the second stage in 2011, China could import as much as 65Bcm by 2012 (according to its recent supply contract with Turkmenistan). There are also other pipeline projects under construction, such as the Sino-Burma pipeline (1,100 km), expected to startup in 2012-2013 with 12 bcm/yr of capacity. Other potential capacity includes the Russia-China Altai pipeline (30-70 bcm), which may bring gas from Siberia to Xinjiang where it may connect with the West-East pipeline.

China is also upgrading its gas distribution pipeline – at the end of 2009, it has 36,000 km of trunk line but will add 24,000km of trunk and 8,000km of branch lines by 2015 and 20,000-30,000km per year of distribution lines. Sinopec estimates that China will see 300,000km of gas pipeline construction over the next decade. PetroChina and Sinopec (China’s two leading gas producers) are rapidly building natural gas infrastructure over the next five years, in line with expectations of increased supply. The two are planning to build storage tanks with a capacity of 30 Bcm vs. today’s capacity of 3 Bcm.

China has three LNG import terminals at the end of 2010, accounting for 9.3 million tonnes per annum (mtpa) of capacity, but with six more terminals under construction and 21 more approved/proposed, the capacity could grow 10x to over 92 mtpa by 2020 (Figure 22). China Oil companies are tying up interest in other LNG developments to secure supply (eg Australia).

40Bcm of gas imports in 2011 vs. 3.6Bcm in 2010 with completion

of pipeline

LNG import capacity to grow 10x to 92 mtpa by 2020 vs.

9.3 mtpa today


27 March 2012 16

Figure 22: China’s LNG import capacity can grow 10x by 2020

LNG Terminal Project Operator/Developer Startup Capacity (mtpa) Status

Operational Dapeng - Phase I CNOOC/BP Jun 2006 3.7 Online Fujian - Phase I CNOOC Feb 2009 2.6 Online Shanghai - Phase I CNOOC Oct 2009 3.0 Online

Operational - Total 9.3 Under Construction Jiangsu - Phase I PetroChina Jun 2011 3.5 Construction Dalian - Phase I PetroChina 4Q 2011 3.0 Construction Fujian - Phase II CNOOC 2012 5.0 Construction Zhejiang Ningbo - Phase I CNOOC 2012 3.0 Construction Guangdong Zhuhai - Phase I CNOOC/Yudean 2013 3.4 Construction Shandong - Phase I Sinopec Nov 2013 3.0 Construction

Under Construction - Total 17.4 Approved/Proposed Tangshan - Phase I PetroChina 2013 3.5 Approved Hainan - Phase I CNOOC early 2014 2.0 Approved Shenzhen - Phase I CNOOC 3.0 Approved Shanghai - Phase II CNOOC 3.0 Approved Zhejiang Ningbo - Phase II CNOOC 6.0 Approved Dalian - Phase II PetroChina 6.0 Approved Jiangsu - Phase II PetroChina 3.0 Approved Shandong - Phase II Sinopec 6.0 Approved Zhuhai Sinopec ? Approved Tianjin Sinopec ? Approved Guangxi Sinopec ? Approved Wenzhou Xinao Gas 3.0 Approved Qinzhou PetroChina ? Planned Rizhao Daesung 0.5 Planned Guangdong Dapeng - Phase II CNOOC 6.2 Proposed Zhuhai - Phase II CNOOC 8.5 Proposed Hainan - Phase II CNOOC 2017-2020 3.0 Proposed Jieyang - Phase I CNOOC 2.0 Proposed Zhanjiang CNOOC ? Proposed Shenzhen PetroChina ? Proposed Tangshan - Phase II PetroChina 10.0 Proposed

Approved/Proposed - Total 65.7+

Source: Company reports, Barclays Research estimates


27 March 2012 17

PETROCHEMICALS: LIMITED IMPACT ON SUPPLY/DEMAND DYNAMICS IN CHINA

The cost of producing US ethylene-derived chemical products relative to Asia has fallen sharply owing to low US natural gas price creating a cash cost arbitrage between both regions.

Despite US cost advantaged chemical production vs Asia, ethylene-derived exports to Asia may slow owing to a recovery in US domestic demand and improved pricing to other regions such as Europe offering better profitability.

In the long term, low natural gas prices are stimulating new chemical investment in the US, leading to increased plant additions post 2015. However, commodity chemical producers in China such as Sinopec (2-EW, PT HK$10) and Sinopec Shanghai Petrochemical (not rated) are unlikely to see any substantial impacts to changes in ethylene-derived chemical supply/demand dynamics in Asia and globally owing to the relative size of incremental capacity globally.

Petrochemical cost structure determined by feedstock

The chemicals industry essentially employs a strategy of cost leadership, particularly for commodity chemicals (ie, ethylene derivatives and basic chemicals), with those producers unable to compete on cost moving toward a differentiation approach. These commodity chemicals are essentially produced from either naphtha feedstock (refined from crude oil) or ethane feedstock (derived from natural gas). Typically, Asian chemical plant particularly in China, use naphtha, while US tend to use ethane (Figure 23-24).

Figure 23: Asia feedstock favours naphtha…

Figure 24: …US more biased to ethane

Naphtha63%

Ethane28%

LPG9%

Other5%

Other

7%

LPG17%

Ethane63%

Naphtha13%

Source: CMAI, Barclays Research Source: CMAI, Barclays Research

Wide cost gap between US and Asia petrochemicals

With crude oil (and hence naphtha) historically having traded at a discount to natural gas in most regions, typically naphtha-derived chemical production is at the higher end of the cash cost curve than ethane biased plant. However, the oversupply in the US natural gas market has resulted in a wide oil and natural gas price differential on an energy equivalent basis (Figure 25). US chemical plant cash cost for ethylene have moved down the cost curve closing the gap with the Middle East, traditionally the lowest cost region globally for chemical output and increased the cost gap with Asia (Figure 26-27). On average, cash costs for Asian ethylene production are cUS$1000-1200/t relative to cUS$500/t in the US.

EQUITY RESEARCH Asia ex-Japan Oil & Gas 1-POSITIVE Scott Darling +852 290 33998 [email protected] Barclays Bank, Hong Kong Clement Chen +852 290 32498 [email protected] Barclays Bank, Hong Kong

mailto:[email protected]�


27 March 2012 18

Figure 25: US natural gas and WTI price differential

US natural gas prices trade at a large discount to WTI

Oil market is influenced by a

cartel, OPEC likely to support a high oil price environment, while

US natural gas prices are determined by regional

supply/demand dynamics

0

5

10

15

20

25

1998 2000 2002 2004 2006 2008 2010 2012E

US$/mbtu

0%

20%

40%

60%

80%

100%

120%Gas as a % of crude, RHSHenry HubWTI

Source: Bloomberg, Barclays Research estimates

Figure 26: US now at low end of cost curve

US ethylene cash cost differential

with Asia is cUS$700/t

0

200

400

600

800

1,000

1,200

1,400

KSAethane

Iranethane

KSANGLs

Canadaethane

KSAnaphtha

KSApropane

USethane

Avg US SE Asia NE Asia WestEurope

Ethylene cash costs, US$/mt

KSA = Kingdom of Saudi Arabia. NGL = natural gas liquids Source: CMAI, Barclays Research estimates.

Figure 27: Cash costs for ethylene production for the US and Asia

Cost arbitrage between US and

Asia ethylene production is likely to remain wide in medium term

0

200

400

600

800

1,000

1,200

1,400

1990 1993 1996 1999 2002 2005 2008 2011 2014E

US ethane cash costs

SE Asia naphtha cash costs

US$/ton

Chart shows ethylene cash costs for a standard US ethane and Asian naphtha cracker. Source: CMAI, Barclays Research estimates


27 March 2012 19

Price differentials favour exports to Europe

Low US natural gas prices since 2009 have increased ethylene derived chemical exports to Asia (Figure 28) owing to lower production costs in the US and strong demand growth in Asia. While it would that this dynamic would continue owing to persistently lower US natural gas prices supporting US plant economics, recovery in domestic US demand for ethylene derived chemicals and improved price differentials with other regions such as Europe, exports have started to fall which we expect to be sustained in the medium term (Figure 29). In the long term, the low cost of chemical production has stimulated investment in new ethylene capacity. However, with the lead time for construction of a new greenfield or large expansion c2-4 years, incremental capacity is likely to start up toward end of the decade. With incremental capacity only representing c3% current global ethylene capacity, we believe that the impacts on both global and Asian supply/demand dynamics are limited.

Figure 28: US polyethylene imports absorbed domestic demand

US polyethylene exports to Asia

have slowed as domestic US demand recovers and pricing

improves

0

1

2

3

4

1991 1994 1997 2000 2003 2006 2009 2012E 2015E 2018E

mtpa

0

2

4

6

8

10

12US$/mbtuUS natural gas price, RHS

Chart shows US polyethylene exports and US natural gas prices (RHS). Source: CMAI, Bloomberg, Barclays Research estimates

Figure 29: Global ethylene price differentials

Price differentials favour US exports to Europe rather than

Asia

(300)

0

300

600

900

1200

Jan-08 Oct-08 Jul-09 Apr-10 Jan-11 Oct-11 Jul-12E Apr-13E

Asia-US ethylene price

Europe-US ethylene price

US$/ton

Chart shows price differentials for ethylene derivatives from the US to Europe and Asia. Source: CMAI, Barclays Research


27 March 2012 20

METALS & MINING: NO LARGE SCALE SHIFT FOR STEEL PRODUCERS

Structurally lower gas prices: while benefiting the US & Canadian mini-mills will not alter the face of the global steel industry

While we believe that a structurally lower gas price will definitely be of benefit to the steel industry in North America, the cost benefits are not large enough to cause a large-scale shift in global steel capacity to North America from Asia, in our view. The main beneficiaries in the near term of the rise in shale gas production in the steel industry are likely to be the OCTG steel pipe manufacturers who supply to the shale gas industry and providers of DRI technology and plants like Midrex. Some of the smaller scale mini-mills and low grade iron ore producers could also benefit.

What has changed? The shift in gas/coal energy cost parity The whole debate has come about as gas has gotten significantly cheaper relative to other energy sources with the advent of shale gas. Gas is increasingly becoming the most competitive source of reductant energy in a blast furnace.

Coal in a steel furnace has two basic uses – to provide ‘reductant energy’ to the iron making process and as a source of carbon for the steel (hence the term ‘carbon steel’). In 2008, gas became cheaper on a US$/BTU basis to Prime Hard Coking coal, and in 2010 it became cheaper than PCI coal. Given the gas prices in the first three months of the year, natural gas has become lower than ever thermal coal (Figure 30).

Figure 30: Relative energy cost between gas and different coal types

0.0

0.5

1.0

1.5

2.0

2.5

2000 2002 2004 2006 2008 2010 2012YTD

HH Gas / Prime HCC HH Gas / PCI Coal HH Gas/ Seaborne Thermal Coal

Gas Cheaper

Coal Cheaper

Parity

Source: Datastream, Bloomberg, Barclays Research

Case study – DRI industry and gas prices

What is DRI? DRI is the product obtained by reducing (removing oxygen content) iron ore into iron, but below iron’s melting point. In India, it is also called sponge iron. As DRI processes operate at lower temperatures (gas-based DRI processes like MIDREX operate at 900C compared to over 1500C in a conventional blast furnace) the processes tend to be more efficient. The other advantage is scale, with DRI plants having smaller critical scale requirements (and hence more flexibility in adding capacity).

EQUITY RESEARCH Asia ex-Japan Metals & Mining 1-POSITIVE Ephrem Ravi +852 290 34892 [email protected] Barclays Bank, Hong Kong


27 March 2012 21

The disadvantages of DRI include:

Increased material handling (especially if the sources of iron ore are further from gas (as is the case in many middle-eastern countries or if the downstream processing of steel is away from energy sources); and

Most DRI processes (except those which used fluidized beds) require pelletized or lump iron ore (which tend to be rare and more expensive than fine iron ore. However, some of the low grade iron ore deposits which need to be pelletized to make it commercial anyway (a popular example being the Mesabi range iron ore in Minnesota in the US) can use DRI to improve their commercial effectiveness.

Global DRI production really started to take off from the mid-late 1980s (Figure 31). The effects of the global oil shock had worn off and there was cheap gas available – especially in the Caribbean region (Mexico, Venezuela, Trinidad) and the Middle East (Iran, Saudi Arabia, Qatar). With the MIDREX technology gaining ground, these sources of ‘stranded’ gas could be exploited for iron reduction and producing DRI.

Figure 31: World DRI production 1970-date

0

10

20

30

40

50

60

70

80

1970 1975 1980 1985 1990 1995 2000 2005 2010

Mill

ion

tonn

es o

f DRI

/HBI

per

ann

um

Source: Midrex, Barclays Research

Currently, the largest producers in the world are clustered near the gas belt around the Gulf of Mexico and the Middle East (Figure 32-33).

Figure 32: World DRI/HBI production by country (2010)

Figure 33: World DRI/HBI production by region (2010)

0

5

10

15

20

25

Indi

aIra

nSa

udi A

rabi

aM

exic

oRu

ssia

Vene

zuel

aTr

inid

ad

Egyp

tM

alay

sia

Qat

arIn

done

sia

Liby

aSo

uth

Afr

ica

Cana

daG

erm

any

Oth

ers

Mill

ion

tonn

es p

er y

ear

Middle East / North Africa

Sub-Saharan Africa

2%

North America

1%

Latin America & Carribean

20%

Former Soviet Union/ Eastern Europe

7%

Western Europe

1%

Asia Oceania

38%

Source: Midrex, Barclays Research Source: Midrex, Barclays Research


27 March 2012 22

The notable exception (and the producer of a third of the world’s DRI) is India where cheap coal has enabled DRI production to flourish in the last decade (Figure 34).

Figure 34: Resource endowments of the main DRI/HBI producing countries of the world

Country 2010

production Gas/Coal Energy -Rich?

India 23.4 Coal Yes - Coal Iran 9.4 Gas Yes - Gas Saudi Arabia 5.5 Gas Yes - Gas Mexico 5.4 Gas Yes - Gas Russia 4.7 Gas Yes - Gas Venezuela 3.8 Gas Yes - Gas Trinidad 3.1 Gas Yes - Gas Egypt 2.9 Gas Yes - Gas Malaysia 2.4 Gas Yes - Gas Qatar 2.2 Gas Yes - Gas Indonesia 1.4 Gas Yes - Gas Libya 1.3 Gas Yes - Gas South Africa 1.1 Coal Yes - Coal Canada 0.6 Gas Yes - Gas Germany 0.5 Gas No Others 2.9 N.A

Source: Midrex, Barclays Research

In fact, nearly two-thirds of the growth in DRI production over the last decade came from India, not from the more common gas-feedstock producers (Figure 35-36).

Figure 35: World DRI/HBI production market share (2000)

Figure 36: World DRI/HBI production market share (2010)

India13%

Iran11%

Saudi Arabia7%

Mexico13%

Russia4%

Venezuela13%

Others39%

India33%

Iran13%Saudi Arabia

8%

Mexico8%

Russia7%

Venezuela5%

Others26%

Source: Midrex, Barclays Research Source: Midrex, Barclays Research

An industry that has been hostage to gas prices Gas prices have been critical to the growth of DRI in the past – the golden age of DRI was in the 1990s when gas prices were low (Figure 37).

DRI production grew at a staggering 10x the rate of steel production – the CAGR of DRI production growth 1990-2000 was 9.5% vs 0.95% for crude steel production (for which DRI is a feedstock) and its share of steel-making feedstock grew from 2% in 1989 to 5.2% by 2000 (Figure 38).


27 March 2012 23

However, then gas prices started increasing and the rise of DRI as a popular feedstock stalled. DRI production grew at 4.9% between 2000 and 2010, marginally lower than the 5.1% growth in crude steel production. DRI’s share of crude steel feedstock fell marginally from 5.2% to 5% over the same period (Figure 39).

Figure 39: DRI production growth rates and gas prices

0%

2%

4%

6%

8%

10%

12%

14%

16%

1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010

DRI

gro

wth

rat

e (3

yr r

ollin

g av

g)

-12345678910

Gas

Pri

ce (

Hen

ry H

ub -

US$

/MM

BTU

)

Gas Price DRI growth rate

Low Gas Prices, Fast DRI Growth

High Gas Prices, Slow DRI Growth

Source: Datastream, Midrex, Barclays Research

As noted earlier, almost all the growth in DRI production in the last decade was not in the traditional ‘gas hubs’, but in India (where coal and iron ore are found in geographic proximity, encouraging production of sponge iron).

Will DRI/HBI change the face of global steel-making again? With the rise of shale gas production, the world of gas is undergoing a structural shift. The gas prices are close to the lowest they have been for a decade (Figure 40).

Importantly for the steel producers, gas not has become a cheaper reductant than the various types of coking coals, and even thermal coals (Figure 41).

Figure 37: DRI/HBI production and crude steel production

Figure 38: Proportion of the world crude steel produced using DRI/HBI as primary feedstock

0

200

400

600

800

1,000

1,200

1,400

1,600

1970 1975 1980 1985 1990 1995 2000 2005 2010

Cru

de S

teel

Pro

duct

ion

(mn

tonn

es)

-

10

20

30

40

50

60

70

80

Wor

ld D

RI P

rodu

ctio

n (m

n to

nnes

)

Crude Steel DRI

0%

1%

2%

3%

4%

5%

6%

1970 1975 1980 1985 1990 1995 2000 2005 2010

Source: Worldsteel, Midrex, Barclays Research Source: Worldsteel, Midrex, Barclays Research


27 March 2012 24

Figure 40: US Henry Hub Gas Price

Figure 41: Simple cost comparison of energy from Gas and Coal

01

2

345

67

89

10

1990

1992

1994

1996

1998

2000

2002

2004

2006

2008

2010

2012

YTD

US$

/MM

BTU

0

2

4

6

8

10

12

2000 2003 2006 2009 2012YT

US$

/MM

BTU

by

ener

gy s

ourc

e

Henry Hub Gas Prime HCCPCI Coal Seaborne Thermal Coal

Source: Datastream, Bloomberg, Barclays Research Source: Datastream, Bloomberg, Barclays Research

However does this mean that steel-making is going to be fundamentally changed forever? We think not (at least not on a 5-10 year view).

While it clearly makes a difference for the high cost steel mills, even at a US$2/MMBTU gas (lower than current spot), the cost differential on a ‘normalized’ basis will offset the cost of steel-making in large integrated blast furnaces (Figure 42). The benefit of DRI is that it can be used in smaller mini-mills providing flexibility for operations – however it would be difficult to replace the economies of scale of a large integrated mill.

Figure 42: Cost of steel production (HRC at mill gate) for an average steel producer

500

520

540

560580

600

620

640

660

680

700

Canada - Gas DRIbased Mill

Mexico - Gas DRIbased Mill

Egypt - Gas DRIbased Mill

India - Coal DRIbased Mill

China - largecoastal BlastFurnace Mill

US - Gas DRIbased Mill @

6/MMBTU gas

US - Gas DRIbased Mill @

2/MMBTU gas

US$

/t o

f Cas

h co

st fo

r H

RC US$52/t

(7%)

Source: Barclays Research estimates

That being said, the benefits of lower gas prices are critical for the smaller mini-mills (especially in North America). Everything else being equal, a structural reduction in gas prices from US$6/mbtu to US$2/mbtu translates into a cost differential of over US$50/t (and possibly higher with ability to blend in lower quality scrap for many products). With most of these companies making much lower margins than US$50/t currently, a doubling


27 March 2012 25

of gross margin (and an even bigger impact on the net profit level) assuming price levels remains constant is a big difference.

Will lower costs of steel production in the US shift the balance in global steel trade? Again, while we think it will at the margins, a fundamental transformational shift is unlikely. The cost reduction of steel-making by >US$50/t is definitely feasible. However, Chinese export prices are at a discount of over US$120/t currently (with an average of US$95/t over the past five years). A differential of over US$70/t in pricing is required to incentivise cross-continental steel trade. Even with a US$100/t differential, it is unlikely that US production can possibly become a net exporter into the global markets (Figure 43).

Figure 43: Price differential between Chinese export price and US domestic price for HRC

-100

-50

0

50

100

150

200

250

300

350

400

Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12

US$

/ to

nne

Average = 95

Source: Steel Business Briefing, Barclays Research


27 March 2012 26

INDUSTRIALS: IMPACT FROM CHANGING LNG DYNAMICS

The US natural gas market has evolved from the “dumping ground” for spot LNG cargoes last decade, to proposals for liquefaction terminals this decade. This may partly change LNG shipping trade, with increased demand from Asia “pulling” more LNG to the East.

New LNG projects, such as in Australia and possibly North America, may support backlogs for shipbuilders in the region in the medium term. Hudong Zhonghua (HUDOGZ CH, not rated) in China, and Samsung Heavy (010140 KS, not rated) and Daewoo Heavy (042660 KS, not rated) in Korea, and historically, Daewoo Shipbuilding, Hyundai Heavy (009540 KS, not rated) and Mitsubishi Heavy (7011 JP) have built LNG vessels.

LNG – In a tighter spot

Liquefied Natural Gas (LNG) is a relatively small, but growing component of seaborne trade. LNG contributes less than 3% of total energy consumption. Natural gas trade is still predominately done through pipelines, which comprise over 70% of international trade in natural gas. The seaborne LNG trade is primarily servicing relatively isolated (island) demand centres in North Asia (Figure 44-46).

Figure 44: Major exports (sq meters mn)

Figure 45: Major imports (sq meters mn)

Algeria9%

Australia10%

Nigeria6%

Egypt6%

Oman4%

Qatar21%

Trinidad8%

Other13%

Indonesia11%

Malaysia12%

Spain11%

Japan36%

S. Korea14%

N. America7%

Other2%

Taiwan5%

China3%

France5%

India5%

OtherEurope

8%

UK4%

Source: Clarksons Research, Barclays Research Source: Clarksons Research, Barclays Research

The push to diversify customer base Japan and Europe comprise about 60% of LNG demand. Both regions have a significant drawback of being relatively slower growing end-markets. The removal of the US as a likely long-term “growth customer” does pressure LNG suppliers to secure reliable, long-term and growing customers. In our view, this has increased the bargaining power of China. We see increasing potential that China will be able to leverage its bargaining position to expedite Chinese shipyards’ moves into higher-end off-shore construction, including off-shore rigs and LNG vessels. On 3 January 12, Yangzijiang Shipbuilding (YZJ SP, 1-OW, PT HK$2.20), a Chinese shipyard, established YZJ Offshore Engineering Pte Ltd, a JV with Qatar Investment Corporation. Ultimately, the agreement includes the plan to acquire 1.25 million square meters of land outside of Shanghai for the construction of a new shipyard. The shipyard is being built in 2012-13 for the construction of off-shore vessels and platforms.

EQUITY RESEARCH Asia ex-Japan Marine Transportation 2-NEUTRAL Jon Windham, CFA +852 290 34672 [email protected] Barclays Bank, Hong Kong

LNG accounts for less than 3% of global energy demand


27 March 2012 27

Figure 46: LNG seaborne trade flow

N. America

Algeria

India

PRC

Korea Japan

Nigeria

Aus

ExportersImporters

Europe

Trinidad

Egypt

Oman

QatarTaiwan

Indo

M’sia

LNG supply toNortheast Asia

Southeast Asia 46%Middle East 27%Australia 16%Other 11%

LNG supply to Europe

Middle East 40%Algeria 30%Nigeria 14%Trinidad 11%Other 5%

LNG supply to N. America

Trinidad 43%Middle East 29%Nigeria 18%Other 10%

N. America

Algeria

India

PRC

Korea Japan

Nigeria

Aus

ExportersImportersExportersImporters

Europe

Trinidad

Egypt

Oman

QatarTaiwan

Indo

M’sia

LNG supply toNortheast Asia

Southeast Asia 46%Middle East 27%Australia 16%Other 11%

LNG supply to Europe

Middle East 40%Algeria 30%Nigeria 14%Trinidad 11%Other 5%

LNG supply to N. America

Trinidad 43%Middle East 29%Nigeria 18%Other 10%

Source: Clarksons Research, Barclays Research

LNG vessels

LNG is a niche market compared with other vessels, accounting for only 14% of the total value of new vessel ordering in the past eight years. There are currently only 66 LNG vessels on order compared with 1,120 tankers, 3,278 dry bulk and 614 container vessels on order. The primary LNG shipyards with current orders are Hudong Zhonghua (HUDOGZ CH, not rated) in China and Samsung Heavy (010140 KS, not rated) and Daewoo Heavy (042660 KS, not rated) in Korea. Historically, Daewoo Shipbulding, Hyundai Heavy (009540 KS, not rated) and Mitsubishi Heavy (7011 JP) have also built LNG vessels.

Figure 47: Global energy consumption

Figure 48: CAGR of major seaborne cargos (2001-11)

Oil34%

NuclearEnergy

5%Natural Gas21%

Hydroelectric

6%

Other4%

LNG2%

Coal28%

0%

1%

2%

3%

4%

5%

6%

7%

8%

9%

Oil

Gra

ins

Cok

ing

coal

Ther

mal

coal LN

G

Con

tain

ers

Iron

ore

Source: BP Statistical Review, IEA, Clarksons Research, Barclays Research Source: Clarksons Research, Barclays Research

LNG accounts for 14% of long-term new vessel ordering


27 March 2012 28

LNG vessel ownership

The largest Chinese LNG owner is China LNG Shipping, a JV between COSCO, China Merchants (144 HK, 1-OW, PT HK$25.63) and CNOOC (883 HK, 1-OW, PT HK$21), with 0.9mn cubic meters of carrying capacity, less than 2% of global capacity (Figure 49-50).

Figure 49: Top LNG vessel owners

Figure 50: Global fleet development

- 1 2 3 4 5 6 7

Kawasaki Kisen

Teekay LNG

Nippon Yusen

Mitsui OSK

MISC

Qatar Gas

Capacity cu. M (mn)

11%

7%

6%

6%

4%

4%

Global market share

0

10,000

20,000

30,000

40,000

50,000

60,000

1993

1995

1997

1999

2001

2003

2005

2007

2009

2011

0%

5%

10%

15%

20%

25%

30%000s cu m (LHS)

y/y growth (RHS)

Source: Clarksons Research, Barclays Research estimates Source: Clarksons Research, Barclays Research

LNG order book LNG orderbook stood at 10.5mn cbm as of 12 February 2012. Top builders by order

backlog are Samsung Heavy Industries (010140 KS, not rated) with 4 mn cbm, equivalent to 38% of the global total, Hyundai Heavy (2.4 mn cbm, 23%), Daewoo Shipbuilding and Marine Engineering (1.8 mn cbm, 17%), STX Offshore (067250 KS, not rated) (0.8 mn cbm, 8%) and Hudong Zhonghua (0.8 mn cbm, 8%), see Figures 51-53.

Samsung Heavy has the largest orderbook of US$4bn in contract value, equivalent to 33% of FY11 revenues of US$12b (Kr13 tr).

Figure 51: Top LNG vessel builders

Country Korea Korea Korea Korea China Korea Others Global total

Shipyard Samsung Heavy

Hyundai Heavy

Daewoo Shipbuilding

STXShipbuilding

Hudong Zhonghua

Mitsubishi H.I.

LNG orderbook

Vessels # 25 15 11 5 5 3 2 66

Capacity mn cu m 4.0 2.4 1.8 0.8 0.8 0.5 0.2 10.5

mn dwt 2.1 1.3 0.9 0.5 0.4 0.2 0.1 5.5

Global market share % 38% 23% 17% 8% 8% 4% 2% 100%

Source: Clarksons, Barclays Research


27 March 2012 29

Figure 52: LNG orderbook (US$bn), end Feb 12

Figure 53: Period end order book

Japan, $0.8b, 6%

China, $1.1b, 9%

Korea, $10.8b, 85%

14

7

3

1010

0

2

4

6

8

10

12

14

16

2008 2009 2010 2011 Feb-12YTD

mn

CBM

Capacity

Source: Clarksons, Barclays Research Source: Clarksons, Barclays Research

LNG exports becoming reality North American LNG exports have the potential to compete in cost terms in the global LNG market. Yet the successful development of liquefaction terminals will depend not only on economics, but also on the ability of project sponsors to secure long-term off-take agreements, gain access to capital, and obtain regulatory permits. The massive capital requirements and the need for long-term off-take contracts suggest that the development of North American liquefaction is likely to require the involvement of large, credit-worthy entities with a track record of operation.

Given current proposals 5 and provided that projects can obtain regulatory permits, we believe North America could acquire 1–2 Bcf/d of LNG export capability by 2017. In our view, the multiple announced projects are vying for a limited set of buyers, suggesting that some of the proposed projects will not come to fruition by 2017. Although we believe the North American resource base could support a greater amount of liquefaction capacity, we see regulatory approvals/permitting, financing projects and securing long-term off-take agreements as the main factors in determining the extent to which many projects are developed. Our LNG supply/demand balance is shown in Figure 54.

Figure 54: LNG: increments in regasification and liquefaction capacity

bcf/d bcm/y

2011 2012E 2013E 2014E Total 2011 2012E 2013E 2014E Total

Regasification 3.5 3.6 3.9 6.8 17.8 36.2 36.9 40.4 70 184

Liquefaction 1.9 1.5 0.6 2.6 6.5 19.4 15.3 6.2 26.5 67

Balance (R-L) 1.6 2.1 3.3 4.3 11.3 17 22 34 44 117

Source: Woodmac, Waterbourne, ICIS Heren, Company websites, Barclays Research estimates

5 The most recent new project seems to be BP, ExxonMobil and ConocoPhillips are in talks about a potential $40bn LNG export project from Alaska according to the Financial Times (FT), 21 March 2012. BP and partners have been trying for more than 20 years to find a way to commercialise stranded gas in Alaska. The initial thought was a $20bn pipeline to the lower 48 but that was moth-balled when US gas prices fell in response to the shale gas revolution. According to the FT the consortium is due to agree on a lease dispute next week with the State of Alaska, which would be necessary ahead of any trial studies on a potential LNG development.


27 March 2012 30

ANALYST(S) CERTIFICATION(S)

We, Scott Darling, Clement Chen, Guo Shou, CFA, Ephrem Ravi and Jon Windham, CFA, hereby certify (1) that the views expressed in this research report accurately reflect our personal views about any or all of the subject securities or issuers referred to in this research report and (2)no part of our compensation was, is or will be directly or indirectly related to the specific recommendations or views expressed in this researchreport.

IMPORTANT DISCLOSURES CONTINUED

Barclays Research is a part of the Corporate and Investment Banking division of Barclays Bank PLC and its affiliates (collectively and each individually, "Barclays"). For current important disclosures regarding companies that are the subject of this research report, please send a writtenrequest to: Barclays Research Compliance, 745 Seventh Avenue, 17th Floor, New York, NY 10019 or refer to http://publicresearch.barcap.com or call 212-526-1072.

The analysts responsible for preparing this research report have received compensation based upon various factors including the firm's totalrevenues, a portion of which is generated by investment banking activities.

Research analysts employed outside the US by affiliates of Barclays Capital Inc. are not registered/qualified as research analysts with FINRA.These analysts may not be associated persons of the member firm and therefore may not be subject to NASD Rule 2711 and incorporated NYSE Rule 472 restrictions on communications with a subject company, public appearances and trading securities held by a research analyst’saccount.

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The Corporate and Investment Banking division of Barclays produces a variety of research products including, but not limited to, fundamental analysis, equity-linked analysis, quantitative analysis, and trade ideas. Recommendations contained in one type of research product may differfrom recommendations contained in other types of research products, whether as a result of differing time horizons, methodologies, or otherwise.

Materially Mentioned Stocks (Ticker, Date, Price)

Angang Steel Co., Ltd. (0347.HK, 26-Mar-2012, HKD 4.78), 2-Equal Weight/1-Positive

China COSCO Holdings Co., Ltd. (1919.HK, 26-Mar-2012, HKD 4.32), 3-Underweight/2-Neutral

China Merchants Holdings (International) Co., Ltd. (0144.HK, 26-Mar-2012, HKD 27.00), 1-Overweight/2-Neutral

China Steel Corp. (2002.TW, 26-Mar-2012, TWD 29.80), 3-Underweight/1-Positive

CNOOC (0883.HK, 26-Mar-2012, HKD 16.48), 1-Overweight/1-Positive

Dongfang Electric Corp. Ltd. (1072.HK, 26-Mar-2012, HKD 18.86), 1-Overweight/1-Positive

Harbin Electric Co. Ltd. (1133.HK, 26-Mar-2012, HKD 8.08), 2-Equal Weight/1-Positive

Maanshan Iron & Steel Co., Ltd. (0323.HK, 26-Mar-2012, HKD 2.09), 3-Underweight/1-Positive

PetroChina (0857.HK, 26-Mar-2012, HKD 11.12), 1-Overweight/1-Positive

Shanghai Electric Group Co. Ltd. (2727.HK, 26-Mar-2012, HKD 3.95), 1-Overweight/1-Positive

Sinopec (0386.HK, 26-Mar-2012, HKD 8.77), 2-Equal Weight/1-Positive

Yangzijiang Shipbuilding (Holdings) Ltd. (YAZG.SI, 26-Mar-2012, SGD 1.31), 1-Overweight/2-Neutral

Other Material Conflicts

The Corporate and Investment Banking Division of Barclays is providing investment banking services to Plains All American Pipeline (PAA) in the potential acquisition of BP's Canadian natural gas liquids (NGL) and liquefied petroleum gas (LPG) business.

The Corporate and Investment Banking Division of Barclays is providing investment banking services to LINN Energy in relation to the potential acquisition of BP's Hugoton Basin properties.

Guide to the Barclays Fundamental Equity Research Rating System:

Our coverage analysts use a relative rating system in which they rate stocks as 1-Overweight, 2-Equal Weight or 3-Underweight (see definitions below) relative to other companies covered by the analyst or a team of analysts that are deemed to be in the same industry sector (the "sectorcoverage universe").

In addition to the stock rating, we provide sector views which rate the outlook for the sector coverage universe as 1-Positive, 2-Neutral or 3-Negative (see definitions below). A rating system using terms such as buy, hold and sell is not the equivalent of our rating system. Investorsshould carefully read the entire research report including the definitions of all ratings and not infer its contents from ratings alone.

Stock Rating

1-Overweight - The stock is expected to outperform the unweighted expected total return of the sector coverage universe over a 12-month investment horizon.


27 March 2012 31


2-Equal Weight - The stock is expected to perform in line with the unweighted expected total return of the sector coverage universe over a 12-month investment horizon.

3-Underweight - The stock is expected to underperform the unweighted expected total return of the sector coverage universe over a 12-month investment horizon.

RS-Rating Suspended - The rating and target price have been suspended temporarily due to market events that made coverage impracticable orto comply with applicable regulations and/or firm policies in certain circumstances including where the Corporate and Investment BankingDivision of Barclays is acting in an advisory capacity in a merger or strategic transaction involving the company.

Sector View

1-Positive - sector coverage universe fundamentals/valuations are improving.

2-Neutral - sector coverage universe fundamentals/valuations are steady, neither improving nor deteriorating.

3-Negative - sector coverage universe fundamentals/valuations are deteriorating.

Below is the list of companies that constitute the "sector coverage universe":

Asia ex-Japan Marine Transportation

China COSCO Holdings Co., Ltd. (1919.HK) China Merchants Holdings (International) Co., Ltd. (0144.HK)

China Rongsheng Heavy Ind. (1101.HK)

China Shipping Container Lines Co., Ltd. (2866.HK) China Shipping Development Co., Ltd. (1138.HK) COSCO Pacific Limited (1199.HK)

Hutchison Port Holdings Trust (HPHT.SI) Neptune Orient Lines Ltd. (NEPS.SI) Orient Overseas (International) Ltd. (0316.HK)

Pacific Basin Shipping Ltd. (2343.HK) Singamas Container Holdings Ltd. (0716.HK) Sinotrans Shipping Ltd. (0368.HK)

Yangzijiang Shipbuilding (Holdings) Ltd. (YAZG.SI)

Asia ex-Japan Metals & Mining

Aluminum Corporation of China Ltd. (2600.HK) Angang Steel Co., Ltd. (0347.HK) China Coal Energy Co., Ltd. (1898.HK)

China Hongqiao Group Ltd. (1378.HK) China Shenhua Energy Co., Ltd. (1088.HK) China Steel Corp. (2002.TW)

CST Mining Group Ltd. (0985.HK) Jiangxi Copper Co., Ltd. (0358.HK) Jindal Steel & Power (JNSP.NS)

JSW Steel (JSTL.NS) Maanshan Iron & Steel Co., Ltd. (0323.HK) Minmetals Resources Ltd. (1208.HK)

NMDC Ltd. (NMDC.NS) Sesa Goa (SESA.NS) Steel Authority of India (SAIL.NS)

Tata Steel (TISC.NS) Yanzhou Coal Mining Co., Ltd. (1171.HK)

Asia ex-Japan Oil & Gas

China Oilfield Services (COSL) (2883.HK) CNOOC (0883.HK) PetroChina (0857.HK)

Sinopec (0386.HK)

China Power Equipment

China High Speed Transmission Equipment Group Co. Ltd. (0658.HK)

Dongfang Electric Corp. Ltd. (1072.HK) Harbin Electric Co. Ltd. (1133.HK)

Shanghai Electric Group Co. Ltd. (2727.HK) Xinjiang Goldwind Science & Technology Co. Ltd. (2208.HK)

Distribution of Ratings:

Barclays Equity Research has 2248 companies under coverage.

42% have been assigned a 1-Overweight rating which, for purposes of mandatory regulatory disclosures, is classified as a Buy rating; 54% of companies with this rating are investment banking clients of the Firm.

42% have been assigned a 2-Equal Weight rating which, for purposes of mandatory regulatory disclosures, is classified as a Hold rating; 48% of companies with this rating are investment banking clients of the Firm.

13% have been assigned a 3-Underweight rating which, for purposes of mandatory regulatory disclosures, is classified as a Sell rating; 39% ofcompanies with this rating are investment banking clients of the Firm.

Guide to the Barclays Research Price Target:

Each analyst has a single price target on the stocks that they cover. The price target represents that analyst's expectation of where the stock willtrade in the next 12 months. Upside/downside scenarios, where provided, represent potential upside/potential downside to each analyst's pricetarget over the same 12-month period.

Barclays offices involved in the production of equity research:

London


27 March 2012 32


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Barclays Bank PLC in the Qatar Financial Centre (Registered No. 00018) is authorised by the Qatar Financial Centre Regulatory Authority (QFCRA). Barclays Bank PLC-QFC Branch may only undertake the regulated activities that fall within the scope of its existing QFCRA licence. Principal place of business in Qatar: Qatar FinancialCentre, Office 1002, 10th Floor, QFC Tower, Diplomatic Area, West Bay, PO Box 15891, Doha, Qatar. Related financial products or services are only available to BusinessCustomers as defined by the Qatar Financial Centre Regulatory Authority.

This material is distributed in the UAE (including the Dubai International Financial Centre) and Qatar by Barclays Bank PLC.

This material is distributed in Saudi Arabia by Barclays Saudi Arabia ('BSA'). It is not the intention of the publication to be used or deemed as recommendation, option or advice for any action (s) that may take place in future. Barclays Saudi Arabia is a Closed Joint Stock Company, (CMA License No. 09141-37). Registered office Al Faisaliah Tower, Level 18, Riyadh 11311, Kingdom of Saudi Arabia. Authorised and regulated by the Capital Market Authority, Commercial Registration Number:1010283024.

This material is distributed in Russia by OOO Barclays Capital, affiliated company of Barclays Bank PLC, registered and regulated in Russia by the FSFM. Broker License #177-11850-100000; Dealer License #177-11855-010000. Registered address in Russia: 125047 Moscow, 1st Tverskaya-Yamskaya str. 21.

This material is distributed in Singapore by the Singapore branch of Barclays Bank PLC, a bank licensed in Singapore by the Monetary Authority of Singapore. Formatters in connection with this report, recipients in Singapore may contact the Singapore branch of Barclays Bank PLC, whose registered address is One Raffles QuayLevel 28, South Tower, Singapore 048583.

Barclays Bank PLC, Australia Branch (ARBN 062 449 585, AFSL 246617) is distributing this material in Australia. It is directed at 'wholesale clients' as defined byAustralian Corporations Act 2001.

IRS Circular 230 Prepared Materials Disclaimer: Barclays does not provide tax advice and nothing contained herein should be construed to be tax advice. Please beadvised that any discussion of U.S. tax matters contained herein (including any attachments) (i) is not intended or written to be used, and cannot be used, by you for the purpose of avoiding U.S. tax-related penalties; and (ii) was written to support the promotion or marketing of the transactions or other matters addressed herein.Accordingly, you should seek advice based on your particular circumstances from an independent tax advisor.

© Copyright Barclays Bank PLC (2012). All rights reserved. No part of this publication may be reproduced in any manner without the prior written permission ofBarclays. Barclays Bank PLC is registered in England No. 1026167. Registered office 1 Churchill Place, London, E14 5HP. Additional information regarding thispublication will be furnished upon request.

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